Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC  20549
Form 10-K

x☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20172021
Or
o
☐ 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

Incorporated in South Dakota7001 Mount Rushmore RoadIRS Identification Number
Rapid City, South Dakota  5770246-0458824
Registrant’s telephone number, including area code
(605) 721-1700
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol
Name of each exchange
on which registered
Common stock of $1.00 par valueBKHNew York Stock Exchange


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


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


Indicate by check mark whether the Registrantregistrant (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 Registrantregistrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Yes           x           No           o


Indicate by check mark whether the Registrantregistrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted 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 Registrantregistrant was required to submit and post such files). Yes ☒ No ☐
Yes           x           No           o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    x


Indicate by check mark whether the Registrantregistrant 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☐
Large accelerated filer    x
Accelerated filer     o
Non-accelerated filero
(Do not check if a smaller reporting company)
☐
Smaller reporting companyo
☐
Emerging growth companyo☐


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


Indicate by check mark whether the Registrantregistrant 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 ☒
Yes           o           No           x

State theThe aggregate market value of the voting stockcommon equity held by non-affiliates of the Registrant.

Atregistrant on the last business day of the registrant’s most recently completed second fiscal quarter, June 30, 2017                                  $3,563,087,1392021, 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.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.
ClassOutstanding at January 31, 20182022
Common stock, $1.00 par value53,544,76164,738,725 
shares


Documents Incorporated by Reference
Portions of the Registrant’sregistrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 20182022 Annual Meeting of Stockholders to be held on April 24, 2018,26, 2022, are incorporated by reference in Part III of this Form 10-K.






TABLE OF CONTENTS

Page
34
89
89
ITEMSBUSINESS AND PROPERTIES
10
ITEM 1A.RISK FACTORS
32History and Organization
10
Electric Utilities
10
Gas Utilities
15
Utility Regulation Characteristics
18
Environmental Matters
18
Human Capital Resources
19
21
4227
LEGAL PROCEEDINGS2.
27
27
4227
Part II
28
4329
SELECTED FINANCIAL DATA
30
ITEMS 7. and 7A.
30
30
31
34
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
46
Cash Flow Activities
46
Capital Resources
47
Credit Ratings
49
Capital Requirements
50
51
4754
2

8756
56
57
60
61
62
64
65
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
168114
169114
169114
Part III
DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
114
170115
170115
171115
171115
171115
Part IV
172115
176119
177120

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GLOSSARY OF TERMS AND ABBREVIATIONS


The following terms and abbreviations appear in the text of this report and have the definitions described below:
ACAlternating Current
AFUDCAllowance for Funds Used During Construction
AltaGasAOCIAltaGas Renewable Energy Colorado LLC, a subsidiary of AltaGas Ltd.
AOCIAccumulated Other Comprehensive Income (Loss)
APSCArkansas Public Service Commission
Aquila TransactionArkansas GasOur July 14, 2008 acquisitionBlack Hills Energy Arkansas, Inc., an indirect, wholly-owned subsidiary of five utilities from Aquila, Inc.Black Hills Utility Holdings, providing natural gas services to customers in Arkansas (doing business as Black Hills Energy).
AROAsset Retirement Obligations
ASCAccounting Standards Codification
ASUAccounting Standards Update as issued by the FASB
ATMAt-the-market equity offering program
Basin ElectricAvailabilityBasin Electric Power CooperativeThe availability factor of a power plant is the percentage of the time that it is available to provide energy.
BblBHCBarrel
BcfBillion cubic feet
BHCBlack Hills Corporation; the Company
BHEPBHSCBlack Hills Exploration and Production, Inc.,Service Company, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, includesCorporation (doing business as Black Hills Gas Resources, Inc. and Black Hills Plateau Production LLC, direct wholly-owned subsidiaries of Black Hills Exploration and Production, Inc.Energy)
Black Hills Colorado IPPBlack Hills Colorado IPP, LLC, a 50.1% owned subsidiary of Black Hills Electric Generation
Black Hills GasBlack Hills Gas, LLC, a subsidiary of Black Hills Gas Holdings, which was previously named SourceGas LLC.
Black Hills Gas HoldingsBlack Hills Gas Holdings, LLC, a subsidiary of Black Hills Utility Holdings, which was previously named SourceGas Holdings LLC
Black Hills Electric GenerationBlack 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 EnergyThe name used to conduct the business of our utility companies
Black Hills Energy Arkansas GasIncludes the acquired SourceGas utility Black Hills Energy Arkansas, Inc. utility operations
Black Hills Energy Colorado ElectricIncludes Colorado Electric’s utility operations
Black Hills Energy Colorado GasIncludes Black Hills Energy Colorado Gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Colorado gas operations and RMNG
Black Hills Energy Iowa GasIncludes Black Hills Energy Iowa gas utility operations
Black Hills Energy Kansas GasIncludes Black Hills Energy Kansas gas utility operations
Black Hills Energy Nebraska GasIncludes Black Hills Energy Nebraska gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Nebraska gas operations
Black Hills Energy ServicesA Choice Gas supplier acquired in the SourceGas Acquisition
Black Hills Energy South Dakota ElectricIncludesServices Company, an indirect, wholly-owned subsidiary of Black Hills Power’s operations in South Dakota, Wyoming and MontanaUtility Holdings, providing natural gas commodity supply for the Choice Gas Programs (doing business as Black Hills Energy).
Black Hills Energy Wyoming ElectricIncludes Cheyenne Light’s electric utility operations
Black Hills Energy Wyoming GasIncludes Cheyenne Light’s natural gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Wyoming gas operations
Black Hills Gas DistributionBlack Hills Gas Distribution, LLC, a company acquired in the SourceGas Acquisition that conducts the gas distribution operations in Colorado, Nebraska and Wyoming. It was formerly named SourceGas Distribution LLC.
Black Hills Non-regulated HoldingsBlack Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills PowerBlack Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy). Also known as South Dakota Electric.
BHSCBlack Hills Service Company LLC, a direct, wholly-owned subsidiary of Black Hills Corporation


Black Hills Utility HoldingsBlack Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills WyomingBlack Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
BLMBtuUnited States Bureau of Land ManagementBritish thermal unit
Busch RanchBusch Ranch Wind Farm is aIThe 29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and AltaGas.Black Hills Electric Generation. Colorado Electric hasand 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.
Ceiling TestBusch Ranch IIRelatedThe 59.4 MW wind farm near Pueblo, Colorado owned by Black Hills Electric Generation to our Oilprovide wind energy to Colorado Electric through a PPA expiring in November 2044.
CARES ActCoronavirus Aid, Relief, and Gas subsidiary, capitalized costs, less accumulated amortizationEconomic Security Act, signed on March 27, 2020, which is a tax and related deferred income taxes, are subjectspending package intended to a ceiling test which limitsprovide additional economic relief and address the pooled costs to the aggregateimpact of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties.COVID-19 pandemic.
CAPPCFTCCustomer Appliance Protection Plan - acquired in the SourceGas Acquisition
CFTCUnited States Commodity Futures Trading Commission
CG&ACawley, Gillespie & Associates, Inc., an independent consulting and engineering firm
Cheyenne LightCheyenne 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 PrairieCheyenne 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 a 132wholly-owned by Wyoming Electric and one combined-cycle, 100 MW natural-gas fired generating facility jointly ownedunit that is jointly-owned by Black Hills PowerWyoming Electric (42 MW) and Cheyenne Light in Cheyenne, Wyoming. Cheyenne Prairie was placed into commercial service on October 1, 2014.South Dakota Electric (58 MW).
Chief Operating Decision Maker (CODM)Chief Executive Officer
Choice Gas ProgramTheRegulator-approved programs in Wyoming and Nebraska that allow certain utility customers to select their natural gas commodity supplier, providing the unbundling of the natural gascommodity service from the distribution component, which opens up the gas supply for competition allowing customers to choose from different natural gas suppliers. Black Hills Gas Distribution distributes the gas and Black Hills Energy Services is one of the Choice Gas suppliers.delivery service.
City of Colorado SpringsColorado Springs, Colorado
City of GilletteGillette, Wyoming
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Colorado ElectricBlack Hills Colorado Electric, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Company, LP,Holdings, providing electric service to customers in Colorado (doing business as Black Hills Energy).
Colorado GasBlack 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).
Colorado GasCommon Use SystemBlack Hills Colorado Gas Utility Company, LP, an indirect, wholly-owned subsidiaryThe 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 Black Hills Utility Holdings (doing business as Black Hills Energy)southwestern South Dakota and northeastern Wyoming.
Colorado Interstate Gas (CIG)Colorado Interstate Natural Gas Pricing Index
Colorado IPPBlack Hills Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Electric Generation
Consolidated Indebtedness to Capitalization RatioAny Indebtedness outstanding at such time, divided by Capitalcapital at such time. Capital being Consolidated Net-Worthconsolidated net-worth (excluding noncontrolling interest and including the aggregate outstanding amount of RSNs)non-controlling interest) plus Consolidated Indebtednessconsolidated indebtedness (including letters of credit and certain guarantees issued and excluding RSNs)issued) as defined within the current Revolving Credit Agreement.Facility.
Cooling Degree DayA 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 over a 30-year average.locations.
CPPCorriedaleClean Power PlanThe 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-19The 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 ProgramCommercial Paper Program
CPUCColorado Public Utilities Commission
CTCombustion turbineTurbine
CTIIThe 40 MW Gillette CT, a simple-cycle, gas-fired combustion turbine owned by the City of Gillette.
CVACushion GasThe 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.
CVACredit Valuation Adjustment
DARTDCDays Away Restricted Transferred (number of cases with days away from work or job transfer or restrictions multiplied by 200,000 thenDirect Current
Dividend Payout RatioAnnual dividends paid on common stock divided by total hours workednet income from continuing operations available for all employees during the year covered)common stock
DCDRSPPDirect current
Dodd-FrankDodd-Frank Wall Street Reform and Consumer Protection Act
DSMDemand Side Management
DRSPPDividend Reinvestment and Stock Purchase Plan


DSMDemand Side Management
DthDekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu).
EBITDAEarnings before interest, taxes, depreciation and amortization, a non-GAAP measurementmeasure.
ECAEnergy Cost Adjustment -- adjustmentsis an adjustment that allowallows us to pass the prudently-incurred cost of fuel and purchased energy through to customers.
Economy EnergyElectricity purchased by one utility from another utility to takePurchased energy that costs less than that produced with the place of electricity that would have cost more to produce on the utility’s own systemutilities’ owned generation.
EIAEECREnergy Efficiency Cost Recovery is an adjustment mechanism that allows us to recover from customers the costs associated with providing energy efficiency programs.
EIAEnvironmental 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 WestTransitionEnergy West Wyoming, Inc., a subsidiaryThe global energy sector’s shift from fossil-based systems of Gas Natural, Inc. Energy West is an acquisition we closed on July 1, 2015.energy production and consumption, including oil, natural gas and coal to renewable energy sources like wind and solar, as well as battery storage solutions.
EnsercoEPAEnserco Energy Inc., a former wholly-owned subsidiary of Black Hills Non-regulated Holdings, which is presented in discontinued operations in this Annual Report filed on Form 10-K
EPAUnited States Environmental Protection Agency
Equity UnitEWGEach Equity Unit has a stated amount of $50, consisting of a purchase contract issued by BHC to purchase shares of BHC common stock and a 1/20, or 5% undivided beneficial ownership interest in $1,000 principal amount of BHC RSNs due 2028.
EWGExempt Wholesale Generator
FASBFinancial Accounting Standards Board
FDICFederal Depository Insurance Corporation
FERCUnited States Federal Energy Regulatory Commission
FitchFitch Ratings Inc.
GAAPAccounting principles generally accepted in the United States of America
GADSGCAGeneration Availability Data System
GCAGas Cost Adjustment -- adjustmentsis an adjustment that allowallows us to pass the prudently-incurred cost of gas and certain services through to customers.
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GHGGreenhouse gases
Global SettlementSettlement with a utilitiesutility’s commission where the dollar figurerevenue requirement is agreed upon, but the specific adjustments used by each party to arrive at the figureamount are not specified in public rate ordersorders.
Happy JackHappy Jack Wind Farm, LLC, owned by Duke Energy Generation Services
Heating Degree DayA 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 over a 30 year average.locations.
IEEEHomeServeInstitute of Electrical and Electronics EngineersWe offer HomeServe products to our natural gas residential customers interested in purchasing additional home repair service plans.
Integrated GenerationNon-regulated power generation and mining businesses that are vertically integrated within our Electric Utilities segment.
Iowa GasBlack 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).
IPPIndependent power producerPower Producer
IPP TransactionIRCThe July 11, 2008 sale of seven of our IPP plantsInternal Revenue Code
IRSIRPIntegrated Resource Plan
IRSUnited States Internal Revenue Service
ITCInvestment Tax Credit
IUBIowa Utilities Board
Kansas GasBlack 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).
kVKCCKilovoltKansas Corporation Commission
LIBORkVKilovolt
LIBORLondon Interbank Offered Rate
LOEMcfLease Operating Expense
Loveland Area ProjectPart of the Western Area Power Association transmission system
MAPPMid-Continent Area Power Pool
MATSUtility Mercury and Air Toxics Rules under the United States EPA National Emissions Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units
MbblThousand barrels of oil
McfThousand cubic feet
McfdThousand cubic feet per day


MDUMontana-Dakota Utilities Co., a subsidiary of MDU Resources Group, Inc.
MEANMunicipal Energy Agency of Nebraska
MISOMidcontinent Independent System Operator, Inc.
MMBtuMillion British thermal units
Moody’sMoody’s Investors Service, Inc.
MSHAUnited States Department of Labor’s Mine Safety and Health Administration
McfeMWThousand cubic feet equivalentMegawatts
MDUMWhMontana Dakota Utilities Co., a regulated utility division of MDU Resources Group, Inc.Megawatt-hours
MEANN/AMunicipal Energy Agency of NebraskaNot Applicable
MGPNAVManufactured Gas Plant
MMBtuMillion British thermal units
MMcfMillion cubic feet
MMcfeMillion cubic feet equivalent
Moody’sMoody’s Investors Service, Inc.
MSHAMine Safety and Health Administration
MTPSCMontana Public Service Commission
MWMegawatts
MWhMegawatt-hours
N/ANot Applicable
NAVNet Asset Value
Nebraska GasBlack Hills Nebraska Gas, Utility Company, LLC, a direct,an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Nebraska (doing business as Black Hills Energy).
NERCNeil Simpson IIA 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.
NERCNorth American Electric Reliability Corporation
NGLNatural Gas Liquids (1 barrel equals 6 Mcfe)
NOAANational Oceanic and Atmospheric Administration
NOAA Climate Normals
This dataset is produced once every 10 years. This dataset contains daily and monthly normals of temperature, precipitation, snowfall, heating and cooling degree days, frost/freeze dates, and growing degree days calculated from observations at approximately 9,800 stations operated by NOAA’s National Weather Service.

NOx
Nitrogen oxide
NOLNet operating lossOperating Loss
NPSCNebraska Public Service Commission
NWPLNorthwest Interstate Natural Gas Pricing Index
NYMEXOCINew York Mercantile Exchange
NYSENew York Stock Exchange
OCIOther Comprehensive Income
OPEBOther Post-Employment Benefits
OSHAUnited States Department of Labor’s Occupational Safety & Health Administration
OSMU.S.United States Department of the Interior’s Office of Surface Mining
PCAPacifiCorpPacifiCorp, a wholly owned subsidiary of MidAmerican Energy Holdings Company, itself an affiliate of Berkshire Hathaway.
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PCAPower 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.
PCCAPower 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$109 million 60The 60.8 MW wind generating projectfarm owned by Colorado Electric.
PPAPower Purchase Agreement
PRPAPlatte River Power Authority
PSAPower Sales Agreement
PTCProduction Tax Credit
Pueblo Airport GenerationThe 440 MW combined cycle gas-fired power generation plants jointly owned by Colorado Electric placed in service(240 MW) and Black Hills Colorado IPP (200 MW). Black Hills Colorado IPP owns and operates this facility. The plants commenced operation on November 7, 2016 and adjacent to Busch Ranch Wind FarmJanuary 1, 2012.
PPAPower Purchase Agreement
PUHCA 2005Public Utility Holding Company Act of 2005
REPAReadyThe 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 WyomingA 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 ReadyVoluntary renewable energy subscription program for large commercial, industrial and governmental customers in South Dakota and Wyoming.
RESARenewable Energy Purchase AgreementStandard 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 FacilityOur $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which matures inwas amended and restated on July 19, 2021, and now terminates on July 19, 2026.
RMNGRocky Mountain Natural Gas a regulatedLLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas utility acquired in the SourceGas Acquisition that provides regulated transmission and wholesale natural gas service to Black Hills Gas Distributionservices in western Colorado (doing business as Black Hills Energy).
RSNsRTORemarketable junior subordinated notes, issued on November 23, 2015Regional Transmission Organization
SAIDISDPUCSystem Average Interruption Duration Index
SDPUCSouth Dakota Public Utilities Commission
SECU. S.United States Securities and Exchange Commission
Service Guard Comfort PlanHomeAppliance protection plan that provides home appliance repair product offering for both natural gas and electricservices through on-going monthly service agreements to residential utility customers.
Silver SageSilver Sage Windpower, LLC, owned by Duke Energy Generation Services
SO2
Sulfur dioxide


S&P
S&PStandard & Poor’s, Global Ratings, a division of The McGraw-Hill Companies,S&P Global Inc.
SourceGasSourceGas Holdings LLC and its subsidiaries, a gas utility owned by funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) that was acquired on February 12, 2016, and is now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy)
SourceGas AcquisitionThe acquisition of SourceGas Holdings, LLC by Black Hills Utility Holdings
SourceGas TransactionOn 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 ElectricIncludes Black Hills Power, operationsInc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and Wyoming and Montana(doing business as Black Hills Energy).
SSIRSPPSouthwest Power Pool, a regional transmission organization (RTO) that oversees the bulk electric grid and wholesale power market in the central United States.
SSIRSystem Safety and Integrity Rider
System Peak DemandRepresents the highest point of retail customer usage for a single hour for the system in total. Our system peaks include demand loads for 100% of plants regardless of joint ownership.hour.
TCATransmission Cost Adjustment -- adjustments passed throughis an annual adjustment mechanism that allows us to recover from customers eligible transmission investments prior to the customer based on transmission costs that are higher or lower than the costs approved in thenext rate case.review.
TCJATax Cuts and Jobs Act enacted on December 22, 2017
TCIRTotal Case Incident Rate (average number of work-related injuries incurred by 100 workers during a one-year period)
Tech ServicesNon-regulated product lines within Black Hills Corporationdelivered 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-ownercustomer-owned gas infrastructure facilities, typically through one-time contracts.
TFATop of IowaNorthern 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.
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TFATransmission Facility Adjustment is an annual adjustment mechanism that allows us to recover charges for qualifying new and modified transmission facilities from customers.
VEBATransmission TieSouth 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.
TSAUnited States Department of Homeland Security’s Transportation Security Administration
UtilitiesBlack Hills’ Electric and Gas Utilities
VEBAVoluntary Employee Benefit Association
VIEVariable Interest Entity
WDEQWyoming Department of Environmental Quality
WECCWind Capacity FactorWestern Electricity Coordinating CouncilMeasures the amount of electricity a wind turbine produces in a given time period relative to its maximum potential
Winter Storm AtlasUriAn October 2013 blizzardFebruary 2021 winter weather event that impacted South Dakota Electric. It wascaused extreme cold temperatures in the second most severe blizzardcentral United States and led to unprecedented fluctuations in Rapid City’s history.customer demand and market pricing for natural gas and energy.
WPSCWorking CapacityTotal gas storage capacity minus cushion gas
WPSCWyoming Public Service Commission
WRDCWyodak 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 IA 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 IIA 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 IIIA 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 PlantWyodak, a 362The 402.3 MW mine-mouth, coal-fired plant ingenerating facility located at our Gillette, Wyoming energy complex, jointly owned 80% by PacifiCorp (80%) and 20% by Black Hills Energy South Dakota.Dakota Electric (20%). Our WRDC mine supplies all of the fuel for the plant.facility.
Wyoming ElectricIncludes Cheyenne Light’sLight, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric utility operationsservice to customers in the Cheyenne, Wyoming area (doing business as Black Hills Energy).
Wyoming Gas
Includes Cheyenne Light’sBlack Hills Wyoming Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas utility operations,services to customers in Wyoming (doing business as well as the acquired SourceGas utility Black Hills Gas Distribution’s Wyoming gas operations

Energy).

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WEBSITE ACCESS TO REPORTS
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 InformationFORWARD-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.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.Factors.


9
Table of Contents
PART I


ITEMS 1 AND 2.BUSINESS AND PROPERTIES

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 vertically-integrated utility company headquartered in Rapid City, South Dakota. Our predecessor company, Black Hills Power and Light Company, was incorporated and began providing electric utility serviceDakota (incorporated in 1941. It was formed through the purchase and combination of several existing electric utilities and related assets, some of which had served customersSouth Dakota in the Black Hills region since 1883. In 1956, with the purchase of the Wyodak Coal Mine, we began producing and selling energy through non-regulated businesses.1941).


We operate our business in the United States, reporting our operating results through our regulated Electric Utilities regulatedand Gas Utilities Power Generation and Mining 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 210,000218,000 electric utility customers in Colorado, Montana, South Dakota Wyoming, Colorado and Montana.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 9411,481.5 MW of generation and 8,8398,899 miles of electric transmission and distribution lines. For additional information, see the Key Elements of our Business Strategy in Item 7.


Our Gas Utilities segment serves approximately 1,042,0001,094,000 natural gas utility customers in Arkansas, Colorado, Iowa, Kansas, Nebraska, Kansas and Wyoming. Our Gas Utilities own and operate 4,6564,732 miles of intrastate gas transmission pipelines and 40,45541,644 miles of gas distribution mains and service lines, sevensix natural gas storage sites, over 45,000more than 50,000 horsepower of compression and nearly 600over 515 miles of gathering lines. On February 12, 2016, we acquired SourceGas Holdings, LLC, adding four regulated natural gas utilities serving approximately 431,000 customers in Arkansas, Colorado, Nebraska and Wyoming. For additional information




on this acquisition, see the Key Elements of our Business Strategy in Item 7 and Note 2 in the Notes to Consolidated Financial Statements in Item 8.

Our Power Generation segment produces electric power from its generating plants and sells the electric capacity and energy primarily to our utilities under long-term contracts. Our Mining segment produces coal at our mine near Gillette, Wyoming, and sells the coal primarily under long-term contracts to mine-mouth electric generation facilities including our own regulated and non-regulated generating plants. For additional information, see the Key Elements of our Business Strategy in Item 7.

Our segments generated the following income from continuing operations available for common stock for the year ended December 31, 2017 and had the following total assets at December 31, 2017 (excluding Corporate and Other):
 Income (loss) from continuing operations available for common stock for the year ended December 31, 2017Total Assets as of December 31, 2017
 (in thousands)
Electric Utilities$110,082$2,906,275
Gas Utilities$65,795$3,426,466
Power Generation$46,479$60,852
Mining$14,386$65,455

On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. As of February 23, 2018, we have either closed transactions or signed contracts to sell more than 90 percent of our oil and gas properties. We have executed agreements to sell all our operated properties and have only non-operated assets with minimal value left to divest. We plan to conclude the sale of all of our remaining assets by mid-year 2018. The results of our Oil and Gas segment are reflected in discontinued operations, other than certain general and administrative and interest costs. BHEP’s assets and liabilities are classified as held for sale. See Note 21 in the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Segment Financial Information

We discuss our business strategy and other prospective information in Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations. Financial information regarding our business segments is incorporated herein by reference to Item 8 - Financial Statements and Supplementary Data, and particularly Note 5 in the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Electric Utilities Segment


We conduct electric utility operations through our Colorado, South Dakota and Wyoming and Colorado subsidiaries. Our Electric Utilities generate, transmit and distribute electricity to approximately 210,000 customers in South Dakota, Wyoming, Colorado and Montana. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our own distribution systems.retail customers. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates. We also provide non-regulated services throughto our retail customers under the Service Guard Comfort Plan and Tech Services product lines.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 Customers202120202019
Residential186,852 184,872 183,232 
Commercial30,326 30,225 29,921 
Industrial81 83 83 
Other1,010 1,017 1,024 
Total Electric Retail Customers at End of Year218,269 216,197 214,260 
As of December 31,
Retail Customers202120202019
Colorado Electric99,709 98,735 97,890 
South Dakota Electric74,509 73,700 73,052 
Wyoming Electric44,051 43,762 43,318 
Total Electric Retail Customers at End of Year218,269 216,197 214,260 
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Table of Contents

Capacity and Demand. System peak demandsPeak Demand for the Electric UtilitiesUtilities’ retail customers for each of the last three years are listed below:
System Peak Demand (in MW)
202120202019
SummerWinterSummerWinterSummerWinter
Colorado Electric407279401297422297
South Dakota Electric397299378304335320
Wyoming Electric274246271246265247
 System Peak Demand (in MW)
 2017 2016 2015
 SummerWinter SummerWinter Summer Winter
South Dakota Electric447402 438389 424 369
Wyoming Electric (a)
249230 236230 212 202
Colorado Electric (b)
398299 412302 392 303
Total Electric Utilities’ Peak Demands1,094931 1,086921 1,028 874

________________________
(a)The July 2017 summer peak load of 249 surpassed previous summer peak record load of 236 set in July 2016. The winter peak record of 230 was set in December 2016.
(b)The July 2016 summer peak load of 412 surpassed previous summer peak record load of 406 set in June 2016.

Regulated Power Plants. As of December 31, 2017,2021, our Electric Utilities’ ownership interests in electric generationgenerating plants were as follows:

UnitFuel
Type		Location
Ownership
Interest % (d)
Owned Nameplate Capacity (MW)In Service Date
Colorado Electric:
Busch Ranch I (a)
WindPueblo, Colorado50%14.52012
Peak View (b)
WindPueblo, Colorado100%60.82016
Pueblo Airport Generation #1-2GasPueblo, Colorado100%200.02011
Pueblo Airport Generation CT #6GasPueblo, Colorado100%40.02016
AIP DieselOilPueblo, Colorado100%10.02001
Diesel #1 and #3-5OilPueblo, Colorado100%8.01964
Diesel #1-5OilRocky Ford, Colorado100%10.01964
South Dakota Electric:
Cheyenne PrairieGasCheyenne, Wyoming58%58.02014
Corriedale (c)
WindCheyenne, Wyoming62%32.52020
Wygen IIICoalGillette, Wyoming52%60.32010
Neil Simpson IICoalGillette, Wyoming100%90.01995
Wyodak PlantCoalGillette, Wyoming20%80.51978
Neil Simpson CTGasGillette, Wyoming100%40.02000
Lange CTGasRapid City, South Dakota100%40.02002
Ben French Diesel #1-5OilRapid City, South Dakota100%10.01965
Ben French CTs #1-4Gas/OilRapid City, South Dakota100%100.01977-1979
Wyoming Electric:
Cheyenne PrairieGasCheyenne, Wyoming42%42.02014
Cheyenne Prairie CTGasCheyenne, Wyoming100%40.02014
Corriedale (c)
WindCheyenne, Wyoming38%20.02020
Wygen IICoalGillette, Wyoming100%95.02008
Integrated Generation:
Wygen ICoalGillette, Wyoming76.5%68.92003
Pueblo Airport Generation #4-5GasPueblo, Colorado
50.1% (e)
200.02012
Busch Ranch I (a)
WindPueblo, Colorado50%14.52012
Busch Ranch II (c)
WindPueblo, Colorado100%59.42019
Top of Iowa (c)
WindJoice, Iowa100%87.12019
Total MW Capacity1,481.5
____________________
(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.




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Table of Contents
Unit
Fuel
Type
Location
Ownership
Interest %
Owned Capacity (MW)
Year
Installed
South Dakota Electric:     
Cheyenne Prairie (a)
GasCheyenne, Wyoming58%55.02014
Wygen III (b)
CoalGillette, Wyoming52%57.22010
Neil Simpson IICoalGillette, Wyoming100%90.01995
Wyodak (c)
CoalGillette, Wyoming20%72.41978
Neil Simpson CTGasGillette, Wyoming100%40.02000
Lange CTGasRapid City, South Dakota100%40.02002
Ben French Diesel #1-5OilRapid City, South Dakota100%10.01965
Ben French CTs #1-4Gas/OilRapid City, South Dakota100%80.01977-1979
Wyoming Electric:     
Cheyenne Prairie (a)
GasCheyenne, Wyoming42%40.02014
Cheyenne Prairie CT (a)
GasCheyenne, Wyoming100%37.02014
Wygen IICoalGillette, Wyoming100%95.02008
Colorado Electric:     
Busch Ranch Wind Farm (d)
WindPueblo, Colorado50%14.52012
Peak View Wind Farm (e)
WindPueblo, Colorado100%60.02016
Pueblo Airport GenerationGasPueblo, Colorado100%180.02011
Pueblo Airport Generation CT (f)
GasPueblo, Colorado100%40.02016
AIP DieselOilPueblo, Colorado100%10.02001
Diesel #1-5OilPueblo, Colorado100%10.01964
Diesel #1-5OilRocky Ford, Colorado100%10.01964
Total MW Capacity   941.1 

________________________
(a)Cheyenne Prairie, a 132 MW natural gas-fired power generation facility, was placed into commercial operation on October 1, 2014, to support the utility customers of South Dakota Electric and Wyoming Electric. The facility includes one simple-cycle, 37 MW combustion turbine that is wholly-owned by Wyoming Electric and one combined-cycle, 95 MW unit that is jointly-owned by Wyoming Electric (40 MW) and South Dakota Electric (55 MW).
(b)Wygen III, a 110 MW mine-mouth coal-fired power plant, is operated by South Dakota Electric. South Dakota Electric has a 52% ownership interest, MDU owns 25% and the City of Gillette owns the remaining 23% interest. Our WRDC coal mine supplies all of the fuel for the plant.
(c)Wyodak, a 362 MW mine-mouth coal-fired power plant, is owned 80% by PacifiCorp and 20% by South Dakota Electric. This baseload plant is operated by PacifiCorp and our WRDC coal mine supplies all of the fuel for the plant.
(d)Busch Ranch Wind Farm, a 29 MW wind farm, is operated by Colorado Electric. Colorado Electric has a 50% ownership interest in the wind farm and AltaGas owns the remaining 50%. Colorado Electric has a 25-year REPA with AltaGas for their 14.5 MW of power from the wind farm.
(e)Peak View Wind Farm achieved commercial operation on November 7, 2016.
(f)Colorado Electric’s 40 MW combustion turbine achieved commercial operation on December 29, 2016.

The Electric Utilities’ annualpower 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 Supply202120202019
Coal34.2 %40.3 %40.0 %
Natural Gas and Diesel Oil (a)
24.4 25.0 22.2 
Wind11.3 8.8 5.8 
Total Generated69.9 74.1 68.0 
Coal, Natural Gas, Oil and Other Market Purchases25.1 21.1 29.1 
Wind Purchases5.0 4.8 2.9 
Total Purchased30.1 25.9 32.0 
Total100.0 %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 iswere as follows:
Fuel and Purchased Power (dollars per MWh)202120202019
Coal$11.55 $11.38 $12.42 
Natural Gas and Diesel Oil (a)
33.65 8.59 11.04 
Total Generated Weighted Average Fuel Cost17.40 9.09 12.48 
Coal, Natural Gas, Oil and Other Market Purchases (a)
64.85 40.80 44.16 
Wind Purchases34.69 42.06 49.19 
Total Purchased Power Weighted Average Cost59.84 41.03 44.62 
Total Weighted Average Fuel and Purchased Power Cost$30.17 $17.36 $22.76 
Fuel Source (dollars per MWh)201720162015
Coal$10.95
$11.27
$10.89
    
Natural Gas$34.05
$30.59
$51.14
    
Diesel Oil (a)
$210.11
$149.13
$303.16
    
Total Average Fuel Cost$12.80
$12.99
$14.62
    
Purchased Power - Coal, Gas and Oil$45.63
$48.36
$47.81
    
Purchased Power - Renewable Sources$53.08
$51.95
$50.92
____________________
______________
(a)Included in the Price per MWh for Diesel Oil are unit start-up costs. The diesel-fueled generating units are generally used as supplemental peaking units and the cost per MWh is reflective of how often the units are started and how long the units are run.

Our Electric Utilities’(a)    The 2021 increase in prices paid for fuel and purchased power supply,was primarily driven by resource as a percentunforeseeable 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 total power supply for our energy needs for the years ended December 31 is as follows:Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Power Supply201720162015
Coal32%33%33%
Gas, Oil and Wind8
7
4
Total Generated40
40
37
Purchased (a)
60
60
63
Total100%100%100%
______________
(a)Wind represents approximately 6%, 7% and 5% of our purchased power in 2017, 2016, and 2015, respectively.

Purchased Power.Power Purchase and Power Sales Agreements. We have executed various agreementsPPAs to support our Electric Utilities’ capacity and energy needs beyond our regulated power plants’ generation. Key contracts include:

South Dakota Electric’s PPAgeneration, which include long-term related party agreements with PacifiCorp expiring on December 31, 2023, which provides for the purchase of 50 MW of coal-fired baseload power;

Colorado Electric’s PPA with Black Hills Colorado IPP expiring on December 31, 2031, which provides 200 MW of energy and capacity to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines. This PPA is reported and accounted for as a capital lease within our business segments and is eliminated on the accompanying Consolidated Financial Statements;

Colorado Electric’s PPA with AltaGas expiring on October 16, 2037, which provides up to 14.5 MW of wind energy from AltaGas’ owned interest in the Busch Ranch Wind Farm;

Wyoming Electric’s PPA with Black Hills Wyoming expiring on December 31, 2022, whereby Black Hills Wyoming provides 60 MW of unit-contingent capacity and energy from its Wygen I facility. The PPA includes an option for Wyoming Electric to purchase Black Hills Wyoming’s ownership interest in the Wygen I facility through 2019, subject to WPSC and FERC approval in order to obtain regulatory treatment. The purchase price related to the option is $2.6 million per MW (65 MWs), adjusted for all depreciated capital additions since 2009, and reduced by depreciation (approximately $5 million per year) over a 35-year life beginning January 1, 2009. The net book value of Wygen I at December 31, 2017 was $69 million and if Wyoming Electric had exercised the purchase option at year-end 2017, the estimated purchase price would have been approximately $133 million;

Wyoming Electric’s 20-year PPA with Duke Energy expiring on September 3, 2028, which provides up to 29.4 MW of wind energy from the Happy Jack Wind Farm to Wyoming Electric. Under a separate intercompany agreement,

Wyoming Electric sells 50% of the facility’s output to South Dakota Electric;

Wyoming Electric’s 20-year PPA with Duke Energy expiring on September 30, 2029, which provides up to 30 MW of wind energy from the Silver Sage wind farm to Wyoming Electric. Under a separate intercompany agreement, Wyoming Electric sells 20 MW of the facility’s output to South Dakota Electric; and

Wyoming Electric and South Dakota Electric’s Generation Dispatch Agreement requires South Dakota Electric to purchase all of Wyoming Electric’s excess energy.

Power Sales Agreements. Our Electric Utilitiesnon-regulated power generation businesses. We also have various long-term power sales agreements.PSAs. Key agreements include:

MDU owns a 25% interestcontracts are disclosed in Wygen III’s net generating capacity for the lifeNote 3 of the plant. During periodsNotes 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 reducedcoal 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 at Wygen III, or during periods when Wygen III is off-line, South Dakota Electric will provide MDU with 25 MW from its othersold to our on-site generation facilities or from system purchases with reimbursementunder long-term supply contracts.

As of costs by MDU;

South Dakota Electric has an agreement through December 31, 2023 to provide MDU capacity and energy up to a maximum of 50 MW;

The City of Gillette owns a 23% interest in Wygen III’s net generating capacity for the life of the plant. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, South Dakota Electric will provide the City of Gillette with its first 23 MW from its other generation facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, South Dakota Electric will also provide the City of Gillette its operating component of spinning reserves; and

South Dakota Electric has an agreement to supply up to 20 MW of energy and capacity to MEAN under a contract that expires in 2023. The terms of the contract run from June 1 through May 31 for each interval listed below. This contract is unit-contingent based on the availability of our Neil Simpson II and Wygen III plants, with decreasing capacity purchased over the term of the agreement. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows:
201820 MW - 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II
2018-202015 MW - 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II
2020-202212 MW - 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II
2022-202310 MW - 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II

South Dakota Electric has an agreement from January 1, 2017 through December 31, 2021, we estimated our recoverable reserves to provide 50 MWbe 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
Table of energy to Cargill (assigned to Macquarie on January 3, 2018) during heavy and light load timing intervals.Contents

Transmission and Distribution. Through our Electric Utilities, we own electric transmission and distribution systems composed of high voltage transmission lines (greater than 69 kV) and low voltage lines (69 kV or less). We also jointly own high voltage linesoperate 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, 2017,2021, our Electric Utilities owned the electric transmission and distribution lines shown below:
UtilityState
Transmission (a)
(in Line Miles)
Distribution
(in Line Miles)
Colorado ElectricColorado598 3,157 
South Dakota Electric (b)
South Dakota, Wyoming1,192 2,566 
Wyoming ElectricWyoming59 1,327 
1,849 7,050 
____________________
UtilityState
Transmission
(in Line Miles)
Distribution
(in Line Miles)
South Dakota ElectricSouth Dakota, Wyoming1,264
2,506
South Dakota Electric - Jointly Owned (a)
South Dakota, Wyoming44
—
Wyoming ElectricSouth Dakota, Wyoming49
1,281
Colorado ElectricColorado602
3,093
(a)    Electric transmission line miles include voltages of 69 kV and above.
__________________________
(a)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 United States and eastern United States, respectively. This transmission tie, which is 65% owned by Basin Electric, provides transmission access to both the WECC region in the West and the MAPP region in the East. The transfer capacity of the tie is 200 MW from West to East, and 200 MW from East to West. South Dakota Electric’s electric system is located in the WECC region. 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.

(b)    South Dakota Electric has firm point-to-point transmission access to deliver up to 50 MW of power on PacifiCorp’sline miles include 43 miles within the Common Use System.

Material transmission system to wholesale customersservices agreements are disclosed in the WECC region through 2023.

South Dakota Electric also has firm network transmission access to deliver power on PacifiCorp’s system to Sheridan, Wyoming, to serve our power sales contract with MDU through December 31, 2023, with the right to renew pursuant to the terms of PacifiCorp’s transmission tariff.

In order to serve Wyoming Electric’s existing load, Wyoming Electric has a network transmission agreement with Western Area Power Association’s Loveland Area Project.

Colorado Electric is party to a joint dispatch agreement between Colorado Electric, Public Service Company of Colorado “PSCo” and Platte River Power Authority.  This FERC-approved agreement, effective in 2017, is structured to allow PSCo, as administrator, to receive load and generation bid information for all three parties and, on an intra-hour basis, serve the combined utility load utilizing the combined bid generating resources on a least-cost basis.  In other words, if one party has excess generation at a lower cost than another party’s generation, the administrator will increase dispatchNote 3 of the lower-cost generation and decrease dispatch of the higher-cost generation.  This resultsNotes to Consolidated Financial Statements in lower energy costs to customers through more efficient dispatch of low-cost generating resources. Under the agreement, Colorado Electric retains the ability to participate or not participate in the joint dispatch at its discretion.this Annual Report on Form 10-K.


Operating Agreements. Our Electric Utilities have the following material operating agreements:

Shared Services Agreements -

◦South Dakota Electric, Wyoming Electric, and Black Hills Wyoming are parties to a shared facilities agreement, whereby each entity charges for the use of assets by the affiliate entity.

◦Black Hills Colorado IPP and Colorado Electric are also parties to a facility fee agreement, whereby Colorado Electric charges Black Hills Colorado IPP for the use of Colorado Electric assets.

◦South Dakota Electric and Wyoming Electric receive certain staffing and management services from BHSC for Cheyenne Prairie.

Jointly Owned Facilities -

◦South Dakota Electric, the City of Gillette and MDU are parties to a shared joint ownership agreement, whereby South Dakota Electric charges the City of Gillette and MDU for administrative services, plant operations and maintenance for their share of the Wygen III generating facility for the life of the plant.

◦Colorado Electric and AltaGas are parties to a shared joint ownership agreement whereby Colorado Electric charges AltaGas for operations and maintenance for their share of the Busch Ranch Wind Farm.

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 winter months for cooling and heating respectively. Because our Electric Utilities have a diverse customer and revenue base, and we have historically optimized the utilization of our electric power supply resources, the impact on our operations may not be as significant when weather conditions are warmerdemand in often greater in the winter and cooler in the summer.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 independent power producersIPPs for the right to providesupply 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
Table of Contents

The following table provides regulatory information for each of our Electric Utilities:
SubsidiaryJurisdic-tionAuthorized Rate of Return on EquityAuthorized Return on Rate BaseAuthorized Capital Structure Debt/EquityAuthorized Rate Base (in millions)Effective DateAdditional Regulatory MechanismsPercentage of Power Marketing Profit Shared with Customers
Colorado Electric (a)
CO9.37%7.43%48%/52%$539.61/2017ECA, TCA, PCCA, EECR/DSM, RESA90%
CO9.37%6.02%67%/33%$57.91/2017Clean Air Clean Jobs Act Adjustment RiderN/A
South Dakota ElectricWY9.90%8.13%47%/53%$46.810/2014ECA65%
SDGlobal Settlement7.76%Global Settlement$543.910/2014ECA, TFA, EIA70%
FERC10.80%8.76%43%/57%
$148.4 (b)
2/2009FERC Transmission TariffN/A
Wyoming Electric (a)
WY9.90%7.98%46%/54%$376.810/2014PCA, EECR/DSM, Rate Base Recovery on Acquisition AdjustmentN/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 JurisdictionCost Recovery Mechanisms
Environmental CostEnergy EfficiencyTransmission ExpenseFuel CostTransmission CapitalPurchased PowerRESA
Colorado Electricþþþþþþ
South Dakota Electric (SD) (a)
þþþþþ
South Dakota Electric (WY) (b)
þþþþ
South Dakota Electric (FERC) (c)
þ
Wyoming Electricþþþþ
____________________
(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.


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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 Customers202120202019
Residential853,908 844,999 831,351 
Commercial84,234 83,135 82,912 
Industrial2,158 2,235 2,208 
Transportation153,929 152,568 149,971 
Total Natural Gas Retail Customers at End of Year1,094,229 1,082,937 1,066,442 

As of December 31,
Retail Customers202120202019
Arkansas180,216 178,281 174,447 
Colorado202,747 197,817 191,950 
Iowa161,905 160,952 159,641 
Kansas117,862 116,973 115,846 
Nebraska298,832 296,778 293,576 
Wyoming132,667 132,136 130,982 
Total Natural Gas Retail Customers at End of Year1,094,229 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:
StateWorking Capacity (Mcf)Cushion Gas
(Mcf)		Total Capacity (Mcf)Maximum Daily Withdrawal Capability (Mcfd)
Arkansas9,273,700 12,318,040 21,591,740 196,000 
Colorado2,361,495 6,164,715 8,526,210 30,000 
Wyoming5,733,900 17,145,600 22,879,500 36,000 
Total17,369,095 35,628,355 52,997,450 262,000 

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

StateIntrastate Gas
Transmission Pipelines
(in line miles)		Gas Distribution
Mains
(in line miles)		Gas Distribution
Service Lines
(in line miles)
Arkansas874 4,972 1,275 
Colorado693 6,990 2,303 
Iowa172 2,863 2,486 
Kansas330 2,980 1,374 
Nebraska1,311 8,443 2,773 
Wyoming1,352 3,532 1,653 
Total4,732 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. TheThese 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, the rates of other utilities, 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 following table provides regulatory information for each of our electric utilities:


SubsidiaryJurisdic-tionAuthorized Rate of Return on EquityAuthorized Return on Rate BaseAuthorized Capital Structure Debt/EquityAuthorized Rate Base (in millions)Effective DateAdditional Tariffed MechanismsPercentage of Power Marketing Profit Shared with Customers
        
South Dakota ElectricWY9.9%8.13%46.7%/53.3%$46.810/2014ECA65%
 SDGlobal Settlement7.76%Global Settlement$543.910/2014ECA, TCA, Energy Efficiency Cost Recovery/DSM70%
 SD 7.76%  5/2014Transmission Facility Adjustment (TFA)N/A
 SD 7.76%  6/2011Environmental Improvement Adjustment TariffN/A
 FERC10.8%9.10%43%/57% 2/2009FERC Transmission TariffN/A
Wyoming ElectricWY9.9%7.98%46%/54%$376.810/2014PCA, Energy Efficiency Cost Recovery/DSM, Rate Base Recovery on Acquisition AdjustmentN/A
 FERC10.6%8.51%46%/54%$31.55/2014FERC Transmission TariffN/A
Colorado ElectricCO9.37%7.43%47.6%/52.4%$539.61/2017ECA, TCA, PCCA, Energy Efficiency Cost Recovery/DSM, Renewable Energy Standard Adjustment90%
 CO9.37%6.02%67.3%/32.7%$57.91/2017Clean Air Clean Jobs Act Adjustment RiderN/A

The regulatory provisions for recovering the costs to supply electricity vary by state. In all states, subject to thresholds noted below, we have cost adjustment mechanisms for our Electric Utilities that allow us to pass the prudently-incurred cost of fuel and purchased power through 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. Some states in which our utilities operate also allow the utility operating in that state to automatically adjust rates periodically for the cost of new transmission or environmental improvements and, in some instances, the utility has the opportunity to earn its authorized return on new capital investment immediately.

The significant mechanisms we have in place include the following by utility and state:

South Dakota Electric has:

An annual adjustment clause which provides for the direct recovery of increased fuel and purchased power cost incurred to serve South Dakota customers. Additionally, the ECA contains an off-system sales sharing mechanism in which South Dakota customers will receive a credit equal to 100% of off-system power marketing operating income from the first $2 million of power marketing margin from short-term sales and a credit equal to 70% of power marketing margins from short-term sales in excess of the first $2 million. South Dakota Electric retains the additional 30%. The ECA methodology allows us to directly assign renewable resources and firm purchases to the customer load. In Wyoming, a similar fuel and purchased power cost adjustment is also in place.

An approved annual Environmental Improvement Adjustment (EIA) tariff which recovers costs associated with generation plant environmental improvements. The EIA and TFA were suspended for a six-year period effective July

1, 2017. See Note 13 in the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

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

In Wyoming, Wyoming Electric has:

An annual cost adjustment mechanism that allows us to pass the prudently-incurred costs of fuel and purchased power through to electric customers. The annual cost adjustment allows for recovery of 85% of coal and coal-related cost per kWh variances from base, and recovery of 95% of purchased power, transmission, and natural gas cost per kWh variances from base.

An approved FERC Transmission Tariff that determines the revenue component of Wyoming Electric’s open access transmission tariff.

In Colorado, Colorado Electric has:

A quarterly ECA rider that allows us to recover forecasted increases or decreases in purchased energy and fuel costs, including the recovery for amounts payable to others for the transmission of the utility's electricity over transmission facilities owned by others, symmetrical interest, and the sharing of off-system sales margins, less certain operating costs (customer receives 90%). The ECA provides for not only direct recovery, but also for the issuance of credits for decreases in purchased energy, fuel costs and eligible energy resources.

Colorado allows an annual TCA rider that includes nine months of actual transmission investment and three months of forecasted investment, with an annual true-up mechanism.

The Clean Air Clean Jobs Act Adjustment rider rate collects the authorized revenue requirement for the 40 MW combustion turbine placed in service on December 31, 2016 with rates effective January 1, 2017.

The Renewable Energy Standard Adjustment rider is specifically designed for meeting the requirements of Colorado’s renewable energy standard and most recently includes cost recovery for the Peak View Wind Project.

See Note 13 in the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information regarding current electric rate activity.



Operating Statistics. The following tables summarize information for our Electric Utilities:

Degree Days201720162015
 Actual
Variance from 30-Year Average (b)
Actual
Variance from 30-Year Average (b)
Actual
Variance from 30-Year Average (b)
Heating Degree Days:      
South Dakota Electric6,870
(4)%6,402
(10)%6,521
(8)%
Wyoming Electric6,623
(12)%6,363
(14)%6,404
(10)%
Colorado Electric4,693
(16)%4,658
(16)%4,846
(12)%
Combined (a)
5,826
(11)%5,595
(13)%5,729
(10)%
       
Cooling Degree Days:      
South Dakota Electric709
11%646
(4)%577
(14)%
Wyoming Electric429
23%460
31%407
16%
Colorado Electric1,027
14%1,358
42%1,270
32%
Combined (a)
798
14%935
26%861
16%
________________
(a)The combined heating degree days are calculated based on a weighted average of total customers by state.
(b)30-Year Average is from NOAA Climate Normals.

  Electric Revenue (in thousands) Quantities sold (MWh)
  201720162015 201720162015
Residential $210,172
$208,725
$209,664
 1,390,952
1,395,097
1,399,901
Commercial 258,754
258,768
258,539
 2,038,495
2,067,486
2,031,556
Industrial 122,958
118,181
112,255
 1,598,755
1,515,553
1,399,641
Municipal 18,144
17,821
17,863
 160,882
162,383
159,496
Subtotal Retail Revenue - Electric 610,028
603,495
598,321
 5,189,084
5,140,519
4,990,594
Contract Wholesale 30,435
17,037
17,537
 722,659
246,630
260,893
Off-system/Power Marketing Wholesale 21,111
22,355
29,726
 661,263
769,843
1,000,085
Other 43,076
34,394
34,259
 —
—
—
Total Revenue and Energy Sold 704,650
677,281
679,843
 6,573,006
6,156,992
6,251,572
Other Uses, Losses or Generation, net —
—
—
 468,179
433,400
414,159
Total Revenue and Energy 704,650
677,281
679,843
 7,041,185
6,590,392
6,665,731
Less cost of fuel and purchased power 268,405
261,349
269,409
    
Gross Margin $436,245
$415,932
$410,434
    
  Electric Revenue (in thousands) 
Gross Margin (a) (in thousands)
 
Quantities Sold (MWh) (b)
  201720162015 201720162015 201720162015
South Dakota Electric $288,433
$267,632
$277,864
 $200,795
$192,606
$194,524
 3,187,392
2,767,315
3,040,703
Wyoming Electric 165,127
157,606
150,156
 89,371
85,036
83,537
 1,762,117
1,677,421
1,530,628
Colorado Electric 251,090
252,043
251,823
 146,079
138,290
132,373
 2,091,676
2,145,656
2,094,400
Total Revenue, Gross Margin, and Quantities Sold $704,650
$677,281
$679,843
 $436,245
$415,932
$410,434
 7,041,185
6,590,392
6,665,731
________________
(a)Non-GAAP measure
(b)Total MWh includes Other Uses, Losses or Generation, net, which is approximately 6%, 7%, and 8% for South Dakota Electric, Wyoming Electric, and Colorado Electric, respectively.


Quantities Generated and Purchased (MWh)201720162015
    
Coal-fired2,230,617
2,201,757
2,228,377
Natural Gas and Oil307,815
343,001
230,320
Wind239,472
80,582
41,043
Total Generated2,777,904
2,625,340
2,499,740
Purchased4,263,281
3,965,052
4,165,991
Total Generated and Purchased7,041,185
6,590,392
6,665,731

Quantities Generated and Purchased (MWh)201720162015
Generated:   
South Dakota Electric1,581,915
1,585,870
1,618,688
Wyoming Electric798,024
805,351
739,277
Colorado Electric397,965
234,119
141,775
Total Generated2,777,904
2,625,340
2,499,740
Purchased:


South Dakota Electric1,605,477
1,181,445
1,422,015
Wyoming Electric964,093
872,070
791,351
Colorado Electric1,693,711
1,911,537
1,952,625
Total Purchased4,263,281
3,965,052
4,165,991
 



Total Generated and Purchased7,041,185
6,590,392
6,665,731
Customers at End of Year201720162015
Residential179,911
178,333
176,901
Commercial29,354
29,086
29,172
Industrial86
88
87
Other914
1,001
1,027
Total Electric Customers at End of Year210,265
208,508
207,187

Customers at End of Year201720162015
South Dakota Electric72,184
71,353
70,733
Wyoming Electric42,130
41,531
41,422
Colorado Electric95,951
95,624
95,032
Total Electric Customers at End of Year210,265
208,508
207,187



Gas Utilities Segment

We conduct natural gas utility operations through our Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming subsidiaries. On February 12, 2016, we acquired SourceGas Holdings, LLC, adding four regulated natural gas utilities serving approximately 431,000 customers in Arkansas, Colorado, Nebraska and Wyoming and a 512 mile regulated intrastate natural gas transmission pipeline in Colorado. Our Gas Utilities transport and distribute natural gas through our distribution network to approximately 1,042,000 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 through Black Hills Energy Services. Black Hills Energy Services has approximately 52,000 retail distribution customers in Nebraska and Wyoming providing unbundled natural gas commodity offerings under the regulatory-approved Choice Gas Program. We also sell, install and service air, heating and water-heating equipment, and provide associated repair service and appliance protection plans under various trade names. Service Guard and CAPP provide appliance repair services to approximately 63,000 and 31,000 residential customers, respectively, through Company technicians and third-party service providers, typically through on-going monthly service agreements. Tech Services serves gas transportation customers throughout our service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.

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 with Colorado Interstate Gas Company, Enable Gas Transmission, Tallgrass Interstate Gas Transmission, Natural Gas Pipeline Company of America, Northern Natural Gas, Panhandle Eastern Pipeline Company, Southern Star Central Gas Pipeline, Black Hills Shoshone Pipeline, TransColorado Gas Transmission, WBI Energy Transmission, Rocky Mountain Natural Gas, Ozark Gas Transmission, Liberty Utilities, Texas Eastern Transmission Pipeline, WestGas InterState Pipeline, Public Service Company of Colorado and Red Cedar Gas Gathering.

In addition to company-owned storage assets in Wyoming, Colorado and Arkansas, we also contract with many of the third-party transportation providers noted above 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 regulated underground gas storage facilities as of December 31, 2017:
 StateWorking Capacity (Mcf)
Cushion Gas (Mcf) (a)
Total Capacity (Mcf)Maximum Daily Withdrawal Capability (Mcfd)
 
 Arkansas8,442,700
12,950,000
21,392,700
196,000
 Colorado2,360,895
6,165,315
8,526,210
30,000
 Wyoming5,733,900
17,145,600
22,879,500
32,950
 Total16,537,495
36,260,915
52,798,410
258,950
________________
(a)Cushion gas represents the volume of gas that must be retained in a facility to maintain reservoir pressure.

The following tables summarize certain operating information for our Gas Utilities.

System Infrastructure (in line miles) as of
Intrastate Gas
Transmission Pipelines
Gas Distribution
Mains
Gas Distribution
Service Lines
December 31, 2017
Arkansas926
4,654
919
Colorado683
6,569
2,399
Nebraska1,256
8,467
3,219
Iowa163
2,777
2,653
Kansas325
2,855
1,337
Wyoming1,303
3,396
1,210
Total4,656
28,718
11,737



Degree Days2017 2016 2015
 Actual
Variance From
30-Year Average (d)
 Actual
Variance From
30-Year Average (d)
 Actual
Variance From
30-Year Average (d)
Heating Degree Days:        
Arkansas (a)
3,295
(19)% 2,397
(41)% —
—%
Colorado5,728
(14)% 5,762
(13)% 5,527
(12)%
Nebraska5,554
(10)% 5,457
(12)% 5,350
(12)%
Iowa6,149
(9)% 5,997
(11)% 6,629
(2)%
Kansas (a)
4,452
(9)% 4,307
(12)% 4,432
(9)%
Wyoming7,123
(5)% 6,750
(10)% 6,404
(10)%
Combined (b) (c)
5,862
(10)% 5,823
(11)% 5,890
(8)%
________________
(a)Kansas and Arkansas have weather normalization mechanisms which mitigate the weather impact on gross margins.
(b)The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to its weather normalization mechanism. Arkansas Gas Distribution is partially excluded based on the weather normalization mechanism in effect from November through April.
(c)To conform to the current year comparisons to normal, the 2016 utility variances compared to normal, as well as the 2016 combined variance compared to normal have been updated.
(d)30-Year Average is from NOAA climate normals.

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, so the demand for this product depends heavily upon weather throughout our service territories, and 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 weather patterns that are cooler than normal and provide higher than normal precipitation; both of which can reduce natural gas 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 would be aimed at increasing competition. 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 distribution charge for transporting the gas through our distribution network.



Rates and Regulation. Our Gas Utilities are subject to the jurisdiction of the public utilities commissions in the states where they operate. The 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, the rates of other utilities, 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 that allow them to adjust their rates to reflectallowing rate adjustments reflecting changes in the wholesale cost of natural gas and to ensure that they recoverrecovery of all the costs prudently incurred in purchasing gas for their customers. In addition to natural gas recovery mechanisms, we have other cost recovery mechanisms, such as regulatory riders,other recovery mechanisms, which vary by utility, but allow us to recover certain costs or earn a return on capital investments, such as those related to energy efficiency plansplan costs and system safety and integrity investments.

16
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The following table provides regulatory information for each of our natural gas utilities:
SubsidiaryJurisdic-tionAuthorized Rate of Return on EquityAuthorized Return on Rate BaseAuthorized Capital Structure Debt/EquityAuthorized Rate Base (in millions)Effective DateAdditional Regulatory Mechanisms
Arkansas Gas (c)
AR9.61%
6.82% (a)
51%/49%
$451.5 (b)
10/2018GCA, Main Replacement Program, At-Risk Meter Relocation Program, Legislative or Regulatory Mandated Expenditures, EECR, Weather Normalization Adjustment, Billing Determinant Adjustment
Colorado Gas (c)
CO9.20%6.56%50%/50%$303.21/2022GCA, SSIR, EECR/DSM
RMNGCO9.90%6.71%53%/ 47%$118.76/2018SSIR, Liquids/Off-system/Market Center Services Revenue Sharing
Iowa Gas (c)
IA9.60%6.75%50%/50%$300.91/2022GCA, EECR, System Safety and Maintenance Adjustment Rider, Gas Supply Optimization revenue sharing
Kansas Gas (c)
KSGlobal SettlementGlobal SettlementGlobal SettlementGlobal Settlement1/2022GCA, 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)
NE9.50%6.71%50%/50%$504.23/2021GCA, 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)
WY9.40%6.98%50%/50%$354.43/2020GCA, EECR, Rate Base Recovery on Acquisition Adjustment, Wyoming Integrity Rider, Choice Gas Program
____________________
SubsidiaryJurisdic-tionAuthorized Rate of Return on EquityAuthorized Return on Rate BaseAuthorized Capital Structure Debt/EquityAuthorized Rate Base (in millions)Effective DateAdditional Tariffed Mechanisms
Gas Utilities:      
Arkansas Gas (a)
AR9.4%
6.47% (b)
52%/48%
$299.4 (c)
2/2016
GCA, Main Replacement Program, At-Risk Meter Relocation Program, Legislative/Regulatory Mandate and Relocations Rider, Energy Efficiency, Weather Normalization Adjustment, Billing Determinant Adjustment

Colorado GasCO9.6%8.41%50%/50%$64.012/2012GCA, Energy Efficiency Cost Recovery/DSM
Colorado Gas Dist.(a)
CO10.0%8.02%49.52%/ 50.48%$127.112/2010
GCA, DSM

RMNG (a)
CO10.6%7.93%49.23%/ 50.77%$90.53/2014
System Safety Integrity Rider, Liquids/Off-system/Market Center Services Revenue Sharing

Iowa GasIAGlobal SettlementGlobal SettlementGlobal Settlement$109.22/2011GCA, Energy Efficiency Cost Recovery/DSM/Capital Infrastructure Automatic Adjustment Mechanism, Gas Supply Optimization revenue sharing
Kansas GasKSGlobal SettlementGlobal SettlementGlobal Settlement$127.41/2015GCA, Weather Normalization Tariff, Gas System Reliability Surcharge, Ad Valorem Tax Surcharge, Cost of Bad Debt Collected through GCA, Pension Levelized Adjustment
Nebraska GasNE10.1%9.11%48%/52%$161.39/2010GCA, Cost of Bad Debt Collected through GCA, Infrastructure System Replacement Cost Recovery Surcharge
Nebraska Gas Dist. (a)
NE9.6%7.67%
48.84%/
51.16%
$87.6/$69.8 (d)
6/2012
Choice Gas Program, System Safety and Integrity Rider, Bad Debt expense recovered through Choice supplier fee

Wyoming GasWY9.9%7.98%46%/54%$59.610/2014GCA, Energy Efficiency Cost Recovery/DSM, Rate Base Recovery on Acquisition Adjustment
Wyoming Gas Dist. (a)
WY9.92%7.98%
49.66%/
50.34%
$100.51/2011
Choice Gas Program, Purchased GCA, Usage Per Customer Adjustment

(a)    Arkansas Gas return on rate base is adjusted to remove certain liabilities from rate review capital structure for comparison with other subsidiaries.
__________
(a)Acquired through SourceGas
(b)Arkansas return on rate base adjusted to remove current liabilities from rate case capital structure for comparison with other subsidiaries.
(c)Arkansas rate base is adjusted to include current(b)    Arkansas Gas rate base is adjusted to include certain liabilities for comparison with other subsidiaries.
(d)Total Nebraska rate base of $87.6 million includes amounts allocated to serve non-jurisdictional and agricultural customers. Jurisdictional Nebraska rate base of $69.8 million excludes those amounts allocated to serve non-jurisdictional and agricultural customers and is used for calculation of jurisdictional base rates.


(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 ChoiceGasthe 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 JurisdictionCost Recovery Mechanisms
DSM/Energy EfficiencyIntegrity AdditionsBad DebtWeather NormalPension RecoveryGas CostBilling Determinant AdjustmentRevenue Decoupling
Arkansas Gasþþþþþ
Colorado Gasþþ
Colorado Gas Dist.þþþ
Rocky Mountain Natural GasN/AþN/AN/AN/AN/AN/AN/A
Iowa Gasþþþ
Kansas Gasþþþþþ
Nebraska Gasþþþ
Nebraska Gas Dist.þþþ
Wyoming Gas RMNG (a)
þþþ
Iowa Gasþþþ
Kansas Gasþþþþþ
Nebraska Gasþþþ
Wyoming Gas Dist.þþþþ
______________________________
(a)    ThisRMNG, which is onlyan 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 Cheyenne Light and does not apply to our other Wyoming gas utilities.RMNG.


Tariff Filings. See Note 13 in2 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for information regarding current natural gas rateregulatory activity.


Operating Statistics

2016 includesstatistics. See a summary of key operating statistics in the Gas Utilities segment operating results from the acquired SourceGas utilities starting February 12, 2016.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
Table of Contents
  Revenue (in thousands) 
Gross Margin (a) (in thousands)
  201720162015 201720162015
         
Residential $499,852
$433,106
$342,145
 $255,626
$228,512
$155,759
Commercial 197,054
162,547
117,574
 78,249
67,375
38,492
Industrial 24,454
21,245
22,398
 6,226
5,601
4,303
Other 8,647
12,694
8,065
 8,647
12,694
7,995
Total Distribution 730,007
629,592
490,182
 348,748
314,182
206,549
         
Transportation and Transmission 135,824
139,490
29,816
 135,824
139,282
29,816
         
Total Regulated 865,831
769,082
519,998
 484,572
453,464
236,365
         
Non-regulated Services 81,799
69,261
31,302
 53,455
32,714
15,290
         
Total Revenue & Gross Margin $947,630
$838,343
$551,300
 $538,027
$486,178
$251,655



  Revenue (in thousands) 
Gross Margin (a) (in thousands)
  201720162015 201720162015
         
Arkansas $153,691
$106,958
$—
 $94,007
$69,840
$—
Colorado 180,852
153,003
73,854
 100,718
86,016
25,387
Nebraska 252,631
244,992
170,972
 154,259
146,831
82,877
Iowa 143,446
130,776
147,952
 66,619
64,170
63,496
Kansas 105,576
100,670
114,362
 53,841
54,247
57,888
Wyoming 111,434
101,944
44,160
 68,583
65,074
22,007
Total Revenue & Gross Margin $947,630
$838,343
$551,300
 $538,027
$486,178
$251,655
__________
(a) Non-GAAP measure



 Quantities
Gas Utilities Quantities Sold & Transported (Dth)201720162015
    
Residential54,645,598
49,390,451
35,649,700
Commercial27,315,871
24,037,861
15,765,242
Industrial5,855,053
5,737,430
5,208,455
Other—
—
14,902
Total Distribution Quantities Sold87,816,522
79,165,742
56,638,299
    
Transportation and Transmission141,600,080
126,927,565
77,393,775
    
Total Quantities Sold & Transported229,416,602
206,093,307
134,032,074

 Quantities
Gas Utilities Quantities Sold & Transported (Dth)201720162015
    
Arkansas26,491,537
19,177,438
—
Colorado28,436,744
23,656,891
9,288,030
Nebraska73,890,509
67,796,021
43,992,986
Iowa37,013,645
35,383,990
35,490,228
Kansas28,251,947
26,463,314
28,086,737
Wyoming35,332,220
33,615,653
17,174,093
Total Quantities Sold & Transported229,416,602
206,093,307
134,032,074

Customers at End of Year201720162015
    
Residential806,744
800,980
533,413
Commercial86,461
84,049
50,175
Industrial2,214
2,050
1,859
Transportation/Other146,839
143,673
5,962
Total Customers at End of Year1,042,258
1,030,752
591,409

Customers at End of Year201720162015
    
Arkansas169,303
166,512
—
Colorado181,876
177,394
78,434
Nebraska290,264
289,653
201,261
Iowa157,444
156,014
155,196
Kansas114,082
112,957
112,364
Wyoming129,289
128,222
44,154
Total Customers at End of Year1,042,258
1,030,752
591,409


Utility Regulation Characteristics


State Regulations

Certain states where we conduct electric utility operations have adopted renewable energy portfolio standards that require or encourage our Electric Utilities to source, by a certain future date, a minimum percentage of the electricity delivered to customers from renewable energy generation facilities. As of December 31, 2017, we were subject to the following renewable energy portfolio standards or objectives:

Colorado. Colorado adopted a renewable energy standard that has two components: (i) electric resource standards and (ii) a 2% maximum annual retail rate impact for compliance with the electric resource standards. The electric resource standards require our Colorado Electric subsidiary to generate, or cause to be generated, electricity from renewable energy sources equaling: (i) 20% of retail sales from 2015 to 2019; and (ii) 30% of retail sales by 2020. Of these amounts, 3% must be generated from distributed generation sources with one-half of these resources being located at customer facilities. The net annual incremental retail rate impact from these renewable resource acquisitions (as compared to non-renewable resources) is limited to 2%. The standard encourages the CPUC to consider earlier and timely cost recovery for utility investment in renewable resources, including the use of a forward rider mechanism. We are currently in compliance with these standards.

Colorado Electric received a settlement agreement of its electric resource plan filed June 3, 2016, to meet requirements under the Colorado Renewable Energy Standard. The settlement, effective February 6, 2017, includes the addition of 60 megawatts of renewable energy to be in service by 2019 and provides for additional small solar and community solar gardens as part of the compliance plan. In the second quarter of 2017, Colorado Electric issued a request for proposals to construct new generation and presented the results to the CPUC on February 9, 2018. We expect a final decision from the CPUC in the second quarter of 2018 approving, conditioning, modifying or rejecting Colorado Electric’s recommended portfolio.

On November 7, 2016, Colorado Electric took ownership of Peak View, a $109 million, 60 MW wind project located near Colorado Electric's Busch Ranch Wind Farm. Peak View achieved commercial operation on November 7, 2016 and was purchased via progress payments throughout 2016 under a commission approved third-party build transfer and settlement agreement. This renewable energy project was originally submitted in response to Colorado Electric’s all-source generation request on May 5, 2014. The Commission’s settlement agreement provides for recovery of the costs of the project through Colorado Electric’s Electric Cost Adjustments and Renewable Energy Standard Surcharge for 10 years and recovery through the Transmission Cost Adjustment, after which Colorado Electric can propose base rate recovery. Colorado Electric will be required to make an annual comparison of the cost of the renewable energy generated by the facility against the bid cost of a PPA from the same facility.

Montana. In 2005, Montana established a renewable portfolio standard that requires public utilities to obtain a percentage of their retail electricity sales from eligible renewable resources. In March 2013, South Dakota Electric filed a petition with the MTPSC requesting a waiver of the renewable portfolio standards primarily due to exceeding the applicable “cost cap” included in the standards. In March 2013, the Montana Legislature adopted legislation that had the effect of excluding South Dakota Electric from all renewable portfolio standard requirements under State Senate Bill 164, primarily due to the very low number of customers we have in Montana and the relatively high cost of meeting the renewable requirements.

South Dakota. South Dakota has adopted a renewable portfolio objective that encourages, but does not mandate utilities to generate, or cause to be generated, at least 10% of their retail electricity supply from renewable energy sources by 2015.

Wyoming. Wyoming currently has no renewable energy portfolio standard.

Absent a specific renewable energy mandate in the territories we serve, our current strategy is to prudently incorporate renewable energy into our resource supply, seeking to minimize associated rate increases for our utility customers. Mandatory portfolio standards have increased and would likely continue to increase the power supply costs of our Electric Utility operations. Although we will seek to recover these higher costs in rates, we can provide no assurance that we will be able to secure full recovery of the costs we pay to be in compliance with standards or objectives. We cannot at this time reasonably forecast the potential costs associated with any new renewable energy standards that have been or may be proposed at the federal or state level.

Federal Regulation


Energy Policy Act.Black Hills Corporation The Energy Policy Act of 2005 included provisions to create an Electric Reliability Organization, which is a holding company whose assets consist primarilyrequired to promulgate mandatory reliability standards governing the operation of investmentsthe bulk power system in our subsidiaries, including subsidiariesthe U.S. FERC certified NERC as the Electric Reliability Organization and also issued an initial order approving many reliability standards that are public utilitieswent into effect in 2007. Entities that violate standards can be subject to fines and holding companies regulated by FERC undercan also be assessed non-monetary penalties, depending upon the nature and severity of the violation.

Federal Power Act and PUHCA 2005.

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 Black Hills Colorado IPP and Black Hills Wyomingentities 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, each files Electric Quarterly Reports are filed with FERC. South DakotaOur Electric ownsUtilities own and operatesoperate FERC-jurisdictional interstate transmission facilities and providesprovide 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.


The Federal Power Act authorizes FERC to certify and oversee a national electric reliability organization with authority to promulgate and enforce mandatory reliability standards applicable to all users, owners and operators of the bulk-power system. FERC has certified NERC as the electric reliability organization. NERC has promulgated mandatory reliability standards and NERC, in conjunction with regional reliability organizations that operate under FERC’s and NERC’s authority and oversight, enforces those mandatory reliability standards.

PUHCA 2005. PUHCA 2005 givesprovides FERC authority with respect to the books and records of a utility holding company. As a utility holding company withwhose assets consist primarily of investments in our subsidiaries, including subsidiaries that are public utilities and also a centralized service company subsidiaries,subsidiary, BHSC, and Black Hills Utility Holdings, we are subject to FERC’s authority under PUHCA 2005.


Power Generation Segment

Our Power Generation segment, which operatesPUHCA 2005 reiterated the definition and benefits of EWG status. Under PUHCA 2005, an EWG is an entity or generator engaged, directly or indirectly through Black Hills Electric Generation and its subsidiaries, acquires, develops and operates our non-regulated power plants. As of December 31, 2017, we held varying interests in independent power plants operating in Wyoming and Colorado with a total net ownership of approximately 269 MW.

We produce electric power from our generating plants and sell the electric capacity and energy, primarily toone or more affiliates, under a combination of mid- to long-term contracts, which mitigates the impact of a potential downturn in future power prices. We currently sell a substantial majority of our non-regulated generating capacity under contracts having terms greater than one year.

As of December 31, 2017, the power plant ownership interests held by our Power Generation segment included:
Power PlantsFuel TypeLocation
Ownership
Interest
Owned Capacity (MW)In Service Date
Wygen ICoalGillette, Wyoming76.5%68.9
2003
Pueblo Airport Generation (a)
GasPueblo, Colorado50.1%200.0
2012
    268.9
 
_________________________
(a)Black Hills Colorado IPP owns and operates this facility. This facility provides capacity and energy to Colorado Electric under a 20-year PPA with Colorado Electric. This PPA is accounted for as a capital lease on the accompanying Consolidated Financial Statements.

Black Hills Wyoming - Wygen I. The Wygen I generation facility is a mine-mouth, coal-fired power plant with a total capacity of 90 MW located at our Gillette, Wyoming energy complex. We own 76.5% of the plant and MEAN owns the remaining 23.5%. We sell 60 MW of unit-contingent capacity and energy from this plant to Wyoming Electric under a PPA that expires on December 31, 2022. The PPA includes an option for Wyoming Electric to purchase Black Hills Wyoming’s ownership interest in the Wygen I facility through 2019. The purchase price related to the option is $2.6 million per MW (65 MWs),


adjusted for all depreciated capital additions since 2009, and reduced by depreciation (approximately $5 million per year) over a 35-year life beginning January 1, 2009. The net book value of Wygen I at December 31, 2017 was $69 million and if Wyoming Electric had exercised the purchase option at year-end 2017, the estimated purchase price would have been approximately $133 million. We sell excess power from our generating capacity into the wholesale power markets when it is available and economical to do so.

Black Hills Colorado IPP - Pueblo Airport Generation. The Pueblo Airport Generating Station consists of two 100 MW combined-cycle gas-fired power generation plants located at a site shared with Colorado Electric. The plants commenced operation on January 1, 2012 and the assets are accounted for as a capital lease under a 20-year PPA with Colorado Electric, which expires on December 31, 2031. Under the PPA with Colorado Electric, any excess capacity and energy shall be for the benefit of Colorado Electric.

Sale of Noncontrolling Interest in Subsidiary

On April 14, 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million to a third party buyer. FERC approval of the sale was received on March 29, 2016. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric. Proceeds from the sale were used to pay down short-term debt and for other general corporate purposes. The operating results for Black Hills Colorado IPP remain consolidated with Black Hills Electric Generation, as Black Hills Colorado IPP has been determined to be a variable interest entity (VIE) in which the Company has a variable interest.

The following table summarizes MWh for our Power Generation segment:
Quantities Sold, Generated and Purchased (MWh) (a)
201720162015
Sold   
Black Hills Colorado IPP (b)
943,618
1,223,949
1,133,190
Black Hills Wyoming (c)
645,810
644,564
663,052
Total Sold1,589,428
1,868,513
1,796,242
 


Generated   
Black Hills Colorado IPP (b)
943,618
1,223,949
1,133,190
Black Hills Wyoming577,124
543,546
561,930
Total Generated1,520,742
1,767,495
1,695,120
    
Purchased   
Black Hills Wyoming (b)
69,377
85,993
68,744
Total Purchased69,377
85,993
68,744
____________________
(a)Company use and losses are not included in the quantities sold, generated and purchased.
(b)The decrease in 2017 is driven by the joint dispatch agreement Colorado Electric joined in 2017. See details of this agreement above in the Electric Utilities segment.
(c)Under the 20-year economy energy PPA with the City of Gillette, effective September 2014, Black Hills Wyoming purchases energy on behalf of the City of Gillette and sells that energy to the City of Gillette.

Operating Agreements. Our Power Generation segment has the following material operating agreements:

Economy Energy PPA and other ancillary agreements

◦Black Hills Wyoming sold its CTII 40 MW natural gas-fired generating unit to the City of Gillette, Wyoming on September 3, 2014. Under the terms of the sale, Black Hills Wyoming entered into ancillary agreements to operate CTII, and provide use of shared facilities including a ground lease and dispatch generation services. In addition, the agreement includes a 20-year economy energy PPA that contains a sharing arrangement in which the parties share the savings of wholesale power purchases made when market power prices are less than the cost of operating the generating unit.




Operating and Maintenance Services Agreement

◦In conjunction with the sale of the noncontrolling interest on April 14, 2016, an operating and maintenance services agreement was entered into between Black Hills Electric Generation and Black Hills Colorado IPP.  This agreement sets forth the obligations and responsibilities of Black Hills Electric Generation as the operator of the generating facility owned by Black Hills Colorado IPP.    This agreement is in effect from the date of the noncontrolling interest purchase and remains effective as long as the operator or one of its affiliates is responsible for managing the generating facilities in accordance with the noncontrolling interest agreement, or until termination by owner or operator. 

Shared Services Agreements

◦South Dakota Electric, Wyoming Electric and Black Hills Wyoming are parties to a shared facilities agreement, whereby each entity charges for the use of assets by the affiliate entity.

◦Black Hills Colorado IPP and Colorado Electric are parties to a facility fee agreement, whereby Colorado Electric charges Black Hills Colorado IPP for the use of Colorado Electric assets.

◦Black Hills Colorado IPP, Wyoming Electric and South Dakota Electric are parties to a Spare Turbine Use Agreement, whereby Black Hills Colorado IPP charges South Dakota Electric and Wyoming Electric a monthly fee for the availability of a spare turbine to support the operation of Cheyenne Prairie Generating Station.

◦Black Hills Colorado IPP and Black Hills Wyoming receive certain staffing and management services from BHSC.

Jointly Owned Facilities

◦Black Hills Wyoming and MEAN are parties to a shared joint ownership agreement, whereby Black Hills Wyoming charges MEAN for administrative services, plant operations and maintenance on their share of the Wygen I generating facility over the life of the plant.

Competition. 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 and foster competition within the wholesale electricity markets. Our Power Generation business 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 independent power producers in some regions.

The Energy Policy Act of 1992. The passage of the Energy Policy Act of 1992 encouraged independent power production by providing certain exemptions from regulation for EWGs. EWGs are exclusively in the business of owning, or operating or both owning and operating all or part of one or more eligible power 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 including rate regulation. We own two EWGs:of rates and charges, they are exempt from other FERC requirements. Through its subsidiaries, Black Hills Corporation is affiliated with three EWGs, Wygen I, and 200 MW (two 100 MW combined-cycle gas-fired units) at the Pueblo Airport Generating Station. OurGeneration (facilities #4-5) and Top of Iowa. Each of these three EWGs werehave been granted market-based rate authority, which allows FERC to waive certain accounting, record-keeping and reporting requirements imposed on public utilities with cost-based rates.authority.





Mining Segment

Our Mining segment operates through our WRDC subsidiary. We surface mine, process and sell primarily low-sulfur sub-bituminous coal at our mine near Gillette, Wyoming. The WRDC coal mine, which we acquired in 1956 from Homestake Gold Mining Company, is located in the Powder River Basin. The Powder River Basin contains one of the largest coal reserves in the United States. We produced approximately 4.2 million tons of coal in 2017.

During our surface mining operations, we strip and store the topsoil. We then remove the overburden (earth and rock covering the coal) with heavy equipment. Removal of the overburden typically requires drilling and blasting. Once the coal is exposed, we drill, fracture and systematically remove it, using front-end loaders and conveyors to transport the coal to the mine-mouth generating facilities. We reclaim disturbed areas as part of our normal mining activities by back-filling the pit with overburden removed during the mining process. Once we have replaced the overburden and topsoil, we re-establish vegetation and plant life in accordance with our approved post-mining topography plan.

In a basin characterized by thick coal seams, our overburden ratio, a comparison of the cubic yards of dirt removed to a ton of coal uncovered, has in recent years trended upwards. The overburden ratio at December 31, 2017 was 2.16, which increased from the prior year as we continued mining in areas with higher overburden. We expect our stripping ratio to be approximately 2.15 by the end of 2018 as we mine in areas with comparable overburden.

Mining rights to the coal are based on four federal leases and one state lease. The federal leases expire between April 30, 2019 and September 30, 2025 and the state lease expires on August 1, 2023. The duration of the leases varies; however, the lease terms generally are extended to the exhaustion of economically recoverable reserves, as long as active mining continues. We pay federal and state royalties of 12.5% of the selling price of all coal. As of December 31, 2017, we estimated our recoverable coal reserves to be approximately 195 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 coal reserve life is equal to approximately 47 years at the current production levels. Our recoverable coal reserve estimates are periodically updated to reflect past coal production and other geological and mining data. Changes in mining methods or the utilization of new technologies may increase or decrease the recovery basis for a coal seam. Our recoverable coal reserves include reserves that can be economically and legally extracted at the time of their determination. We use various assumptions in preparing our estimate of recoverable coal reserves. See Risk Factors under Mining for further details.

Substantially all of our coal production is currently sold under contracts to:

South Dakota Electric for use at the 90 MW Neil Simpson II plant. This contract is for the life of the plant;

Wyoming Electric for use at the 95 MW Wygen II plant. This contract is for the life of the plant;

The 362 MW Wyodak power plant owned 80% by PacifiCorp and 20% by South Dakota Electric. PacifiCorp is obligated to purchase a minimum of 1.5 million tons of coal each year of the contract term, subject to adjustments for planned outages. South Dakota Electric is also obligated to purchase a minimum of 0.375 million tons of coal per year for its 20% share of the power plant. This contract expires December 31, 2022;

The 110 MW Wygen III power plant owned 52% by South Dakota Electric, 25% by MDU and 23% by the City of Gillette to which we sell approximately 600,000 tons of coal each year. This contract expires June 1, 2060;

The 90 MW Wygen I power plant owned 76.5% by Black Hills Wyoming and 23.5% by MEAN to which we sell approximately 500,000 tons of coal each year. This contract expires June 30, 2038; and

Certain regional industrial customers served by truck to which we sell a total of approximately 150,000 tons of coal each year. These contracts have terms of one to five years.

Our Mining segment sells coal to South Dakota Electric and Wyoming Electric for all of their requirements under cost-based agreements that regulate earnings from these affiliate coal sales to a specified return on our coal mine’s cost-depreciated investment base. The return calculated annually is 400 basis points above A-rated utility bonds applied to our Mining investment base. South Dakota Electric made a commitment to the SDPUC, the WPSC and the City of Gillette that coal for South Dakota Electric’s operating plants would be furnished and priced as provided by that agreement for the life of the Neil Simpson II plant and through June 1, 2060, for Wygen III. The agreement with Wyoming Electric provides coal for the life of the Wygen II plant.


The price of unprocessed coal sold to PacifiCorp for the Wyodak plant is determined by the coal supply agreement described above. The agreement includes a price adjustment in 2019. The price adjustment essentially allows us to retain the full economic advantage of the mine’s location adjacent to the plant. The price adjustment is based on the market price of coal plus considerations for the avoided costs of rail transportation and a coal unloading facility, which PacifiCorp would have to incur if it purchased coal from another mine. In addition, the agreement also provides for the monthly escalation of coal price based on an escalation factor.

WRDC supplies coal to Black Hills Wyoming for the Wygen I generating facility for requirements under an agreement using a base price that includes price escalators and quality adjustments through June 30, 2038 and includes actual cost per ton plus a margin equal to the yield for Moody’s A-Rated 10-Year Corporate Bond Index plus 400 basis points with the base price being adjusted on a 5-year interval. The agreement stipulates that WRDC will supply coal to the 90 MW Wygen I plant through June 30, 2038.

Competition. Our primary strategy is to sell the majority of our coal production to on-site, mine-mouth generation facilities under long-term supply contracts. Historically, off-site sales have been to consumers within a close proximity to the mine. Rail transport market opportunities for WRDC coal are limited due to the lower heating value (Btu) of the coal, combined with the fact that the WRDC coal mine is served by only one railroad, resulting in less competitive transportation rates. Management continues to explore the limited market opportunities for our product through truck transport.

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 considerations and availability affect the overall demand for coal as a fuel.

Environmental Matters. We are subject to federal, state and local laws and regulations providing for air, water and solid waste pollution control; state facility-siting regulations; zoning and planning regulations of certain state and local authorities; federal health and safety regulations; and state hazard communication standards. See Environmental Matters section for further information.

Mine Reclamation. Reclamation is required during production and after mining has been completed. Under applicable law, we must submit applications to, and receive approval from, the WDEQ for any mining and reclamation plan that provides for orderly mining, reclamation and restoration of the WRDC mine. We have approved mining permits and are in compliance with other permitting programs administered by various regulatory agencies. The WRDC coal mine is permitted to operate under a five-year mining permit issued by the State of Wyoming. In 2016, that five-year permit was re-issued. Based on extensive reclamation studies, we have accrued approximately $12 million for reclamation costs as of December 31, 2017. Mining regulatory requirements continue to increase, which impose additional cost on the mining process.


Environmental Matters


At Black Hills,In November 2020, we deliverannounced clean energy goals to reduce GHG emissions that are based on prudent and proven solutions while minimizing cost impacts to our customerscustomers. See more information in Key Elements of our Business Strategy within Management’s Discussion and communities guided by our commitment to environmental stewardship;  to sustain environmental compliance which resultsAnalysis of Financial Condition and Results of Operations in healthier communities.Item 7 of this Annual Report on Form 10-K.


South Dakota and Wyoming Power Generation. Based on current regulations, technology and plans, the following table contains our current estimates of capital expenditures expected to be incurred over the next three years to comply with current environmental laws and regulations as described below, including regulations that cover water, air, soil and other pollutants, but excluding plant closures and the cost of new generation. The ultimate cost could be significantly different from the amounts estimated.

Environmental Expenditure Estimates
Total
(in thousands)
2018$3,086
20191,674
2020611
Total$5,371

Methane Rules (Greenhouse Gas Emissions). The EPA and the State of Colorado have implemented strict regulatory requirements on fugitive methane emissions associated with oil and natural gas exploration and production operations and from natural gas gathering and transmission systems. Additionally, the BLM issued a new rule referred to as the Methane Rule (aka Venting and Flaring rule) with the intent to capture methane leaks and lost royalties from companies that operate on federal land.

The rule has been postponed for one year by the BLM, but continues to be legally contested. While this risk is substantially reduced through the divestiture of BHEP, it continues to impact our remaining natural gas gathering and transmission operations. It is anticipated that regulatory control in this area may continue to expand, affecting a larger portion of Black Hills’ natural gas operations, including storage and distribution. Presently, we have seven compressor stations in our natural gas transmission operations affected by the rule (one in Arkansas, three in Colorado, and three in Wyoming).

Our operations are currently in compliance with both EPA and BLM rules. Although the BLM rule has been postponed, non- compliance would expose us to both enforcement action and civil suits. We will continue to monitor the litigation until the BLM’s rule status is clarified through the resolution of legal challenges. Additionally, we are developing a corporate-wide methane control strategy to address GHG emissions from our natural gas operations.

Water Issues. Our facilities are subject to a variety ofsignificant state and federal environmental regulations governing existingthat encourage the use of clean energy technologies and potential water/ wastewater dischargesregulate emissions of GHGs. We have undertaken initiatives to meet current requirements and protectionto 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 surface waters from oil pollution. Generally, such regulations are promulgated under the Clean Water Act and govern overall water/wastewater discharges through EPA’s surface water discharge and storm water permits. All of our facilities that are required to have such permits have those permits in place and are in compliance with discharge limitations and plan implementation requirements. The EPA proposed effluent limitation guidelines and standards on June 7, 2013 and published the final rule on November 3, 2015. This rule will have an impact on the Wyodak Plant. The terms of this new regulation impact the next permit renewal, which will be in 2020. Additionally,2019, the EPA regulates surface water oil pollution through its oil pollution prevention regulations. Alladopted 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 our facilities subject to these regulations have compliant prevention plans in place.

Short-term Emission Limits. The EPAAppeals for the D. C. Circuit issued a decision vacating and State Air Quality Programs implemented short-term emission limits for coal and natural gas-fired generating units during normal and start-up operating scenarios for Sulfur Dioxide (SO2), Nitrogen Oxide (NOx) and Opacity. The limits pertain to emissions during start-up periods and upset conditions such as mechanical malfunctions. State and federal regulatory agencies typically excuse short-term emissions exceedancesremanding the Affordable Clean Energy rule. That decision, if they are reported and corrected immediatelynot successfully appealed or if it occurs during start-up.

We proactively manage this requirement through maintenance efforts and installing additional pollution control systems to control SO2 emission short-term excursions during start-up. These actions have nearly eliminated our short-term emission limit compliance risk while plant availability remained above 90% for all four of our coal-fired plants at the Neil Simpson Complex. To eliminate the remaining potential for exceedances, an innovative trip logic mechanism was implemented to shut the power plant down if a predicted emission limit is to be exceeded. Similar efforts have been taken and similar results achieved with our natural gas fired combustion turbine sites as well.

Regional Haze (Impacts to the Wyodak Power Plant). The EPA Regional Haze rule was promulgated to improve visibility in our National Parks and Wilderness Areas.The State of Wyoming proposed controls in its Regional Haze State Implementation Plan (SIP) which allowed Pacificorp to install low-NOx burners in its Wyodak Plant. The EPA did not agree with the State of Wyoming’s determination and overruled it in a Federal Implementation Plan (FIP). The State of Wyoming and other interested parties are challenging the EPA’s determination. If the challenge is unsuccessful, additional capital investmentreconsidered, would be necessary to bring the Wyodak Plant into compliance. Our share of this capital investment would be approximately $40 million.

Mining. Operations at the WRDC mine must regularly address issues related to the proximity of the mine disturbance boundary to the City of Gillette, and to residential and industrial properties. Homeowner complaints and challenges to the permits may occur as mining operations move closer to residential areas. Specific concerns could include damage to wells, fugitive dust emissions, vibration and an emissions cloud from blasting.

Former Manufactured Gas Plants (FMGP). Federal and state laws authorizeallow the EPA and other agencies to issue orders compelling potentially responsible parties to clean up sites that are determined to present an actual or potential threat to human health or the environment. Our gas utilities are managing FMGP sites in Iowa, Nebraska and Colorado. We are currently in discussionsproceed with EPA, state regulators, and/or other third-parties to determine the ultimate resolution to these sites.

Clean Power Plan. The EPA was directed to repeal, revise, and replacealternate regulation of coal-fired power plants, either reviving the Clean Power Plan rule. The EPA issued two public noticesor proposing additional regulation. Compliance could result in the Federal Register late in 2017. The first identified the EPA’s intent to repeal the rule and the second was issued to seek public input on proposals to replace the CPP with an Advanced Notice of Proposed Rule Making (ANPRM). Natural gas and renewable generation industries are pushing the EPA to replace the current rule. We will continue to monitor and comment on the proposals and take appropriate action related to any new or modified rules.significant investment.


OSM Coal Combustion Residual Rule (CCR). The EPA issued the CCR that is currently effective and established requirements to protect surface and groundwater from impacts of coal ash impoundments. WRDC is exempt from the EPA CCR because coal ash is used for backfill reclamation in the areas previously mined. We would be subject to any proposed OSM CCR.

During the development of the OSM rule, it was anticipated that placing ash below groundwater levels would be disallowed. While our mining operations place ash below groundwater levels, the State of Wyoming gave us approval to grandfather this ash disposal in the Peerless Pit, with the Mine Plan Permit 232-T8, as a potential preventative measure to a new rule. As such, any risks associated with having to construct a new ash disposal site above groundwater and then complete backfilling the existing ash pit area to required reclamation levels are not applicable at this time.

Oil and Gas Segment Divestiture. Regulatory agencies placed a significant emphasis on regulating oil and gas activities over the past few years to address GHG and climate change concerns mainly due to the associated methane emissions. The regulatory activity significantly increased compliance risk. We will see relief in our compliance risk concerns with the divestiture of our oil and gas segment in 2018.

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 annually and develop mitigation strategies to successfully and responsibly manage and ensure compliance across the enterprise. enterprise successfully and responsibly. For additional information on environmental matters, see Item 1A and Note 193 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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Other PropertiesHuman Capital Resources


In additionOverview

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 facilities previously disclosed in Items 1safety of our customers and 2, we own or lease several facilities throughouttheir fellow employees, allows Black Hills Corporation to successfully grow and manage our service territories. Our owned facilitiesbusiness year over year. The impacts of COVID-19 to our businesses and employees are as follows:

In Rapid City, South Dakota, we have a new 220,000 square foot corporate headquarters building, Horizon Point, which was completeddiscussed in the fourth quarterRecent Developments within Management’s Discussion and Analysis of 2017.Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.

Our TeamAs of December 31, 2021As of December 31, 2020
Total employees2,8843,011
Women in executive leadership positions (a)
30%31%
Gender diversity (women as a % of total employees)26%26%
Represented by a union25%25%
Military veterans14%16%
Ethnic diversity (non-white employees as a % of total)12%11%
For the year ended December 31, 2021For the year ended December 31, 2020
Number of external hires214299
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 rate3%3%
____________________
In Arkansas, Nebraska, Iowa, Colorado, Kansas(a)    Executive leadership positions are defined as positions with Vice President, Senior Vice President or Chief in their title.
(b)    Includes voluntary and Wyoming we own various office, service center, storage, shop and warehouse space totaling over 717,000 square feet utilized by our Gas Utilities.involuntary separations, but excludes internships.


In South Dakota, Wyoming, Colorado and Montana we own various office, service center, storage, shop and warehouse space totaling approximately 237,000 square feet utilized by our Electric Utilities and Mining segments.

In addition to our owned properties, we lease 270,925 square feet of properties within our service areas.

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.

Total Employees

Number of Employees
As of December 31, 2021
Electric Utilities420 
Gas Utilities1,191 
Corporate and Other1,273 
Total2,884 

At December 31, 2017, we had 2,744 full-time employees in continuing operations. Approximately 27%2021, approximately 20% of our total employees are represented by a collective bargaining agreement. We have not experienced any labor stoppages in recent years. At December 31, 2017, approximately 24%and 22% of our Electric Utilities and Gas Utilities employees were eligible for regular or early retirement.retirement (age 55 with at least 5 years of service).


The following table sets forth the number of employees included in continuing operations:Collective Bargaining Agreements

Number of Employees
Corporate484
Electric Utilities and Gas Utilities2,199
Mining and Power Generation61
Total2,744

At December 31, 2017,2021, certain employees of our Electric Utilities and Gas Utilities were covered by the following collective bargaining agreements:agreements as shown in the table below. We have not experienced any labor stoppages in decades.
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UtilityNumber of EmployeesUnion AffiliationExpiration Date of Collective Bargaining Agreement
Colorado Electric
94 IBEW Local 667April 15, 2023
South Dakota Electric(a)131128 
IBEW Local 1250March 31, 2022
Wyoming Electric4225 
IBEW Local 111June 30, 20192024
ColoradoTotal Electric Utilities103247 
IBEW Local 667April 15, 2018
Iowa Gas115132 
IBEW Local 204JulyJanuary 31, 20202026
Kansas Gas(c)
1716 
Communications Workers of America, AFL-CIO Local 6407December 31, 20192024
Nebraska Gas9992 
IBEW Local 244March 13, 2022
Nebraska Gas(b)
143140 
CWA Local 7476October 30, 20192023
Wyoming Gas(b)
8615 
IBEW Local 111June 30, 2024
Wyoming Gas78 CWA Local 7476October 30, 20192023
Total Gas Utilities736473 
__________
(a)On January 26, 2017, South Dakota Electric’s contract was ratified with an expiration date of March 31, 2022.
(b)TotalIn the 2016 negotiations with the CWA Local 7476, the union agreed to disclaim their interest in Colorado Gas employees and to split the remaining bargaining unit into two distinct bargaining units, Nebraska Gas and Wyoming Gas.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.

(c)Kansas Gas completed a wage adjustment that was ratified on November 15, 2017.



For the year ended December 31, 2021
ITEM 1A.Total Case Incident Rate (incidents per 200,000 hours worked)RISK FACTORS1.06
Preventable Motor Vehicle Incident Rate (vehicle accidents per 1 million miles driven)1.81
Proactive Safety and Wellness Participation Rate (a)
71%

____________________
(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. The followingRisks that may adversely affect our business operations, financial condition, results of operations or cash flows are described below. These risk factors, andalong 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. These important

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 matters discussed hereinprices, 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 our future actual financial results or outcomes to differ materially.deviate from previous estimates.


OPERATING RISKS


Our financial performance depends on the successful operation of our facilities. If the risks involved in our operations are not appropriately managed or mitigated, our operations may not be successful and this could adversely affect our results of operations.

Operating electric generating facilities, the coal mine and electric and natural gas transmission and distribution systems, involvesnatural gas storage facilities and a coal mine.

The risks including: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 productutility services and satisfy our contractual obligations may be hindered;


Interruptions to•Natural gas supply of fuel and other commodities used infor generation and distribution. Our regulated utilities and non-regulated entities purchase fuelnatural gas from a number of suppliers.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 fuelnatural gas due to various factors, including but not limited to, transportation delays, labor relations, weather, sabotage, cyber-attacks and environmental regulations, whichregulations;

•Replacement power. The cost of supplying or securing replacement power during scheduled and unscheduled outages of generation facilities could limit our utilities’ ability to operate their facilities;

Electricity is dangerous for employees and the general public should they come in contact with power lines or electrical service facilities and equipment. Natural conditions and other disasters such as wind, lightning and winter storms can cause wildfires, pole failures and associated property damage and outages;

Operating hazards such as leaks, mechanical problems and accidents, including explosions, affecting our natural gas distribution system which could impact public safety, reliability and customer confidence;

Operational limitations imposed by environmental and other regulatory requirements;

Breakdown or failure of equipment or processes, including those operated by PacifiCorp at the Wyodak Plant;

Labor relations. Approximately 27% of our employees are represented by a total of eight collective bargaining agreements;

Our ability to transition and replace our retirement-eligible utility employees. At December 31, 2017, approximately 24% of our Electric Utilities and Gas Utilities employees were eligible for regular or early retirement;

Inability to recruit and retain skilled technical labor; and

Disruption in the functioning of our information technology and network infrastructure which are vulnerable to disability, failures and unauthorized access. If our information technology systems were to fail and we were unable to recover in a timely manner, we would be unable to fulfill critical business functions.

Changes in the interpretation of the Tax Cuts and Jobs Act (“TCJA”) could adversely affect us.

On December 22, 2017, the TCJA was signed into law, significantly reforming the U.S. Internal Revenue Code. The TCJA, among other things, includes a decrease in the U.S. federal corporate tax rate from 35% to 21%, imposes significant additional limitations on the deductibility of interest, allows for the expensing of capital expenditures, and modifies or repeals many business deductions and credits. The new tax law contains several provisions that impacted our 2017 financial results and will impact the Company into the future. As allowed under SEC Staff Accounting Bulletin No. 118 (SAB 118), the Company has recorded provisional income tax amounts as of December 31, 2017 for changes pursuant to the TCJA related to depreciation, for which the impacts could not be finalized upon issuance of the Company’s financial statements but reasonable estimates could be determined.



In accordance with ASC 740, the enactment of the law on December 22, 2017 required revaluation of federal deferred tax assets and liabilities using the new lower corporate statutory tax rate of 21%. As a result of the revaluation, deferred tax assets and liabilities were reduced by approximately $309 million. Of the $309 million, approximately $301 million is related to our regulated utilities and is reclassified to a regulatory liability. This regulatory liability will generally be amortized over the remaining life of the related assets using the normalization principles as specifically prescribed in the TCJA. On a consolidated financial statement basis, the revaluation of deferred tax assets and liabilities to the 21% federal corporate tax rate that are not subject to the regulatory construct resulted in a one-time, non-cash, income tax benefit of approximately $8 million in 2017.

The TCJA includes provisions limiting interest deductibility in certain circumstances. While we expect to maintain deductibility of interest expense, the lower tax rate reduces the tax benefits associated with interest deductibility on holding company debt that is not recovered in the regulatory construct.

We are working with utility regulators in each of the states we serve to provide benefits of tax reform to our customers. We expect an increase in working capital requirements as a result of complying with the TCJA and the impact of providing TCJA benefits to customers. The lower tax rate effective January 1, 2018, will negatively impact the Company’s cash flows by approximately $35 million to $45 million annually for the next several years.

If we are unable to obtain reasonable outcomes with our utility regulators in passing benefits of the TCJA back to customers, or if our interpretations on the provisions of depreciation or interest deductibility in the TCJA change, our results of operations, financial position and cash flows could be materially impacted.operations;

Construction, expansion, refurbishment and operation of power generating and transmission and resource extraction facilities involve significant risks which could reduce profitability.

The construction, expansion, refurbishment and operation of power generating and transmission and resource extraction facilities involve many risks, including:

•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;approvals could negatively impact our ability to operate

and our results of operations;
Contractual restrictions upon
•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;outages, could negatively impact our results of operations;


The cost of supplying or securing replacement power during scheduled and unscheduled outages;

The unavailability or increased cost of equipment;

The cost of recruiting and retaining or the unavailability of skilled labor;

Supply interruptions, work stoppages and labor disputes;

•Increased costs. Increased capital and operating costs to comply with increasingly stringent environmental laws and regulations;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;groups could negatively impact our ability to operate our businesses.

Weather interferences;

Availability and cost of fuel supplies;

Unexpected engineering, environmental and geological problems; and

Unanticipated cost overruns.


The ongoing operation of our facilitiesbusiness involves many of the risks described above, in addition to risks relatingassociated with threats to the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants may employ recently developed and technologically complex equipment, including newer environmental emission control technology.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 increase expenses 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.


Operating results canCyberattacks, 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. 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, or these risks and losses.

In May and July 2021, the TSA issued security directives 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 are currently implementing several of these directives and 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.

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 adversely affected by variations from normal weather conditions.vulnerable to disability, failures or unauthorized access.


Weather conditions, including the impacts of climate change, may cause fluctuation in customer usage.

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, customers’ energy use could increase or decrease. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating.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 and income 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.
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Table of operations, financial position and cash flows.Contents


Our businesses are located in areas that could be subject to seasonal natural disasters such as severe snow and ice storms, flooding and wildfires. These events could result in interruption of our business, damage to our property such as power lines and substations, and repair and clean-up costs. We may not be able to recover the costs incurred in restoring transmission and distribution property following these natural disasters through a change in our regulated rates thereby resulting in a negative impact on our results of operations, financial position and cash flows.FINANCIAL RISKS

Our Mining operations are subject to operating risks that are beyond our control which could affect our profitability and production levels. Our surface mining operations could be disrupted or materially affected due to adverse weather or natural disasters such as heavy snow, strong winds, rain or flooding.

Prices for some of our products and services as well as a portion of our operating costs are volatile and may cause our revenues and expenses to fluctuate significantly.


A portion of our net income is attributable to sales of contract and off-system wholesale electricity and natural gas. Energy prices are influenced by many factors outside our control, including, among other things, fuel prices, transmission constraints, supply and demand, weather, general economic conditions, and the rules, regulations and actions of system operators in those markets. Moreover, unlike most other commodities, electricity cannot be stored and therefore must be produced concurrently with its use. As a result, wholesale power markets may be subject to significant, unpredictable price fluctuations over relatively short periods of time.

Our Mining operations require reliable supplies of replacement parts, explosives, fuel, tires and steel-related products. If the cost of these increase significantly, or if sources of supplies and mining equipment become unavailable to meet our replacement demands, our productivity and profitabilitysub-investment grade credit rating could be lower than our current expectations.

Our revenues, results of operations and financial condition are impacted by customer growth and usage in our service territories and may fluctuate with current economic conditions, emerging technologies or responses to price increases.

Our revenues, results of operations and financial condition are impacted by demand in our service territories. Customer growth and usage may be impacted by a number of factors, including the voluntary reduction of consumption of electricity and natural gas by our customers in response to increases in prices and demand-side management programs, economic conditions impacting decreases in 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 would 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 results of operations, financial position and cash flows.

Our operations rely on storage and transportation assets owned by third parties to satisfy our obligations.

Our Electric Utilities, Gas Utilities and Power Generation segments rely on pipeline companies and other owners of gas storage facilities to deliver natural gas to customers, to supply our natural gas-fired power plants and to hedge commodity costs. If storage capacity is inadequate or transportation is disrupted,impact our ability to satisfy our obligations may be hindered. As a result,access capital markets.


we may be responsible for damages incurred by our counterparties, such as the additional cost of acquiring alternative supply at then-current market rates, or for penalties imposed by state regulatory authorities.


Our utilities are subject to pipeline safety and system integrity laws and regulations that may require significant capital expenditures or significant increases in operating costs.

Compliance with pipeline safety and system integrity laws and regulations, or future changes in these laws and regulations, may result in increased capital, operating and other costs which may not be recoverable in a timely manner from customers in rates. Failure to comply may result in fines, penalties, or injunctive measures that would not be recoverable from customers in rates and could result in a material impact on our results of operations, financial position and cash flows.

Our energy production, transmission and distribution activities, and our storage facilities for our natural gas involve numerous risks that may result in accidents and other catastrophic events that could give rise to additional costs and cause a substantial loss to us.

Inherent in our natural gas and electricity transmission and distribution activities, as well as in our transportation and storage of natural gas and our Mining operations, are a variety of hazards and operating risks, such as leaks, blowouts, fires, releases of hazardous materials, explosions and operational problems. These events could impact the safety of employees or others and result in injury or loss of human life, and cause significant damage to property or natural resources (including public lands), environmental pollution, impairment of our operations and substantial financial losses to us. Particularly for our transmission and distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the damages resulting from any such events could be substantial. While we maintain liability and property insurance coverage, such policies are subject to certain limits and deductibles. The occurrence of any of these events not fully covered by our insurance could have a material adverse effect on our financial position, results of operations or cash flows.

Threats of terrorism and catastrophic events that could result from terrorism, or individuals and/or groups attempting to disrupt our businesses, or the businesses of third parties, may impact our operations in unpredictable ways.

Terrorist acts or other similar events could harm our businesses by limiting their ability to generate, purchase or transmit power and by delaying their development and construction of new generating facilities and capital improvements to existing facilities. These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure our assets and could adversely affect our operations by contributing to disruption of supplies and markets for natural gas, oil and other fuels. They could also impair our ability to raise capital by contributing to financial instability and lower economic activity.

The implementation of security guidelines and measures and maintenance of insurance, to the extent available, addressing such activities could increase costs. These types of events could materially adversely affect our financial results. In addition, these types of events could require significant management attention and resources and could adversely affect our reputation among customers and the public.

A cyber attack may disrupt our operations, or lead to a loss or misuse of confidential and proprietary information and create a potential liability.

We use and operate sophisticated information technology systems and network infrastructure. In addition, in the ordinary course of business, we collect and retain sensitive information including personal information about our customers and employees. Cyber attacks targeting our electronic control systems used at our generating facilities and for electric and gas distribution systems, could result in a full or partial disruption of our electric and/or gas operations. Cyber attacks targeting other key information technology systems could further add to a full or partial disruption of our operations. Any disruption of these operations could result in a loss of service to customers and a significant decrease in revenues, as well as significant expense to repair system damage and remedy security breaches. Any theft, loss and/or fraudulent use of customer, shareowner, employee or proprietary data as a result of a cyber attack could subject us to significant litigation, liability and costs, as well as adversely impact our reputation with customers and regulators, among others.

We have instituted security measures and safeguards to protect our operational systems and information technology assets, including certain safeguards required by FERC. The security measures and safeguards we have implemented may not always be effective due to the evolving nature and sophistication of cyber attacks. Despite our implementation of security measures and safeguards, all of our information technology systems are vulnerable to disability, failures or unauthorized access, including cyber attacks. If our information technology systems were to fail or be breached by a cyber attack or a computer


virus and be unable to recover in a timely way, we would be unable to fulfill critical business functions and sensitive confidential and other data could be compromised which could have a material adverse effect not only on our financial results, but on our public reputation as well.

Increased risks of regulatory penalties could negatively impact our results of operations, financial position or liquidity.

Business activities in the energy sector are heavily regulated, primarily by agencies of the federal government. Agencies that historically sought voluntary compliance, or issued non-monetary sanctions, now employ mandatory civil penalty structures for regulatory violations. The FERC, NERC, CFTC, EPA, OSHA, SEC 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 operations and/or our financial results.

Certain Federal laws, including the Migratory Bird Act and the Endangered Species Act, provide special protection to certain designated species. These laws and any state equivalents provide for significant civil and criminal penalties for non-permitted activities that result in harm to or harassment of certain protected animals, including damage to their habitats. If such species are located in an area in which we conduct operations, or if additional species in those areas become subject to protection, our operations and development projects, particularly transmission, generation, wind and pipeline projects, could be restricted or delayed, or we could be required to implement expensive mitigation measures.

Our current or future development and expansion activities may not be successful, which could impair our ability to execute our growth strategy.

Execution of our growth plan is dependent on successful ongoing and future development and expansion activities. We can provide no assurance that we will be able to complete development projects or expansion activities we undertake or continue to develop attractive opportunities for growth. Factors that could cause our development and expansion activities to be unsuccessful include:

Our inability to obtain required governmental permits;

Our inability to secure adequate utility rates through regulatory proceedings;

Our inability to obtain financing on acceptable terms, or at all;

The possibility that one or more credit rating agencies would downgrade our issuer credit rating to below investment grade, thus increasing our cost of doing business;

Our inability to attract and retain management or other key personnel;

Our inability to negotiate acceptable construction, fuel supply, power sales or other material agreements;

Reduced growth in the demand for utility services in the markets we serve;

Changes in federal, state, local or tribal laws and regulations, particularly those which would make it more difficult or costly to fully develop our coal reserves or our power generation capacity;

Fuel prices or fuel supply constraints;

Pipeline capacity and transmission constraints;

Competition within our industry and with producers of competing energy sources; and

Changes in tax rates and policies.



Utilities

Regulatory commissions may refuse to approve some or all of the utility rate increases we have requested or may request in the future, or may determine that amounts passed through to customers were not prudently incurred and therefore are not recoverable.

Our regulated Electric Utilities 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 authorities 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. 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 the state public utility commissions will judge all of our costs, including our direct and allocated borrowing andsenior unsecured debt service costs, to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that produce a full recovery of our costs and the return on invested capital allowed by the applicable state public utility commission.

To some degree, each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs) without having to file a rate case. To the extent we are able to pass through such costs to our customers and a state public utility commission subsequently determines that such costs should not have been paid by the customers; we may be required to refund such costs. Any such costs not recovered through rates, or any such refund, could adversely affect our results of operations, financial position or cash flows.

If market or other conditions adversely affect operations or require us to make changes to our business strategy in any of our utility businesses, we may be forced to record a non-cash goodwill impairment charge. Any significant impairment of our goodwill related to these utilities would cause a decrease in our assets and a reduction in our net income and shareholders’ equity.

We had approximately $1.3 billion of goodwill on our consolidated balance sheets as of December 31, 2017. A substantial portion of the goodwill is related to the SourceGas Acquisition and the Aquila Transaction. If we make changes in our business strategy or if market or other conditions adversely affect operations in any of our businesses, we may be forced to record a non-cash impairment charge, which would reduce our reported assets, net income and shareholders’ equity. 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 economic conditions and interest rates, regulatory, industry or 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 one or more business segments, which may result in an impairment charge.

Municipal governments may seek to limit or deny franchise privileges which could inhibit our ability to secure adequate recovery of our investment in assets subject to condemnation.

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. 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.



Mining

If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, our costs could be significantly greater than anticipated or be incurred sooner than anticipated.

We conduct surface mining operations that are subject to operations, reclamation and closure standards. We estimate our total reclamation liabilities based on permit requirements, engineering studies and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is reviewed periodically by our management and engineers and by government regulators. The estimated liability can change significantly if actual costs vary from our original assumptions or if government regulations change significantly. GAAP requires that asset retirement obligations be recorded as a liability based on fair value, which reflects the present value of the estimated future cash flows. In estimating future cash flows, we consider the estimated current cost of reclamation and apply inflation rates. The resulting estimated reclamation obligations could change significantly if actual amounts or the timing of these expenses change significantly from our assumptions, which could have a material adverse effect on our results of operations and financial position.

Estimates of the quality and quantity of our coal reserves may change materially due to numerous uncertainties inherent in three-dimensional structural modeling, and any inaccuracies in interpretation or modeling could materially affect the estimated quantity and quality of our reserves.

The process of estimating coal reserves is uncertain and requires interpretations and modeling. Significant inaccuracies in interpretation or modeling could materially affect the quantity and quality of our reserve estimates. The accuracy of reserve estimates is a function of engineering and geological interpretation, conditions encountered during actual reserve recovery and undetected deposit anomalies. Variance from the assumptions used and drill hole modeling density could result in additions or deletions from our volume estimates. In addition, future environmental, economic or geologic changes may occur or become known that require reserve revisions either upward or downward from prior reserve estimates.

FINANCING RISKS

Our credit ratings could be lowered below investment grade in the future. If this were to occur, it could impact our access to capital, cost of capital and other operating costs.

Our issuer credit rating is Baa2 (Stable outlook) by Moody’s; BBBBBB+ (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 to complete new financings on reasonable terms, orif at all. A credit rating downgrade, particularly to a sub-investment grade, could also result in counterparties requiring us to post additional collateral under existing or new contracts or trades.contracts. In addition, a ratings downgrade would increase our interest expense under some of our existing debt obligations, including borrowings under our credit facilities.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.


Derivatives regulations could impede our ability to manage business and financial risks by restricting ourOur use of derivative financial instruments as hedges against fluctuating commodity prices and interest rates.

Dodd-Frank contains significant derivatives regulations, including a requirement that certain transactions be cleared resulting in a requirement to post cash collateral (commonly referred to as “margin”) for such transactions. Dodd-Frank provides for a potential exception from these clearing and cash collateral requirements for commercial end-users such as utilities and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions.

We use natural gas derivative instruments for our hedging activities for our Gas and Electric Utilities’ operations. We may also use interest rate derivative instruments to minimize the impact of interest rate fluctuations. As a result of Dodd-Frank regulations promulgated by the CFTC, we may be required to post collateral to clearing entities for certain swap transactions we enter into. In addition our exchange-traded futures contracts are subject to futures margin posting requirements, which could have a significant impact on our business by reducing our ability to execute derivative transactions to reduce commodity price and interest rate 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. In addition, a requirement for our counterparties to post collateral could result in additional costs being passed on to us, thereby decreasing our profitability.




Our hedging activities that are designed to protect against commodity price and financial market risks may cause fluctuationscould result in reportedmaterial financial results due to accounting requirements associated with such activities.losses.


We use various financial contracts and physical derivatives, including futures, forwards, options and swaps, to manage commodity price and financial marketinterest rate risks. The timing of the recognition of gains or losses on these economic hedges in accordance with GAAP doesmay not alwaysconsistently match up with the gains or losses on the commodities or assets being hedged. The differenceFor 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 can result in volatilitytreatment, fluctuating commodity prices may cause fluctuations in reported financial results even though the expected profit margin may be essentially unchanged from the dates the transactions were consummated.due to mark-to-market accounting treatment.


Our use of derivative financial instruments could result in material financial losses.

From time to time, we have sought to limit a portion of the potential adverse effects resulting from changes in commodity prices and interest rates by using derivative financial instruments and other hedging mechanisms. 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.


Market performance or changes in other assumptionsAdditionally, our exchange-traded futures contracts are subject to futures margin posting requirements. To the extent we are unable to meet these requirements, this could require us to make significant unplanned contributions to our pension plans and other postretirement benefit plans. Increasing costs associated with our defined benefit retirement plans may adversely affect our results of operations, financial position or liquidity.

As discussed in Note 18 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, we have one defined benefit pension plan (the pension plan is closed to new employees and frozen for certain employees who did not meet age and service based criteria) and several defined post-retirement healthcare plans and non-qualified retirement plans that cover certain eligible employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirementsbusiness by reducing our ability to execute derivative transactions to reduce commodity price uncertainty and the expense recognized related to these plans. These estimates and assumptionsprotect cash flows. Requirements to post collateral may change basedcause 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 actual return on plan assets, changes in interest rates and any changes in governmental regulations.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 theythese subsidiaries depend on our future earnings, capital requirements and financial condition and are subjectconditions to declaration by the Board of Directors. Our operating subsidiaries have certain restrictions on their ability to transfer funds in the form of dividends or loans to us.fund such dividends. See “Liquidity“Liquidity and Capital Resources”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.


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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 the capital markets and the costs and terms of available financing depend on many factors, including changes in our credit ratings, changes in the federal or state regulatory environment affecting energy companies, volatility in commodity or electricity prices and general economic and market conditions.




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.


National and regional economic conditions may cause increased counterparty credit risk, late payments and uncollectible accounts, which could adversely affect our results of operations, financial position and liquidity.accounts.


A future recession or pandemic, if one occurs, may lead to an increase in late payments or non-payment from retail residential, commercial and industrial utility customers, as well as from our non-utility customers. If late payments and uncollectible accounts increase, earnings and cash flows from our continuing operations may be reduced.


Our abilityWe may be unable to obtain insurance coverage, and the terms of any available insurance coverage could be adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers. Our insurance coveragewe currently have may not provide protection against allapply or may be insufficient to cover a significant losses.loss.


Our ability to obtain insurance, as well as the cost of such insurance, could be impacted by developments affecting the insurance businesses, international, national, state or local events, as well asindustry and the financial condition of insurers. InsuranceAdditionally, insurance providers could deny coverage may not continueor decline to be available at all,extend coverage under the same or at rates or onsimilar terms similar to thosethat are presently available to us. A loss for which we are not fullyadequately insured could materially and adversely affect our financial results. Our insuranceThe coverage we currently have in place may not apply to a particular loss, or it may not be sufficient or effective underto cover all circumstances and against all hazards or liabilities to which the Company may be subject, including but not limited toliability and losses associated with climate change, wildfire, natural gas and storage field explosions, cyber-security breaches, environmental hazards fire-related liability fromand natural eventsdisasters.

Market performance or inadequate facility maintenance, distribution property losses, cyber-security riskschanges in key valuation assumptions could require us to make significant unplanned contributions to our pension plan and dangers that exist inother 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 gatheringexpense recognized related to our pension and transportation of gas in pipelines.

Increasing costsother postretirement benefit plans. An adverse change to key assumptions associated with our health caredefined 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.

Costs associated with our healthcare plans and other benefits may adversely affect our results of operations, financial position or liquidity.could increase significantly.


The costs of providing health carehealthcare benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health carehealthcare 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 in oursupporting administrative and accounting processes, as well as changes to the cost of our plans, and the increasing costs and funding requirements associated with our health care plans may adversely affect our results of operations, financial position or liquidity.

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 can beis no assurance that the state public utility commissions will allow recovery.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.


An effective systemPANDEMIC RISK

The ongoing COVID-19 pandemic, including its variants, or any other pandemic and the associated impact on business and economic conditions could negatively affect our business operations, results of internal control may not be maintained, leading to material weaknesses in internal control overoperations, financial reporting.condition and cash flows.


Section 404The scale and scope of the Sarbanes-Oxley Act of 2002 requires management to make an assessment ofCOVID-19 outbreak, the designresulting pandemic or any other future pandemic, and effectiveness of internal controls. Our independent registered public accounting firm is required to attest to the effectiveness of these controls. During their assessment of these controls, management or our independent registered public accounting firm may identify areas of weakness in control design or effectiveness, which may lead toassociated impact on the conclusion that a material weakness in internal control exists. Any control deficiencies we identify in the futureeconomy and financial markets could adversely affect the Company’s business, results of operations and financial condition. As a provider of essential services, the Company has an obligation to provide electric and natural gas services to our ability to reportcustomers. The Company remains focused on protecting the health of our financial results on a timelycustomers, employees and accurate basis,the communities in which could result in a loss of investor confidence in our financial reports or have a material adverse effect on our ability towe operate our business or access sources of liquidity.

A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance thatwhile assuring the control system’s objectives will be met. If we are unable to assert that our internal controls over financial reporting are effective, market perceptioncontinuity of our business operatingoperations.
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Although the impact of the COVID-19 pandemic and its variants to our 2021 results and stock price could be adversely affected.



ENVIRONMENTAL RISKS

Federal and state laws concerning GHG regulations and air emissions may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain.

We own and operate regulated and non-regulated fossil-fuel generating plants in South Dakota, Wyoming and Colorado. Developments under federal and state laws and regulations governing air emissions from fossil-fuel generating plants may result in more stringent emission limitations, which couldoperation was not significant, we cannot ultimately predict whether it will have a material impact on our costsfuture liquidity, financial condition or results of operations. Various pending or final state and EPA regulations that willWe also cannot predict the impact our facilities are also discussed in Item 1 of this Annual ReportCOVID-19 on Form 10-K under the section “Environmental Matters.”

Due to uncertainty as to the final outcome of federal climate change legislation, legal challenges, state clean power plan developments or regulatory changes under the Clean Air Act, we cannot definitively estimate the effect of GHG legislation or regulation on our results of operations, cash flows or financial position.

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 reduction of load of coal-fired power generation facilities and potential increased loadhealth of our combined cycle natural gas-fired generation units. To the extentemployees, our regulated fossil-fuel generating plants are included in rate base we will attemptsupply chain or our ability to recovermitigate higher costs associated with complying with emission standards or other requirements. We will also attempt to recovermanaging through the emission complianceCOVID-19 pandemic.

As recovery from the COVID-19 pandemic continues, additional uncertainties have emerged, including the impacts of:
•vaccine mandates and testing requirements on our workforce;
•inflation increasing prices of commodities and materials, outside services, employee costs and interest rates;
•supply chain disruptions on the availability and cost of materials; and
•labor shortages and increased turnover on costs of our non-regulated fossil-fuel generating plants from utilityretaining and other purchasersattracting employees.

The situation remains fluid and it is difficult to predict with certainty the potential impact of the power generated by those non-regulated power plants. Any unrecovered costs could have a material impactCOVID-19 pandemic, or any other future pandemic, on our financial operating results including earnings, cash flows and liquidity.


ITEM 1B.UNRESOLVED STAFF COMMENTS

None.


ITEM 2.        PROPERTIES

See Item 1 for a description of operations and financial condition. our principal business properties.

In addition future changesto the properties disclosed in environmental regulations governing air emissions could render somethe 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 our power generating units more expensive or uneconomical to operatethe tangible utility properties of South Dakota Electric and maintain.

The costs to achieve or maintain compliance with existing or future governmental laws, regulations or requirements, and any failure to do so, could adversely affect our results of operations, financial position or liquidity.

Our business segmentsWyoming Electric are subject to numerous environmental lawsliens securing first mortgage bonds issued by South Dakota Electric and regulations affecting many aspects of present and future operations, including air emissions, 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 approvals. Compliance with environmental laws and regulations may require significant expenditures, including expenditures for cleanup costs and damages arising from contaminated properties. Failure to comply with environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting operating assets.Wyoming Electric, respectively.


The business segments may not be successful in recovering 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 the business segments’ financial position, results of operations or cash flows, future environmental compliance costs could have a significant negative impact..

The characteristics of coal may make it difficult for coal users to comply with various environmental standards related to coal combustion or utilization and the use of alternative energy sources for power generation as mandated by states could reduce coal consumption.ITEM 3.LEGAL PROCEEDINGS


Future regulations may require further reductions in emissions of mercury, hazardous pollutants, SO2, NOx, volatile organic compounds, particulate matter and GHG, which are released into the air when coal is burned. These requirements could require the installation of costly emission control technology or the implementation of other measures. Reductions in mercury emissions required by EPA’s MATS rule, will likely require some power plants to install new equipment, at substantial cost, or discourage the use of certain coals containing higher levels of mercury.

Coal competes with other energy sources, such as natural gas, wind, solar and hydropower. The EPA was directed to repeal, revise and replace the CPP rule. At this time, it is not known what effect this will have on coal as a domestic energy source, and could have a significant impact on our mining operations.



Existing or proposed legislation focusing on emissions enacted by the United States or individual states could make coal a less attractive fuel alternative for our customers and could impose a tax or fee on the producer of the coal. If our customers decrease the volume of coal they purchase from us or switch to alternative fuels as a result of existing or future environmental regulations aimed at reducing emissions, our operations and financial results could be adversely impacted.

Oil and Gas (Discontinued Operations)
If the risks involved in our Oil and Gas operations are not appropriately managed or mitigated through final sale dates, or if the divestiture of this business segment does not occur as currently anticipated, we could incur costs and/or additional write-downs of the carrying value of our natural gas and oil properties.
As of February 23, 2018, we have either closed transactions or signed contracts to sell more than 90 percent of our oil and gas properties. We expect to conclude the sale of all of our remaining oil and gas assets by mid-year 2018. Until the sale transactions are final, we continue to own and operate these assets and are exposed to the risks associated with those operations. In addition, while we have signed agreements for the significant majority of the properties, until the sales are closed, there is a risk that the transactions do not occur as planned. Additional operating costs, additional write-down of carrying value or the non-closure of sale agreements as currently signed could result in an adverse impact to our financial results.

ITEM 1B.UNRESOLVED STAFF COMMENTS

None.

ITEM 3.LEGAL PROCEEDINGS

Information regarding our legal proceedings is incorporated herein by reference to the “Legal Proceedings” sub-caption within Item 8, Note 193, “Commitments“Commitments, Contingencies and Contingencies”Guarantees”, of ourthe 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 59, 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 20 years of experience with the Company.

Brian G. Iverson, age 59, 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 18 years of experience with the Company.

Erik D. Keller, age 58, 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 56, 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 22 years of experience with the Company.

Jennifer C. Landis, age 47, 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 20 years of experience with the Company.

Stuart A. Wevik, age 60, has been Senior Vice President - Utility Operations since August 26, 2019. He served as Group Vice President - Electric Utilities from 2016 to August 2019, Vice President - Utility Operations from 2008 to 2016, Vice President - Operations from 2004 to 2008 and Vice President and General Manager from 2003 to 2004. Mr. Wevik has 36 years of experience with the Company. Mr. Wevik intends to retire on June 1, 2022.
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PART II


ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

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 DecemberJanuary 31, 2017,2022, we had 3,7323,475 common shareholders of record and approximately 25,00060,937 beneficial owners, representing all 50 states, the District of Columbia and 7 foreign countries.


We have paid a regular quarterly cash dividend each year sinceCOMPARATIVE STOCK PERFORMANCE

The following performance graph compares the incorporation ofcumulative total stockholder return from Black Hills Corporation common stock, as compared with the S&P 500 Index, S&P 500 Utilities index, and our predecessor company in 1941 and expect to continue paying a regular quarterly dividendperformance peer group for the foreseeable future. At its Januarypast five years. The graph assumes an initial investment of $100 on December 31, 2018 meeting, our Board of Directors declared a quarterly dividend of $0.475 per share, equivalent to an annual dividend of $1.90 per share.2016, and assumes all dividends were reinvested. The 2018 equivalent rate of $1.90 per share would mark 2018 as the 48th consecutive annual dividend increasestockholder return shown below for the Company.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.


bkh-20211231_g1.jpg

Years ended December 31,
201620172018201920202021
Black Hills Corporation$100.00 $100.77 $108.81 $139.91 $113.21 $134.59 
S&P 500100.00 121.83 116.49 153.17 181.35 233.41 
S&P 500 Utilities100.00 112.11 116.71 147.46 148.18 174.36 
Performance Peer Group (a)
100.00 113.59 119.17 143.70 123.74 140.78 
____________________
(a)    Performance Peer Group represents the list of 20 utility and energy industry companies used in our 2021 Proxy Statement which was filed with the SEC on March 18, 2021.

DIVIDENDS

For additional discussion ofinformation concerning dividends, our dividend policy and factors that may limit our ability to pay dividends, see “Liquidity“Key Elements of our Business Strategy” and “Liquidity and Capital Resources”Resources” under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report on Form 10-K.

Quarterly dividends paid and the high and low prices for our common stock, as reported in the New York Stock Exchange Composite Transactions, for the last two years were as follows:

Year ended December 31, 2017First QuarterSecond QuarterThird QuarterFourth Quarter
Dividends paid per share$0.445
$0.445
$0.445
$0.475
Common stock prices


 
High$67.02
$72.02
$71.01
$69.79
Low$60.02
$65.37
$67.08
$57.01

Year ended December 31, 2016First QuarterSecond QuarterThird QuarterFourth Quarter
Dividends paid per share$0.420
$0.420
$0.420
$0.420
Common stock prices    
High$61.13
$63.53
$64.58
$62.83
Low$44.65
$56.16
$56.86
$54.76


UNREGISTERED SECURITIES ISSUED


There were no unregistered securities sold during 2017.2021.


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.
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ISSUER PURCHASES OF EQUITY SECURITIES

There were no equity securities acquired for the twelve months ended December 31, 2017.
The following table contains monthly information about our acquisitions of equity securities for the three months ended December 31, 2021:


ITEM 6.SELECTED FINANCIAL DATA

Period
Total Number of Shares Purchased (a)
Average Price Paid per ShareTotal Number of Shares Purchased as Part of Publicly Announced Plans or ProgramsMaximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
October 1, 2021 - October 31, 20211$63.15 — — 
November 1, 2021 - November 30, 202177766.10 — — 
December 1, 2021 - December 31, 20218,68068.40 — — 
Total9,458$68.21 — — 
(Minor differences may result due to rounding)____________________
Years Ended December 31,2017 2016 2015 2014 2013 
(dollars in thousands, except per share amounts)         
           
Total Assets 
$6,658,902
 $6,541,773
 $4,626,643
 $4,216,752
 $3,820,875
 
           
Property, Plant and Equipment 
          
Total property, plant and equipment$5,567,518
 $5,315,296
 $3,849,309
 $3,606,931
 $3,412,623
 
Accumulated depreciation and depletion(1,026,088) (929,119) (794,695) (714,762) (687,010) 
Total property, plant and equipment, net$4,541,430
 $4,386,177
 $3,054,614
 $2,892,169
 $2,725,613
 
           
Capital Expenditures          
Continuing Operations$337,689
 $460,450
 $289,896
 $281,828
 $314,847
 
Discontinued Operations23,222
 6,669
 168,925
 109,439
 64,687
 
Total Capital Expenditures$360,911
 $467,119
 $458,821
 $391,267
 $379,534
 
           
Capitalization (excluding noncontrolling interests)
          
Current maturities of long-term debt$5,743
 $5,743
 $—
 $275,000
 $—
 
Notes payable211,300
 96,600
 76,800
 75,000
 82,500
 
Long-term debt, net of current maturities and deferred financing costs3,109,400
 3,211,189
(a)1,853,682
 1,255,953
 1,383,714
 
Common stock equity1,708,974
 1,614,639
(b)1,465,867
(b)1,353,884
 1,283,500
 
Total capitalization$5,035,417
 $4,928,171
 $3,396,349
 $2,959,837
 $2,749,714
 
           
Capitalization Ratios          
Short-term debt, including current maturities4% 2% 2% 12% 3% 
Long-term debt, net of current maturities62% 65%(a)55% 42% 50% 
Common stock equity34% 33% 43% 46% 47% 
Total100% 100% 100% 100% 100% 
           
Total Operating Revenues$1,680,266
 $1,538,916
 $1,261,322
 $1,338,456
 $1,220,968
 
           
Net Income Available for Common Stock          
Electric Utilities$110,082
 $85,827
 $77,579
 $57,270
 $49,003
 
Gas Utilities65,795
 59,624
 39,306
 44,151
 35,838
 
Power Generation46,479
(c)25,930
(c)32,650
 28,516
 16,288
(c)
Mining14,386
 10,053
 11,870
 10,452
 6,327
 
Corporate and intersegment eliminations(42,609)(d)(44,302)(d)(19,857)(d)(7,927) 5,855
(d)
Income (loss) from continuing operations available for common stock194,133
 137,132
 141,548
 132,462
 113,311
 
Income (loss) from discontinued operations, net of tax (b)
(17,099) (64,162) (173,659) (1,573) 4,112
 (e)
Net income (loss) available for common stock$177,034
 $72,970
 $(32,111) $130,889
 $117,423
 


SELECTED FINANCIAL DATA continued

Years Ended December 31,2017 2016 2015 2014 2013 
(dollars in thousands, except per share amounts)         
           
Dividends Paid on Common Stock$96,744
 $87,570
 $72,604
 $69,636
 $67,587
 
           
Common Stock Data(f) (in thousands)
          
Shares outstanding, average basic53,221
 51,922
 45,288
 44,394
 44,163
 
Shares outstanding, average diluted55,120
 53,271
 45,288
 44,598
 44,419
 
Shares outstanding, end of year53,541
 53,382
 51,192
 44,672
 44,499
 
           
Earnings (Loss) Per Share of Common Stock (in dollars)
        
Basic earnings (loss) per average share -          
Continuing operations$3.92
 $2.83
 $3.12
 $2.98
 $2.57
 
Discontinued operations (b)
(0.32) (1.23) (3.83) (0.04) 0.09
(e) 
Non-controlling interest(0.27) (0.19) —
 —
 —
 
Total$3.33
 $1.41
 $(0.71) $2.94
 $2.66
 
Diluted earnings (loss) per average share -         
Continuing operations$3.78
 $2.75
 $3.12
 $2.97
 $2.55
 
Discontinued operations (b)
(0.31) (1.20) (3.83) (0.04) 0.09
 
Non-controlling interest(0.26) (0.18) —
 —
 —
 
Total$3.21
 $1.37
 $(0.71) $2.93
 $2.64
 
           
Dividends Declared per Share$1.81
 $1.68
 $1.62
 $1.56
 $1.52
 
           
Book Value Per Share, End of Year$31.92
 $30.25
 $28.63
 $30.31
 $28.84
 
           
Return on Average Equity (h)
11.7% 8.9% 10.0% 10.0% 9.1% 



SELECTED FINANCIAL DATA continued
Years ended December 31,2017 2016 2015 2014 2013
Operating Statistics:         
Generating capacity (MW):         
Electric Utilities (owned generation)941
 941
 841
 841
 790
Electric Utilities (purchased capacity)110
 110
 210
 210
 150
Power Generation (owned generation)269
 269
 269
 269
 309
Total generating capacity1,320
 1,320
 1,320
 1,320
 1,249
Electric Utilities:         
MWh sold:         
Retail electric5,189,084
 5,140,519
 4,990,594
 4,775,808
 4,642,254
Contracted wholesale722,659
 246,630
 260,893
 340,871
 357,193
Wholesale off-system661,263
 769,843
 1,000,085
 1,118,641
 1,456,762
Total MWh sold6,573,006
 6,156,992
 6,251,572
 6,235,320
 6,456,209
          
Gas Utilities: 
         
Gas sold (Dth)87,816,522
 79,165,742
 56,638,299
 64,861,411
 64,131,850
Transport volumes (Dth)141,600,080
 126,927,565
 77,393,775
 77,433,266
 73,730,017
          
Power Generation Segment:         
MWh Sold (g)
1,589,428
 1,868,513
 1,796,242
 1,760,160
 1,564,789
MWh Purchased69,377
 85,993
 68,744
 38,237
 5,481
          
Mining Segment:         
Tons of coal sold (thousands of tons)4,183
 3,817
 4,140
 4,317
 4,285
Coal reserves (thousands of tons)194,909
 199,905
 203,849
 208,231
 212,595

(a)The increase in 2016 includes the debt associated with the SourceGas acquisition (see Note 6 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K).
(b)On November 1, 2017, we made the decision to divest our oil and gas business. 2017 includes an after-tax fair value impairment on held-for-sale assets of $13 million. 2016 includes non-cash after-tax impairment charges to crude oil and natural gas properties of $67 million. 2015 includes non-cash after-tax ceiling test impairment charges to crude oil and natural gas properties of $158 million and a non-cash after-tax equity investment impairment charge of $2.9 million (see Note 21 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K).
(c)
On April 14, 2016, BHEG sold a 49.9% interest in Black Hills Colorado IPP. Net income available for common stock for 2017 and 2016 was reduced by $14 million and $9.6 million, respectively, attributable to this noncontrolling interest. 2013 includes $6.6 million after-tax expense relating to the settlement of interest rate swaps and write-off of deferred financing costs in conjunction with the prepayment of Black Hills Wyoming’s project financing.
(d)2017, 2016 and 2015 include incremental SourceGas Acquisition costs, after-tax of $2.8 million, $30 million and $6.7 million, respectively. 2016 and 2015 also include after-tax internal labor costs attributable to the SourceGas Acquisition of $9.1 million and $3.0 million that otherwise would have been charged to other segments. 2013 includes $20 million non-cash after-tax unrealized mark-to-market gains, respectively, related to certain interest rate swaps; 2013 also includes $7.6 million after-tax expense for a make-whole premium, write-off of deferred financing costs relating to the early redemption of our $250 million notes and interest expense on new debt.
(e)Discontinued operations in 2013 includes post-closing adjustments and operations relating to Enserco, sold in 2012.
(f)In 2016, we issued 1.97 million shares at an average share price of $60.95 under our ATM equity offering program. In November 2015, we issued 6.3 million shares of common stock, par value $1.00 per share at a price of $40.25.
(g)The decrease in 2017 is driven by the joint dispatch agreement Colorado Electric became a part of in 2017. See details of this agreement in Item 1. Business and Properties, Electric Utilities Segment in this Annual Report on Form 10-K.
(h)Calculated based on Income (loss) from continuing operations available for common stock.


For additional information on our business segments see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A, Quantitative and Qualitative Disclosures about Market Risk and Note 5(a)    Shares were acquired under the share withholding provisions of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

ITEMS 7 &MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
and 7A.OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISKOmnibus 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 growth-oriented, vertically-integratedenergy solutions provider that invests in our communities’ safety, sustainability and growth with a mission of Improving Life with Energy and a vision to be the Energy Partner of Choice. The Company’s core mission— and our primary focus — is to provide safe, reliable and cost-effective electric and natural gas service to 1.3 million utility company operating in the United States. We report our operations and results in the following financial segments.

Electric Utilities: Our Electric Utilities segment generates, transmits and distributes electricity to approximately 210,000 customers in South Dakota, Wyoming, Colorado and Montana. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our own distribution systems. Additionally, we sell excess power to other utilities and marketing companies,over 800 communities in eight states, including our affiliates.

Gas Utilities: Our Gas Utilities conduct natural gas utility operations through our Arkansas, Colorado, Iowa, Kansas, WyomingMontana, Nebraska, South Dakota and Nebraska subsidiaries. OurWyoming.

We conduct our business operations through two operating segments: Electric Utilities and Gas Utilities transport and distribute natural gas through our network to approximately 1,042,000 natural gas customers. Additionally, we sell contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates, on an as available basis.

Our Gas Utilities also provide non-regulated services through Black Hills Energy Services. Black Hills Energy Services provides approximately 52,000 retail distribution customers in Nebraska and Wyoming with unbundled natural gas commodity offerings under the regulatory-approved Choice Gas Program. We also sell, install and service air conditioning, heating and water-heating equipment, and provide associated repair service and protection plans under various trade names. Service Guard and CAPP provide appliance repair services to approximately 63,000 and 31,000 residential customers, respectively, through Company technicians and third-party service providers, typically through on-going monthly service agreements. Tech Services serves gas transportation customers throughout our service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.

Power Generation: Our Power Generation segment produces electric power from its generating plants and sells the electric capacity and energy principally to our utilities under long-term contracts.

Mining: Our Mining segment produces coal at our coal mine near Gillette, Wyoming and sells the coal primarily to on-site, mine-mouth power generation facilities.

Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. All of our non-utility business segments support our utilities.Utilities. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other. The Company conducts its utility operations under the name Black Hills Energy predominantly in rural areas of the Rocky Mountains and Midwestern states. The Company considers itself a domestic electric and natural gas utility company.


Overview: Our customer focus provides opportunitiesThe Company has provided energy and served customers for 138 years, since the 1883 gold rush days in Deadwood, South Dakota. Throughout our history, the common thread that unites the past to expandthe present is our business by constructing additional rate base assetscommitment to serve our utility customers and expandingcommunities. By being responsive and service focused, we can help our non-regulatedcustomers and communities thrive while meeting rapidly changing customer expectations.

An important 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 products and servicesa low carbon future, integrating the Energy Transition and more renewable energy into our overall strategy and decision making. For this important work, we are Ready to serve. In addition, we are committed to a more sustainable future by better managing our wholesale customers.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 Objective

Our objectiveemphasis is to be best-in-class relative to certain operational performance metrics, such ason consistently outperforming utility industry averages in key safety power plant availability,metrics; modernizing utility infrastructure; transforming the customer experience; growing our electric and natural gas system reliability, efficiency, customer serviceload; and cost management. Our notable operational performance metrics for 2017 include:

•
Our three electric utilities achieved 1st quartile reliability ranking with 67 customer minutes of outage time (SAIDI) in 2017 compared to industry averages (IEEE 2017 1st quartile is less than 97 minutes);

Our power generation fleet achieved a forced outage factor of 5.04% for coal-fired plants, 1.42% for natural gas-fired turbines, 0.74% for natural gas-combined cycle power blocks and 0.17% for diesel plants in 2017, compared to an industry average* of 3.10%, 3.38%, 2.24% and 1.03%, respectively (*NERC GADS 2016 Data);

Our power generation fleet availability was 89.82% for coal-fired plants, 95.70% for natural gas-fired turbines, 95.93% for natural gas-combined cycle power blocks, 99.53% for diesel-fired plants, and 94.06% for wind generation in 2017 while the industry averages** were 86.37%, 90.88%, 94.11%, 93.61 and 96.0% respectively (** NERC GADS 2016 data used for coal, natural gas-gas turbines, natural gas-combined cycles, and diesel plants; NERC GADS does not keep wind at this time; accordingly, wind average obtained from wind generation articles by manufacturer(s));

•
Our safety TCIR of 1.3 compares to an industry average of 2.1+ and our DART rate of 0.8 compares to an industry average of 1.2+ (+ Bureau of Labor Statistics (BLS)-all utilities of all sizes - most recent industry averages are 2016); and
Our mine completed over five years with no MSHA reportable injuries and received an award from the State of Wyoming for eight years without a lost time incident.  The mine also received the State Mine Inspector’s Award for the fourth year in a row forpursuing operating as the safest small mine and received the Mine Safety and Health Administration’s Certificate of Achievement for No Lost Time Incidents.

The electric utility industry is facing requirements to upgrade aging infrastructure, deploy smart grid technology and comply with new state and federal environmental regulations and renewable portfolio standards. Increased energy efficiency and smart grid technologies suppress demand in manyefficiencies. These areas of focus will present the United States. These competing considerations present challenges tocompany with significant investment needs as we harden our infrastructure systems, meet customer growth and fulfill customer expectations for cleaner energy companies’ approach to balancing capital spending and obtaining satisfactory rate recovery on investments.

State regulatory commissions have lowered authorized returns and implemented other regulatory mechanisms for cost recovery due to the slow-growing economy and concerns that utility rate increases may further harm local economies. The average awarded return on equity for investor-owned utilities over the past year has been just under 10%. The average regulatory lag is less than 12 months, according to the Edison Electric Institute. Sustained low interest rates heavily influence the lower rates of return, along with actions by state commissions to moderate rate increases during a period of economic recovery.

In our gas and electric utilities’ service territories, we will continue to work with regulators to ensure we meet our obligations to serve projected customer demand and to comply with environmental mandates by constructing the infrastructure necessary to provide safe, reliable energy. By maintaining our high customer service and reliability standards in a cost-efficient manner, our goal is to secure appropriate rate recovery that provides fair economic returns on our utility investments.

According to the U.S. Energy Information Administration, approximately 30% of electricity generated in the United States is from coal-fired power plants.services. It will take significant timealso allow us to better understand our customer and expense before this generation can be replaced with alternative technologies. As a result, coal-fired resources will remain a necessary componentcommunity needs while providing more intuitive and cost-effective solutions.


30
Table of the nation’s electric supply for the foreseeable future. The regulatory climate in recent years, combined with the EPA’s regulations, have limited construction of new conventional coal-fired power plants, but, if technologies such as carbon capture and sequestration become more proven and less expensive, they could provide for the long-term economic use of coal. We have investigated and will continue to investigate the possible deployment of these technologies at our mine site in Wyoming.Contents

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 Customers202120202019
Residential853,908 844,999 831,351 
Commercial84,234 83,135 82,912 
Industrial2,158 2,235 2,208 
Transportation153,929 152,568 149,971 
Total Natural Gas Retail Customers at End of Year1,094,229 1,082,937 1,066,442 

As of December 31,
Retail Customers202120202019
Arkansas180,216 178,281 174,447 
Colorado202,747 197,817 191,950 
Iowa161,905 160,952 159,641 
Kansas117,862 116,973 115,846 
Nebraska298,832 296,778 293,576 
Wyoming132,667 132,136 130,982 
Total Natural Gas Retail Customers at End of Year1,094,229 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:
StateWorking Capacity (Mcf)Cushion Gas
(Mcf)		Total Capacity (Mcf)Maximum Daily Withdrawal Capability (Mcfd)
Arkansas9,273,700 12,318,040 21,591,740 196,000 
Colorado2,361,495 6,164,715 8,526,210 30,000 
Wyoming5,733,900 17,145,600 22,879,500 36,000 
Total17,369,095 35,628,355 52,997,450 262,000 

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

StateIntrastate Gas
Transmission Pipelines
(in line miles)		Gas Distribution
Mains
(in line miles)		Gas Distribution
Service Lines
(in line miles)
Arkansas874 4,972 1,275 
Colorado693 6,990 2,303 
Iowa172 2,863 2,486 
Kansas330 2,980 1,374 
Nebraska1,311 8,443 2,773 
Wyoming1,352 3,532 1,653 
Total4,732 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.

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The following table provides regulatory information for each of our natural gas utilities:
SubsidiaryJurisdic-tionAuthorized Rate of Return on EquityAuthorized Return on Rate BaseAuthorized Capital Structure Debt/EquityAuthorized Rate Base (in millions)Effective DateAdditional Regulatory Mechanisms
Arkansas Gas (c)
AR9.61%
6.82% (a)
51%/49%
$451.5 (b)
10/2018GCA, Main Replacement Program, At-Risk Meter Relocation Program, Legislative or Regulatory Mandated Expenditures, EECR, Weather Normalization Adjustment, Billing Determinant Adjustment
Colorado Gas (c)
CO9.20%6.56%50%/50%$303.21/2022GCA, SSIR, EECR/DSM
RMNGCO9.90%6.71%53%/ 47%$118.76/2018SSIR, Liquids/Off-system/Market Center Services Revenue Sharing
Iowa Gas (c)
IA9.60%6.75%50%/50%$300.91/2022GCA, EECR, System Safety and Maintenance Adjustment Rider, Gas Supply Optimization revenue sharing
Kansas Gas (c)
KSGlobal SettlementGlobal SettlementGlobal SettlementGlobal Settlement1/2022GCA, 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)
NE9.50%6.71%50%/50%$504.23/2021GCA, 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)
WY9.40%6.98%50%/50%$354.43/2020GCA, 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 JurisdictionCost Recovery Mechanisms
DSM/Energy EfficiencyIntegrity AdditionsBad DebtWeather NormalPension RecoveryGas CostRevenue Decoupling
Arkansas Gasþþþþþ
Colorado Gasþþþ
RMNG (a)
þ
Iowa Gasþþþ
Kansas Gasþþþþþ
Nebraska Gasþþþ
Wyoming Gasþþþ
____________________
(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.
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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.


Efficiently plan, constructWe are subject to significant state and operate utility systemsfederal environmental regulations that provide safe, reliableencourage the use of clean energy technologies and affordableregulate 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.
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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 competitive, sustained returnstheir 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 TeamAs of December 31, 2021As of December 31, 2020
Total employees2,8843,011
Women in executive leadership positions (a)
30%31%
Gender diversity (women as a % of total employees)26%26%
Represented by a union25%25%
Military veterans14%16%
Ethnic diversity (non-white employees as a % of total)12%11%
For the year ended December 31, 2021For the year ended December 31, 2020
Number of external hires214299
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 rate3%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 Utilities420 
Gas Utilities1,191 
Corporate and Other1,273 
Total2,884 

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.
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UtilityNumber of EmployeesUnion AffiliationExpiration Date of Collective Bargaining Agreement
Colorado Electric94 IBEW Local 667April 15, 2023
South Dakota Electric128 IBEW Local 1250March 31, 2022
Wyoming Electric25 IBEW Local 111June 30, 2024
Total Electric Utilities247 
Iowa Gas132 IBEW Local 204January 31, 2026
Kansas Gas16 Communications Workers of America, AFL-CIO Local 6407December 31, 2024
Nebraska Gas92 IBEW Local 244March 13, 2022
Nebraska Gas140 CWA Local 7476October 30, 2023
Wyoming Gas15 IBEW Local 111June 30, 2024
Wyoming Gas78 CWA Local 7476October 30, 2023
Total Gas Utilities473 
Total720 

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%
____________________
(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 Companynature 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 andependent 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 utility serving approximately 1.25 million utilitycustomer 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 than 800 communitiescost 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 Rocky Mountainstate 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 Midwestern states,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 territory that spans nearly 1,600 miles, reaching from Cody, Wyoming to Blytheville, Arkansas. Our natural gasterritories possess the power of condemnation and could establish a municipal utility business owns and operateswithin a 45,000-mile natural gas transmission and distribution pipeline system andportion of our electric utility business owns and operates 941 megawatts of generation capacity and 8,800 miles of transmission and distribution lines. The company’s primary growth strategy is to invest in these utility systems to ensure the continued delivery of safe, reliable and affordable energy for customers and competitive, sustained returnscurrent service territories by limiting or denying franchise privileges for our shareholders.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.


Maintain a safe and reliable gas distribution system.
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Changes in Federal tax law may significantly impact our business.

We rigorously comply with all applicableare subject to taxation by the various taxing authorities at the federal, state and local regulationslevels 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 strivedeductions and credits. The outcome of regulatory proceedings regarding the extent to consistently meet industry best practice standards.  Preventing natural gas losseswhich 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 our gas delivery systems isother tax-related assumptions may cause actual financial results to deviate from previous estimates.

OPERATING RISKS

Our financial performance depends on the successful operation of the utmost importance to ensure publicelectric generating facilities, electric and employee safety and to protect the environment. We construct, maintain and update our gas delivery systems with state of the art materials and products and continuously monitor their integrity. System leaks are repaired as soon as possible while ensuring the safety of the public and our employees.  We have removed all cast and wrought iron from our natural gas transmission and distribution systems, natural gas storage facilities and they contain very minimal quantitiesa 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 bare steel pipelines. Manyor 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 are authorized to use system safety, integrity and replacement cost recovery mechanisms that providenon-regulated entities purchase natural gas from a number of suppliers for customer rate adjustments which reflect the cost incurred in repairingour generating facilities and replacing the gas delivery systems.

Efficiently plan, construct and operate rate base power generation facilities to serve our electric utilities. Our company began as a vertically-integrated electric utility. This business model remains a core strength and strategy today as we invest in and operate efficient power generation resources to cost-effectively supply electricityfor 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 striverely on various suppliers in our supply chain for the materials necessary to provide powerexecute 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 reasonable ratesDecember 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 customersemployees are represented by unions; and earn competitive returns for

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



Our power production strategy focuses on low-cost construction andThe ongoing operation of our generating facilities. Our low power productionbusiness 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 result from a variety of factors including low fuel costs, efficiencyor be unable to deliver energy and/or operate below expected capacity levels, which in converting fuel into energy, low per unit operationturn could reduce revenues or cause us to incur higher operating and maintenance costs and highpenalties. 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 vendors’ information systems, could further add to a full or partial disruption of our operations. 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, or these risks and losses.

In May and July 2021, the TSA issued security directives 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 are currently implementing several of these directives and 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.

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.

Weather conditions, including the impacts of climate change, may cause fluctuation in customer usage.

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, customers’ energy use could increase or decrease. 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 and income 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.
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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, if at all. 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.

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 power plant availability. 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.

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We leveragemay be unable to obtain financing on reasonable terms needed to refinance debt, fund planned capital expenditures or otherwise execute our mine-mouth coal-fired generating capacityoperating strategy.

Our ability to eliminate fuel transportationexecute 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 the capital markets and the costs and terms of available financing depend on many factors, including changes in our credit ratings, changes in the federal or state regulatory environment affecting energy companies, volatility in commodity or electricity prices and general economic and market conditions.

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 often representour utility subsidiaries are adequately capitalized to provide safe and reliable service. Possible additional measures would be evaluated in the largestcontext of then-prevailing market conditions, prudent financial management and any applicable regulatory requirements.

National and regional economic conditions may cause increased counterparty credit risk, late payments and uncollectible accounts.

A future recession or pandemic, if one occurs, may lead to an increase in late payments or non-payment from retail residential, commercial and industrial utility customers, as well as from our non-utility customers. If late payments and uncollectible accounts increase, earnings and cash flows from our continuing operations may be reduced.

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 the Company may be subject, including liability and losses associated with climate change, wildfire, 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.

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.

PANDEMIC RISK

The ongoing COVID-19 pandemic, including its variants, or any other pandemic and the associated impact on business and economic conditions could negatively affect our business operations, results of operations, financial condition and cash flows.

The scale and scope of the COVID-19 outbreak, the resulting pandemic or any other future pandemic, and the associated impact on the economy and financial markets could adversely affect the Company’s business, results of operations and financial condition. As a provider of essential services, the Company has an obligation to provide electric and natural gas 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.
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Although the impact of the COVID-19 pandemic and its variants to our 2021 results of operation was not significant, we cannot ultimately predict whether it will have a material impact on our future liquidity, financial condition or results of operations. We also cannot predict the impact of COVID-19 on the health of our employees, our supply chain or our ability to mitigate higher costs associated with managing through the COVID-19 pandemic.

As recovery from the COVID-19 pandemic continues, additional uncertainties have emerged, including the impacts of:
•vaccine mandates and testing requirements on our workforce;
•inflation increasing prices of commodities and materials, outside services, employee costs and interest rates;
•supply chain disruptions on the availability and cost of materials; and
•labor shortages and increased turnover on costs of retaining and attracting employees.

The situation remains fluid and it is difficult to predict with certainty the potential impact of the COVID-19 pandemic, or any other future pandemic, on our financial operating results including earnings, cash flows and 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 59, 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 20 years of experience with the Company.

Brian G. Iverson, age 59, 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 18 years of experience with the Company.

Erik D. Keller, age 58, 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 56, 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 22 years of experience with the Company.

Jennifer C. Landis, age 47, 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 20 years of experience with the Company.

Stuart A. Wevik, age 60, has been Senior Vice President - Utility Operations since August 26, 2019. He served as Group Vice President - Electric Utilities from 2016 to August 2019, Vice President - Utility Operations from 2008 to 2016, Vice President - Operations from 2004 to 2008 and Vice President and General Manager from 2003 to 2004. Mr. Wevik has 36 years of experience with the Company. Mr. Wevik intends to retire on June 1, 2022.
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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, 2022, we had 3,475 common shareholders of record and 60,937 beneficial owners, representing all 50 states, the District of Columbia and 7 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, 2016, 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.

bkh-20211231_g1.jpg

Years ended December 31,
201620172018201920202021
Black Hills Corporation$100.00 $100.77 $108.81 $139.91 $113.21 $134.59 
S&P 500100.00 121.83 116.49 153.17 181.35 233.41 
S&P 500 Utilities100.00 112.11 116.71 147.46 148.18 174.36 
Performance Peer Group (a)
100.00 113.59 119.17 143.70 123.74 140.78 
____________________
(a)    Performance Peer Group represents the list of 20 utility and energy industry companies used in our 2021 Proxy Statement which was filed with the SEC on March 18, 2021.

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 2021.

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.
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ISSUER PURCHASES OF EQUITY SECURITIES

The following table contains monthly information about our acquisitions of equity securities for the three months ended December 31, 2021:
Period
Total Number of Shares Purchased (a)
Average Price Paid per ShareTotal Number of Shares Purchased as Part of Publicly Announced Plans or ProgramsMaximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
October 1, 2021 - October 31, 20211$63.15 — — 
November 1, 2021 - November 30, 202177766.10 — — 
December 1, 2021 - December 31, 20218,68068.40 — — 
Total9,458$68.21 — — 
____________________
(a)    Shares were acquired under the share withholding provisions of the 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 that invests in our communities’ safety, sustainability and growth with a mission of Improving Life with Energy and a vision to be the Energy Partner of Choice. The Company’s core mission— and our primary focus — is to provide safe, reliable and cost-effective electric and natural gas service to 1.3 million utility customers in over 800 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming.

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. The Company conducts its utility operations under the name Black Hills Energy predominantly in rural areas of the Rocky Mountains and Midwestern states. The Company considers itself a domestic electric and natural gas utility company.

The Company has provided energy and served customers for 138 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.

An important component of our strategy involves sustainable operations and supporting the delivered cost of coal for many other utilities. Additionally,Energy Transition. How we operate our plants with high levels of availability as comparedcompany for the social good has never been more important. We are committed to industry benchmarks.

Rate-based generation assets offer several advantages for customerscleaner energy and shareholders, including:

When generating assets are included ina low carbon future, integrating the utility rate baseEnergy Transition 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 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 consumers and investors by lowering the cost of capital; and

Investors are provided a long-term, reasonable, stable return on their investment.

Proactively integrate alternative and renewable energy into our utility energy supply while mitigating customer rate impacts. The energyoverall strategy and utility industries face uncertainty and potential investment opportunities related to existing and potential legislation and regulation intended to reduce GHG emissions and increase the use of renewable and other alternative energy sources. To date, many states have enacted, and others are considering, mandatory renewable energy standards, requiring utilities to meet certain thresholds of renewable energy generation. Some states have either enacted or are considering legislation setting GHG emissions reduction targets. Federal legislation for both 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 provide investment opportunities for our electric utilities, gas utilities and power generation business. These mandates will also likely increase prices for electricity and/or natural gas for our utility customers. As a regulated utilitydecision making. For this important work, we are responsible for providing safe, reliable and affordable sources of energyReady to our customers. Accordingly, we employ a customer-centered strategy for complying with renewable energy standards and GHG emission regulations that balance 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.
Build and maintain strong relationships with wholesale power customers of our utilities and our power generation business. We strive to build strong relationships with other utilities, municipalities and wholesale customers. We believe we will continue to be a primary provider of electricity to wholesale utility customers, who will continue to need products such as capacity and energy to reliably serve their customers. By providing these products under long-term contracts, we help our customers meet their energy needs. We also earn more stable revenues and greater returns for shareholders over the long term than we would by selling energy into more volatile energy spot markets.serve. In addition, relationshipswe are committed to a more sustainable future by better managing our impacts to the planet, whether that we have established with wholesale power customers have developed intois water usage, recycling, biodiversity, or other opportunities. MEAN, MDUimportant 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 City of Gillette, Wyoming were wholesale power customers that are now joint owners in two of our power plants, Wygen I and Wygen III, reducing risk and providing steady revenues.

Vertically integrate businesses that are supportive ofcustomer experience; growing our electric and natural gas utility businesses. While our primarycustomer load; and pursuing operating efficiencies. These areas of focus is on growing our core utilities, we selectively invest in vertically integrated businesses that provide cost effective and efficient fuel and energy to our utilities. We currently own and operate a coal mine and power generation assets that are vertically integrated into and supportive of our electric utilities. These operations are located at our utility generating complexes and are physically integrated into our electric utility operations.

Our surface coal mine is located immediately adjacent to our Gillette energy complex in northeastern Wyoming, where all five of our coal-fired power plants are located. We operate and own 100% or own a majority interest in four ofwill present the five plants; we have a 20% interest in the fifth plant, which is operated by a third party. The coal mine provides low-sulfur coal directly to these power plants via a conveyor belt system, minimizing coal transportation costs. On average, the coal can be delivered to

the adjacent power plants at substantially less than $1.00 per MMBtu, providing very cost competitive fuel to our power plants when compared to other coal-fired and gas-fired power plants.

We have a power generation segment that employs professionalscompany with significant expertise in planning and building power generation facilities, having constructed 19 coal-fired, gas-fired and renewable generation projects since 1995 with aggregate project costs in excess of $2 billion. This group also provides shared services to our electric utilities’ generation facilities, resulting in efficient management of all of the company’s generation assets. In certain states, our electric utilities are required to competitively bid for generation resources needed to serve customers. Generally, our power generation segment submits bids in response to those competitive solicitations. Our generation segment can often realize competitive advantages provided by prior construction expertise, fuel supply advantages and by co-locating new plants at existing sites, reducing infrastructure and operating costs.

Expand utility operations through selective acquisitions of electric and gas utilities. The electric and natural gas utility industries have consolidated significantly over the past decade and continue to consolidate. We have successfully acquired and integrated numerous utility systems since 2005, including two large, transformational acquisitions - the Aquila utility properties in 2008 and SourceGas in 2016. Through these acquisitions, we developed a scalable platform that simplifies the rapid integration of acquired utilities, providing significant benefits to both customers and shareholders. The company targets small to large utilities, including municipal and private utility systems, located primarily in geographies that are near to or contiguous with our existing utility service territories and provide long-term value for both customers and shareholders. In the near-term, we do not expect to pursue large utility acquisitions, particularly given the high valuation multiples realized in recent utility transactions. We will continue to pursue the purchase of small utility systems within or near our geographic footprint, which can be quickly and efficiently integrated into our existing utilities.

Grow our dividend. We are extremely proud of our track record for annual dividend increases for shareholders. In January 2018, we declared a dividend of $0.475 per share, equivalent to an annual dividend rate of $1.90 per share. This annual equivalent rate represents an increase of 5% over the total 2017 dividend of $1.81 per share and the 48th consecutive annual dividend increase. We intend to continue our record of annual dividend increases with a targeted dividend payout ratio of 50% to 60%. This target payout ratio provides the flexibility for greater increases to our dividend during periods of relatively slow earnings growth.

Maintain an investment grade credit rating and ready access to debt and equity capital markets. 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.



Prospective Information

We expect to generate long-term growth through the expansion of integrated utilities and supporting operations. Sustained growth requires continued capital deployment. Our integrated energy portfolio, focused primarily on regulated utilities provides growth opportunities, yet avoids concentrating business risk. We expect much of our growth in the next few years will come from capital deployment opportunities at our utilities and continued focus on improving efficiencies and reducing costs. Although dependent on market conditions, we are confident in our ability to obtain additional financing, as necessary, to continue our growth plans. We remain focused on prudently managing our operations and maintaining our overall liquidity to meet our operating, capital and financing needs as well as executingwe harden our long-term strategic plan.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.


Electric Utilities

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In September 2017, the Mountain West Transmission Group, which includes all
Table of Black Hills electric utilities and seven other electricity providers, formally expressed an interest in joining the Southwest Power Pool (SPP) regional transmission organization. If membership is deemed beneficial, filings with FERC and state public utility commissions would likely occur in mid-2018 with integration into SPP in late 2019.Contents

On January 17, 2017, Colorado Electric received approval from the CPUC on a settlement agreement for its electric resource plan which provides for the addition of 60 megawatts of renewable energy to be in service by 2019. The resource plan was filed on June 3, 2016, to meet requirements under the Colorado Renewable Energy Standard. In the second quarter of 2017, Colorado Electric issued a request for proposals to acquire renewable energy resources to comply with the Colorado Renewable

Energy Standard and presented the results to the CPUC on February 9, 2018. We expect a final decision from the CPUC in the second quarter of 2018 approving, conditioning, modifying or rejecting Colorado Electric’s recommended portfolio.

Retail MWhs sold increased in 2017 primarily due to industrial load growth at Wyoming Electric, which set a new all-time summer peak load of 249 MW in July 2017.

Construction was completed on the 144 mile transmission line connecting the Teckla Substation in northeast Wyoming to the Lange Substation near Rapid City, South Dakota. The first segment of this project connecting Teckla to Osage, WY was placed in service on August 31, 2016. The second segment connecting Osage to Lange was placed in service on May 30, 2017.

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 Customers202120202019
Residential853,908 844,999 831,351 
Commercial84,234 83,135 82,912 
Industrial2,158 2,235 2,208 
Transportation153,929 152,568 149,971 
Total Natural Gas Retail Customers at End of Year1,094,229 1,082,937 1,066,442 

As of December 31,
Retail Customers202120202019
Arkansas180,216 178,281 174,447 
Colorado202,747 197,817 191,950 
Iowa161,905 160,952 159,641 
Kansas117,862 116,973 115,846 
Nebraska298,832 296,778 293,576 
Wyoming132,667 132,136 130,982 
Total Natural Gas Retail Customers at End of Year1,094,229 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 2017, we filed requests for rate reviewsaddition 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 Colorado, drivento 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:
StateWorking Capacity (Mcf)Cushion Gas
(Mcf)		Total Capacity (Mcf)Maximum Daily Withdrawal Capability (Mcfd)
Arkansas9,273,700 12,318,040 21,591,740 196,000 
Colorado2,361,495 6,164,715 8,526,210 30,000 
Wyoming5,733,900 17,145,600 22,879,500 36,000 
Total17,369,095 35,628,355 52,997,450 262,000 

15
The following table summarizes certain information regarding our system infrastructure as of December 31, 2021:

StateIntrastate Gas
Transmission Pipelines
(in line miles)		Gas Distribution
Mains
(in line miles)		Gas Distribution
Service Lines
(in line miles)
Arkansas874 4,972 1,275 
Colorado693 6,990 2,303 
Iowa172 2,863 2,486 
Kansas330 2,980 1,374 
Nebraska1,311 8,443 2,773 
Wyoming1,352 3,532 1,653 
Total4,732 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, madesuch as energy efficiency plan costs and system safety and integrity investments.

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The following table provides regulatory information for each of our natural gas utilities:
SubsidiaryJurisdic-tionAuthorized Rate of Return on EquityAuthorized Return on Rate BaseAuthorized Capital Structure Debt/EquityAuthorized Rate Base (in millions)Effective DateAdditional Regulatory Mechanisms
Arkansas Gas (c)
AR9.61%
6.82% (a)
51%/49%
$451.5 (b)
10/2018GCA, Main Replacement Program, At-Risk Meter Relocation Program, Legislative or Regulatory Mandated Expenditures, EECR, Weather Normalization Adjustment, Billing Determinant Adjustment
Colorado Gas (c)
CO9.20%6.56%50%/50%$303.21/2022GCA, SSIR, EECR/DSM
RMNGCO9.90%6.71%53%/ 47%$118.76/2018SSIR, Liquids/Off-system/Market Center Services Revenue Sharing
Iowa Gas (c)
IA9.60%6.75%50%/50%$300.91/2022GCA, EECR, System Safety and Maintenance Adjustment Rider, Gas Supply Optimization revenue sharing
Kansas Gas (c)
KSGlobal SettlementGlobal SettlementGlobal SettlementGlobal Settlement1/2022GCA, 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)
NE9.50%6.71%50%/50%$504.23/2021GCA, 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)
WY9.40%6.98%50%/50%$354.43/2020GCA, EECR, Rate Base Recovery on Acquisition Adjustment, Wyoming Integrity Rider, Choice Gas Program
____________________
(a)    Arkansas Gas return on recently acquired utilitiesrate base is adjusted to replace, upgraderemove 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 maintainWyoming 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 JurisdictionCost Recovery Mechanisms
DSM/Energy EfficiencyIntegrity AdditionsBad DebtWeather NormalPension RecoveryGas CostRevenue Decoupling
Arkansas Gasþþþþþ
Colorado Gasþþþ
RMNG (a)
þ
Iowa Gasþþþ
Kansas Gasþþþþþ
Nebraska Gasþþþ
Wyoming Gasþþþ
____________________
(a)    RMNG, which is an intrastate transmission pipeline that provides natural gas transmission and distribution pipelines. wholesale services in western Colorado, has an SSIR recovery mechanism. The other cost recovery mechanisms are not applicable to RMNG.

Tariff Filings. See 2017 Results of Operations and Note 132 of the Notes to the 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.
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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 information.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.
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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 TeamAs of December 31, 2021As of December 31, 2020
Total employees2,8843,011
Women in executive leadership positions (a)
30%31%
Gender diversity (women as a % of total employees)26%26%
Represented by a union25%25%
Military veterans14%16%
Ethnic diversity (non-white employees as a % of total)12%11%
For the year ended December 31, 2021For the year ended December 31, 2020
Number of external hires214299
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 rate3%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 Utilities420 
Gas Utilities1,191 
Corporate and Other1,273 
Total2,884 

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.
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UtilityNumber of EmployeesUnion AffiliationExpiration Date of Collective Bargaining Agreement
Colorado Electric94 IBEW Local 667April 15, 2023
South Dakota Electric128 IBEW Local 1250March 31, 2022
Wyoming Electric25 IBEW Local 111June 30, 2024
Total Electric Utilities247 
Iowa Gas132 IBEW Local 204January 31, 2026
Kansas Gas16 Communications Workers of America, AFL-CIO Local 6407December 31, 2024
Nebraska Gas92 IBEW Local 244March 13, 2022
Nebraska Gas140 CWA Local 7476October 30, 2023
Wyoming Gas15 IBEW Local 111June 30, 2024
Wyoming Gas78 CWA Local 7476October 30, 2023
Total Gas Utilities473 
Total720 

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%
____________________
(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 vendors’ information systems, could further add to a full or partial disruption of our operations. 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, or these risks and losses.

In May and July 2021, the TSA issued security directives 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 are currently implementing several of these directives and 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.

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.

Weather conditions, including the impacts of climate change, may cause fluctuation in customer usage.

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, customers’ energy use could increase or decrease. 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 and income 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.
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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, if at all. 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.

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.

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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 the capital markets and the costs and terms of available financing depend on many factors, including changes in our credit ratings, changes in the federal or state regulatory environment affecting energy companies, volatility in commodity or electricity prices and general economic and market conditions.

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.

National and regional economic conditions may cause increased counterparty credit risk, late payments and uncollectible accounts.

A future recession or pandemic, if one occurs, may lead to an increase in late payments or non-payment from retail residential, commercial and industrial utility customers, as well as from our non-utility customers. If late payments and uncollectible accounts increase, earnings and cash flows from our continuing operations may be reduced.

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 the Company may be subject, including liability and losses associated with climate change, wildfire, 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.

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.

PANDEMIC RISK

The ongoing COVID-19 pandemic, including its variants, or any other pandemic and the associated impact on business and economic conditions could negatively affect our business operations, results of operations, financial condition and cash flows.

The scale and scope of the COVID-19 outbreak, the resulting pandemic or any other future pandemic, and the associated impact on the economy and financial markets could adversely affect the Company’s business, results of operations and financial condition. As a provider of essential services, the Company has an obligation to provide electric and natural gas 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.
26

Although the impact of the COVID-19 pandemic and its variants to our 2021 results of operation was not significant, we cannot ultimately predict whether it will have a material impact on our future liquidity, financial condition or results of operations. We also cannot predict the impact of COVID-19 on the health of our employees, our supply chain or our ability to mitigate higher costs associated with managing through the COVID-19 pandemic.

As recovery from the COVID-19 pandemic continues, additional uncertainties have emerged, including the impacts of:
•vaccine mandates and testing requirements on our workforce;
•inflation increasing prices of commodities and materials, outside services, employee costs and interest rates;
•supply chain disruptions on the availability and cost of materials; and
•labor shortages and increased turnover on costs of retaining and attracting employees.

The situation remains fluid and it is difficult to predict with certainty the potential impact of the COVID-19 pandemic, or any other future pandemic, on our financial operating results including earnings, cash flows and 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 59, 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 20 years of experience with the Company.

Brian G. Iverson, age 59, 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 18 years of experience with the Company.

Erik D. Keller, age 58, 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 56, 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 22 years of experience with the Company.

Jennifer C. Landis, age 47, 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 20 years of experience with the Company.

Stuart A. Wevik, age 60, has been Senior Vice President - Utility Operations since August 26, 2019. He served as Group Vice President - Electric Utilities from 2016 to August 2019, Vice President - Utility Operations from 2008 to 2016, Vice President - Operations from 2004 to 2008 and Vice President and General Manager from 2003 to 2004. Mr. Wevik has 36 years of experience with the Company. Mr. Wevik intends to retire on June 1, 2022.
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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, 2022, we had 3,475 common shareholders of record and 60,937 beneficial owners, representing all 50 states, the District of Columbia and 7 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, 2016, 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.

bkh-20211231_g1.jpg

Years ended December 31,
201620172018201920202021
Black Hills Corporation$100.00 $100.77 $108.81 $139.91 $113.21 $134.59 
S&P 500100.00 121.83 116.49 153.17 181.35 233.41 
S&P 500 Utilities100.00 112.11 116.71 147.46 148.18 174.36 
Performance Peer Group (a)
100.00 113.59 119.17 143.70 123.74 140.78 
____________________
(a)    Performance Peer Group represents the list of 20 utility and energy industry companies used in our 2021 Proxy Statement which was filed with the SEC on March 18, 2021.

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 2021.

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.
29

ISSUER PURCHASES OF EQUITY SECURITIES

The following table contains monthly information about our acquisitions of equity securities for the three months ended December 31, 2021:
Period
Total Number of Shares Purchased (a)
Average Price Paid per ShareTotal Number of Shares Purchased as Part of Publicly Announced Plans or ProgramsMaximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
October 1, 2021 - October 31, 20211$63.15 — — 
November 1, 2021 - November 30, 202177766.10 — — 
December 1, 2021 - December 31, 20218,68068.40 — — 
Total9,458$68.21 — — 
____________________
(a)    Shares were acquired under the share withholding provisions of the 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 that invests in our communities’ safety, sustainability and growth with a mission of Improving Life with Energy and a vision to be the Energy Partner of Choice. The Company’s core mission— and our primary focus — is to provide safe, reliable and cost-effective electric and natural gas service to 1.3 million utility customers in over 800 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming.

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. The Company conducts its utility operations under the name Black Hills Energy predominantly in rural areas of the Rocky Mountains and Midwestern states. The Company considers itself a domestic electric and natural gas utility company.

The Company has provided energy and served customers for 138 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.

An important 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. For this important work, we are Ready to serve. 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 1,481.5 MW of generation capacity and 8,900 miles of transmission and distribution lines and our Gas Utilities own and operate 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 285-mile, multi-phase transmission expansion project will serve the growing needs of customers enhancing the resiliency of its overall electric system and expanding access to power markets and renewable energy resources. The project will enable Wyoming Electric to maintain top-quartile reliability and support further economic growth in the Cheyenne area. Wyoming Electric plans to file an application with the WPSC seeking approval for the project in the first quarter of 2022. Following approval, construction would commence in early 2023.

Our Gas Utilities investedutilize 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 networksystems and related technology such as advanced meteringcontinue to replace aging infrastructure through programs that prioritize safety and mobile data terminals. We continually monitorreliability for our investmentscustomers. Our Gas Utilities are authorized to use system safety, integrity and costs of operations in all states to determine the appropriateness of additionalreplacement 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, 2021, we estimate our five-year capital investment to be approximately $3.2 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 2021 and forecasted capital expenditures for the next five years from 2022 through 2026 are as follows (in millions):

Actual (a)
Forecasted
Capital Expenditures By Segment :
202120222023202420252026
(in millions)
Electric Utilities$286 $239 $205 $285 $231 $155 
Gas Utilities383 363 383 386 349 346 
Corporate and Other11 9 12 13 13 13 
Incremental projects (b)
— — — — 60 140 
Total$680 $611 $600 $684 $653 $654 
____________________
(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 other rate filings. Asnon-regulated assets within our Electric Utilities segment. However, we believe that generation assets that are rate-based provide long-term benefits to customers. In the fourth quarter of 2021, we revised our operating segments to align with our vertically integrated business model for our Electric Utilities. Our power generation and mining businesses, which were previously presented as separate operating segments, are now part of our growthvertically integrated Electric Utilities segment.

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Our power production strategy focuses on low-cost construction and efficient operation of our generating facilities. Our low power production costs result from a variety of factors including low fuel costs (operations located near energy hubs), efficiency in converting fuel into energy and low per unit operating and maintenance costs. In addition, we operate our plants with high levels of Availability as compared to industry benchmarks.

Rate Base Generation: We continue to lookbelieve 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 opportunitiescustomers 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 contains a power generation business that owns non-regulated generating facilities that are contracted through long-term power purchase municipalagreements with our electric utilities. Our power generation business has an experienced staff with significant expertise in planning, building and privately-owned gasoperating 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. This 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 distribution systemsoperating costs. All power plants within or nearbythis business, except Top of Iowa, are contracted to our service territories.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.


Mining

Production fromGeneration 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 Mining segment primarily serves mine-mouthresource rich areas of Colorado and Wyoming, natural gas supply to fuel our gas-fired generation can be sourced at competitive prices. Our only 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 select regional customers with long-term fuel needs. Total annual production wasown 20% of the fifth power plant. The small coal mine provides approximately 4.23.5 million tons for 2017. Mining operations movedof low-sulfur coal directly to an area with higher overburden ratios in 2017, which increased miningthese power plants via a conveyor belt system, minimizing transportation costs. However, lowerOn average, the fuel costs and efficiencies in executingcan be delivered to the adjacent power plants at less than $1.00 per MMBtu, providing very cost competitive fuel to our mine plan partially offsetpower plants when compared to alternatives. Nearly all the mine’s production is sold to these costs. Our stripping ratio at December 31, 2017 was 2.16 and we expect stripping ratios in 2018 to be approximately 2.15 as the areas planned for mining contain comparable overburden.

Our strategy is to sell the majority of our coal production to on-site mine-mouth generation facilities under long-term supply contracts. Approximately one-half of our coalproduction is sold under cost-plus contracts with affiliates. HistoricallyA 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 limited off-site salesutility energy supply while mitigating customer rate impacts. In November 2020, we announced clean energy goals to reduce GHG emissions intensity for our Electric Utilities of 40% by 2030 and 70% by 2040 and achieve GHG reductions of 50% by 2035 for our Gas Utilities. Our goals are based on existing technology and computed from 2005 baseline levels of GHG emissions intensity for our electric operations and natural gas distribution system. Since 2005, we have beenreduced GHG emissions intensity from our Gas Utilities by more than 33% and achieved a 30% reduction from our Electric Utilities (an additional 5% reduction since announcing our goal in 2020 for our Electric Utilities). Additionally, our Electric Utilities have reduced nitrogen oxide and sulfur dioxide emissions by more than 75% since 2005. Our electric utility in Colorado has achieved a nearly 50% reduction in GHG emissions since 2005 and is on track to consumers within a close proximityreach 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 mine,customers. This keeps our customers at the forefront of our decision-making, which is central to our values.

More of our customers, particularly our larger customers, are demanding cleaner sources of energy to meet their sustainability goals. In addition, there is more interest from consumers, regulators and legislators to increase the use of renewable and other alternative energy sources. To support this interest:

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•We created the Renewable Ready program for South Dakota and Wyoming 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, on November 30, 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 the near-term planning period through 2026 propose the addition of 100 MW of renewable generation, the conversion of Neil Simpson II to natural gas in 2025 and consideration of up to 20 MW of battery storage.

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.

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, crypto miners and other blockchain opportunities; exploring energy markets such as RTOs; and expanding our transmission capabilities. As an example, we have supported enabling legislation in Wyoming for the growing blockchain and digital currency businesses while implementing our own Blockchain Interruptible Service Tariff to serve these customers. We are also re-focusing on our product and services offerings to our natural gas customers.

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

•Electric Vehicles (EV): 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 will investigate behind-the-meter solutions for customers. In January 2022, the CPUC approved a transportation electrification plan for Colorado Electric including off-site sales contracts served by truck.the implementation of EV and charger rebates and EV rates.

•Renewable Natural Gas (RNG): Our teams are developing RNG/carbon offset offerings for our retail customers, evaluating multiple RNG investment opportunities and exploring value generation with our natural gas storage assets. We also continue to expand our RNG interconnections, with several projects actively injecting RNG into our natural gas system.

Execute disciplined capital allocation and explore small strategic opportunities. We are planning a disciplined capital investment program of approximately $600 million annually over the next two years 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. 2021 represented our 51st consecutive year of increasing dividends. In January 2022, our Board of Directors declared a quarterly dividend of $0.595 per share, equivalent to an annual dividend of $2.38 per share. We intend to continue our record of annual dividend increases with a targeted dividend payout ratio of 50% to 60%.

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

Winter Storm Uri

In February 2021, a prolonged period of historic cold temperatures across the central United States covered all of our Utilities’ service territories, 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 of Winter Storm Uri, we incurred significant incremental natural gas and fuel costs.

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. Proceeds from the August 26, 2021 debt transaction were used to repay amounts outstanding under this term loan. See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further information.

During the second quarter, our Utilities submitted cost recovery applications with the utility commissions in our state jurisdictions to recover incremental costs associated with Winter Storm Uri. To date, several of our Utilities have received interim or final Commission Orders and have begun recovering costs from customers. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further information on our regulatory activity.

COVID-19 Pandemic

For the year ended December 31, 2021, we did not experience significant impacts to our financial results, liquidity or operational activities due to COVID-19. We continue to pursuemonitor loads, customers’ ability to pay, the potential for supply chain disruption or inflation that may impact our capital and maintenance project plans, the availability of third-party resources to execute our business plans and the capital markets to ensure we have the liquidity necessary to support our financial needs. State Orders lifting temporarily suspended disconnections have been issued in all of our jurisdictions.

As we look forward, our operating results could be affected by COVID-19 as discussed in detail in our Risk Factors.

Business Segment Highlights and Corporate Activity

Electric Utilities

•On January 26, 2022, Colorado Electric agreed to join SPP’s Western Energy Imbalance Service Market. Colorado Electric, PRPA, and the Colorado subsidiary of Xcel Energy Inc. will join the market in April 2023 and will continue to study long-term solutions for joining or developing an organized wholesale market. The expansion allows the utilities to participate in a real-time market to dispatch energy at lower costs.

•On January 5, 2022, South Dakota Electric and Wyoming Electric set new opportunitieswinter peak loads. This is the fourth new winter peak for Wyoming Electric since 2015. Wyoming Electric’s new winter peak load of 253 MW surpasses the previous peak of 247 MW set in December 2019. South Dakota Electric’s new winter peak of 327 MW surpasses the previous winter peak of 326 MW set in February 2021.

•In November 2021, Wyoming Electric announced its Ready Wyoming electric transmission expansion initiative. See Key Elements of our Business Strategy above for further information.

•On October 5, 2021, our Electric Utilities and several other utilities in the western United States formed the Western Markets Exploratory Group to research the potential for an organized wholesale market in the western interconnect, including expanding transmission systems and other grid-related services. The group plans to identify market solutions that can help achieve carbon reduction goals while supporting reliable, cost-effective services for customers.

•On September 19, 2021, Wygen I experienced an unplanned outage that continued until mid-December 2021. For the year ended December 31, 2021, the outage had an $11 million negative impact to Operating income. We are currently assessing insurance recovery opportunities.

•On August 24, 2021, Wyoming Electric issued a request for proposals under its Blockchain Interruptible Service tariff. We have narrowed the bidder’s list and selected finalists for contract negotiations.

•On July 28, 2021, Wyoming Electric set a new all-time and summer peak load of 274 MW, exceeding the previous peak of 271 MW set in July 2020.

•On July 27, 2021, South Dakota Electric set a new all-time and summer peak load of 397 MW, exceeding the previous peak of 378 MW set in August 2020.

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•On June 30, 2021, South Dakota Electric and Wyoming Electric submitted an IRP to the SDPUC and WPSC. See Key Elements of our coal despite limitations inherentBusiness Strategy above for further information.

•On February 19, 2021, Colorado Electric entered into a PPA with TC Colorado Solar, LLC (TC Solar) to transportingpurchase up to 200 MW of renewable energy upon construction of a new solar facility, to be owned by TC Solar. On January 31, 2022, TC Solar provided termination notice of the PPA to Colorado Electric. Colorado Electric has disputed TC Solar’s right to termination and pursuant to the agreement, has initiated discussions with TC Solar.

Gas Utilities

•See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for recent regulatory activity for our lower-heat content coal.Gas Utilities in Arkansas, Colorado, Iowa, Kansas and Nebraska.


Corporate and Other


We utilized favorable short-term borrowings•On August 26, 2021, we completed a public debt offering which consisted of $600 million, 1.037% 3-year senior unsecured notes due August 23, 2024. The proceeds from our CP programthe offering were used to pay down $100 million on a Corporaterepay amounts outstanding under our term loan due in 2019 with principal payments of $50 million paid in May and an additional $50 million paid in July. In August 2017, we renewed the ATM equity offering program, which reset the sizeentered into on February 24, 2021. See Note 8 of the programNotes to an aggregate valueConsolidated Financial Statements in this Annual Report on Form 10-K for further information.

•On July 19, 2021, we amended and restated our corporate Revolving Credit Facility. See Note 8 of upthe Notes to $300 million. See additional detailConsolidated Financial Statements in the 2017 Corporate highlights.this Annual Report on Form 10-K for further information.






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Results of Operations


Executive SummaryOur discussion and Overviewanalysis for the year ended December 31, 2021 compared to 2020 as well as discussion and analysis of the results of operations for the year ended December 31, 2020 compared to 2019, is included herein. For further discussion and analysis that remains unchanged for the year ended December 31, 2020 compared to 2019, 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, 2020, which was filed with the SEC on February 26, 2021.

 For the Years Ended December 31,
 2017Variance2016Variance2015
 (in thousands)
Revenue      
Revenue$1,810,447
$143,412
$1,667,035
$280,036
$1,386,999
Intercompany eliminations(130,181)(2,062)(128,119)(2,442)(125,677)
 $1,680,266
$141,350
$1,538,916
$277,594
$1,261,322
      
Income from continuing operations available for common stock (a)
     
Electric Utilities 
$110,082
$24,255
$85,827
$8,248
$77,579
Gas Utilities (b)
65,795
6,171
59,624
20,318
39,306
Power Generation (c)
46,479
20,549
25,930
(6,720)32,650
Mining14,386
4,333
10,053
(1,817)11,870
 236,742
55,308
181,434
20,029
161,405
      
Corporate and Other (a) (b) (d) (e)
(42,609)1,693
(44,302)(24,445)(19,857)
      
Income from continuing operations194,133
57,001
137,132
(4,416)141,548
      
(Loss) from discontinued operations, net of tax (f) (g)
(17,099)47,063
(64,162)109,497
(173,659)
Net income (loss) available for common stock$177,034
$104,064
$72,970
$105,081
$(32,111)
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.
______________
(a)Income from continuing operations available for common stock for 2017 includes a net tax benefit of $7.6 million from the revaluation of deferred tax balances due to a decrease in the statutory Federal income tax rate resulting from the TCJA. This benefit’s impact to our operating segments and Corporate and Other was: Electric Utilities - $23 million tax benefit; Gas Utilities - $6.8 million tax expense; Power Generation - $24 million tax benefit; Mining - $2.7 million tax benefit; Corporate and Other - $35 million tax expense which includes $28 million of tax expense from the revaluation of Corporate deferred taxes, as well as an additional $7.0 million of tax expense from the revaluation of deferred taxes that were originally recorded to AOCI.
(b)Income from continuing operations available for common stock for 2017 includes a $4.1 million tax benefit from a true-up to the filed 2016 SourceGas tax returns relating to the SourceGas Acquisition.
(c)
On April 14, 2016, BHEG sold a 49.9% interest in Black Hills Colorado IPP. Income from continuing operations available for common stock for 2017 and 2016 was reduced by $14 million and $9.6 million, respectively, attributable to this noncontrolling interest.
(d)
Income from continuing operations available for common stock for 2017, 2016 and 2015include incremental SourceGas Acquisition costs, after-tax of $2.8 million, $30 million and $6.7 million, respectively and after-tax internal labor costs attributable to the SourceGas Acquisition of $0.5 million, $9.1 million and $3.0 million, respectively that otherwise would have been charged to other business segments.
(e)Income from continuing operations available for common stock for 2016 included tax benefits of approximately $4.4 million as a result of the re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016.
(f)
Loss from discontinued operations in 2017, 2016 and 2015 included non-cash after-tax impairments of crude oil and natural gas properties of $13 million, $67 million and $160 million, respectively. See Note 21 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
(g)Loss from discontinued operations in 2016 included a tax benefit of approximately $5.8 million recognized from additional percentage depletion deductions that are being claimed with respect to our oil and gas properties involving prior years.


The following business group and segmentSegment information does not include intercompany eliminations and all amounts are presented on a pre-tax basis unless otherwise indicated. Per share information references diluted shares unless otherwise noted.Minor differences in amounts may result due to rounding.



Consolidated Summary and Overview

For the Years Ended December 31,
202120202019
(in thousands, except per share amounts)
Operating income (loss):
Electric Utilities$202,676 $210,974 $217,677 
Gas Utilities211,157 215,889 189,971 
Corporate and Other(4,404)1,440 (1,606)
Operating Income409,429 428,303 406,042 
Interest expense, net(152,404)(143,470)(137,659)
Impairment of investment— (6,859)(19,741)
Other income (expense), net1,404 (2,293)(5,740)
Income tax (expense)(7,169)(32,918)(29,580)
Net income251,260 242,763 213,322 
Net income attributable to non-controlling interest(14,516)(15,155)(14,012)
Net income available for common stock$236,744 $227,608 $199,310 
Total earnings per share of common stock, Diluted$3.74 $3.65 $3.28 
2017

2021 Compared to 20162020


Income from continuing operations available for common stock was $194 million, or $3.52 per diluted share in 2017 compared to $137 million, or $2.57 per diluted share in 2016. The variance to the prior year wasincluded the following:

•Electric Utilities’ operating income decreased $8.3 million primarily due to:

Corporate and Other, excluding tax reform impacts, decreased by approximately $37 million compared to the same period in the prior year driven primarily by a $27 million reduction of after-tax external acquisition and transition costs, a reduction of approximately $8.6 million of internal labor attributedColorado Electric’s TCJA-related bill credits to the SourceGas Acquisition and lower reallocated discontinued operation expenses of approximately $2.9 million, partiallycustomers (which is offset by a $4.4 millionreduced tax benefit in 2016;
Gas Utilities’ earnings, excluding tax reformexpense), unfavorable impacts increased approximately $13 million, with a full year of earnings from our acquired SourceGas utilities compared to approximately 10.5 months in 2016,an unplanned outage at Wygen I and a $4.1 million tax benefit recognized in 2017;
We recorded a net tax benefit of approximately $8 millionhigher depreciation as a result of the revaluation of deferred tax balances dueadditional plant placed in service, partially offset by increased power marketing and wholesale revenues, increased rider revenues, increased commercial and industrial demand, a prior year expense related to the decrease in the statutory Federal income tax rate as a resultearly retirement of the TCJA. This benefit’s impact to our operating segmentscertain non-regulated generation assets, residential customer growth and Corporateincreased usage, and Other was:
◦Electric Utilities - $23 million tax benefit
◦Gas Utilities - $6.8 million tax expense
◦Power Generation - $24 million tax benefit
◦Mining - $2.7 million tax benefit
◦Corporate and Other - $35 million tax expense consisting of $28 million of tax expense from the revaluation of Corporate deferred tax balances and $7 million of tax expense from the revaluation of deferred taxes that were originally recorded to AOCI.
Electric Utilities’ earnings, excluding tax reform impacts, were comparable to the prior year reflecting an increase from returns on prior year generation investments, offset by higher employee costs and higher generation maintenance expenses;COVID-19 impacts;
Earnings at our Power Generation segment, excluding tax reform impacts,•Gas Utilities’ operating income decreased $3.5$4.7 million primarily due to an increase in net income attributable to noncontrolling interests, reflecting a full year in 2017 compared to approximately 8.5 months in 2016; and
Earnings at our Mining segment, excluding tax reform impacts, increased approximately $1.6 million due to an increase in tons sold as a result of an extended outage in the prior year;.

Net income (loss) available for common stock was $177 million, or $3.21 per diluted share in 2017, compared to $73 million, or $1.37 per share in 2016. BHEP has been reclassified and is included in discontinued operations. (Loss)Winter Storm Uri costs incurred by Black Hills Energy Services, lower heating demand from discontinued operations was $(17) million or $(0.31) per diluted share in 2017 compared to $(64) million or $(1.20) per diluted share in 2016. Discontinued operations in 2017 included an after-tax fair value impairment of assets of approximately $13 million compared to 2016 which included non-cash after-tax oil and gas property impairment charges of $67 million. Also included in 2016 discontinued operations was a $5.8 million tax benefit recognized from additional percentage depletion deductions that were claimed with respect to our oil and gas properties involving prior years.

2017 Overview of Business Segments and Corporate Activity

Electric Utilities

In our Electric Utilities service territories, wintermilder weather was mostly comparable to the prior year and the summer was milder in 2017 compared to the prior year. Heating degree days in 2017 were 11% lower than normal compared to 13% lower than normal in 2016. Cooling degree days for the full year of 2017 were 14% higher than normal compared to 26% higher than normal in 2016.

On January 17, 2017, Colorado Electric received approval from the CPUC on a settlement agreement for its electric resource plan which provides for the addition of 60 megawatts of renewable energy to be in service by 2019. The resource plan was filed June 3, 2016, to meet requirements under the Colorado Renewable Energy Standard. In the second quarter of 2017, Colorado Electric issued a request for proposals to acquire renewable energy resources to comply with the Colorado Renewable Energy Standard and presented the results to the CPUC on February 9, 2018. We expect a final decision from the CPUC in the second quarter of 2018 approving, conditioning, modifying or rejecting Colorado Electric’s recommended portfolio.



On January 9, 2017, we filed an application with the CPUC for rehearing, reargument or reconsideration of the Commission’s December 19, 2016 decision to increase annual revenue by $1.2 million. This application was denied by the CPUC on June 9, 2017. We subsequently filed an appeal of this decision with Denver County District Court on July 10, 2017. On October 4, 2017, the Company filed an Opening Brief. The Company filed a Reply Brief on November 22, 2017.  The matter is pending.

Construction was completed on the 144 mile transmission line connecting the Teckla Substation in northeast Wyoming to the Lange Substation near Rapid City, South Dakota. The first segment of this project connecting Teckla to Osage, WY was placed in service on August 31, 2016. The second segment connecting Osage to Lange was placed in service on May 30, 2017.

On July 19, 2017, Wyoming Electric set a new summer load peak of 249 MW, exceeding the previous summer peak of 236 MW set in July 2016.

Gas Utilities

Our service territories reported comparable year-over-year winter weather as measured by heating degree days compared to the 30-year average. Combined heating degree days for the full year in 2017 were 10% less than normal compared to 11% less than normal in the same period in 2016.

The Gas Utilities also experienced cooler summer temperatures and higher precipitation levels during the third quarter of 2017 compared to the same period in 2016, which reduced the irrigation load delivered to agricultural customers, primarily in our Nebraska service territory.

On December 15, 2017, Arkansas Gas filed a rate review application with the APSC requesting an annual increase in revenue of approximately $30 million. The annual increase is based on a return on equity of 10.2% and a capital structure of 45.3% debt and 54.7% equity. This rate review was driven by approximately $160 million of investments made since 2016 to replace, upgrade and maintain Arkansas Gas’ approximately 5,500 miles of natural gas transmission and distribution pipelines. If approved, new rates would be implemented(primarily in the fourth quarter of 2018. We are reviewing the impact of tax reform as it applies2021), Nebraska Gas TCJA-related bill credits to the filing.customers and higher operating expenses partially offset by new rates and customer growth;

On November 17, 2017, Wyoming Gas requested rate review application with the WPSC requesting an annual increase in revenue of approximately $1.4•Corporate and Other expenses increased $5.8 million for natural gas system improvements supporting its Northwest Wyoming customers. The annual increase is based on a return on equity of 10.2% and a capital structure of 46% debt and 54% equity. This rate review wasprimarily due to higher employee costs driven by approximately $6a prior year favorable true-up;
•Interest expense increased $8.9 million of investments made since 2015primarily due to replace, upgrade and maintain approximately 620 miles of natural gas transmission and distribution pipelines. If approved, new rates would be implementedhigher debt balances partially offset by lower rates;
•A prior year $6.9 million pre-tax non-cash impairment in mid-2018. We are reviewing the impact of tax reform as it applies to the filing.

On October 3, 2017, RMNG filed a rate review application with the CPUC requesting an annual increase in revenue of $2.2 million and an extension of SSIR to recover costs from 2018 through 2022. The annual increase is based on a return on equity of 12.25% and a capital structure of 53.37% debt and 46.63% equity. This rate review was driven by the impending expiration of the SSIR on May 31, 2018; this application requests a continuation of the SSIR through 2022. We are reviewing the impact of tax reform as it applies to the filing.

Corporate Activities

On August 4, 2017, we renewed the ATM equity offering program, which reset the size of the program to an aggregate value of up to $300 million. The renewed program, which allows us to sell shares2020 of our common stock, is the same as the prior year program other than the aggregate value increased from $200 million to $300 million. We did not issue any common shares during the twelve months ended December 31, 2017.

On December 12, 2017, Moody’s affirmed Black Hills’ credit rating at Baa2 withinvestment in equity securities of a Stable outlook.

On October 4, 2017, Fitch affirmed Black Hills’ credit rating at BBB+ rating and maintained a Stable outlook.

On July 21, 2017, S&P affirmed Black Hills’ credit rating at BBB rating and maintained a Stable outlook.





Discontinued Operations

On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. As of February 23, 2018, we have either closed transactions or signed contracts to sell more than 90 percent of ourprivately held oil and gas properties. We have executed agreementscompany;
•Other income increased $3.7 million primarily due to sell alllower non-service pension costs driven by a lower discount rate, lower costs for our operated propertiesnon-qualified benefit plans which were driven by market performance and have only non-operated assetsrecognition of death benefits from Company-owned life insurance; and
36
•Income tax expense decreased $26 million primarily due to lower pre-tax income and a lower effective tax rate driven primarily by tax benefits from Colorado Electric and Nebraska Gas TCJA-related bill credits (which is offset by reduced revenue), flow-through tax benefits related to repairs and gain deferral and increased tax benefits from federal production tax credits associated with minimal value left to divest. We plan to conclude the sale of all of our remaining assets by mid-year 2018. The results of our Oil and Gas segment are reflected in discontinued operations, other than certain general and administrative and interest costs which have been reallocated to our other segments. Oil and Gas segment assets and liabilities are classified as held for sale.new wind assets.


20162020 Compared to 20152019


Income from continuing operations available for common stock was $137 million, or $2.57 per diluted share in 2016, compared to $142 million, or $3.12 per diluted share in 2015. The variance to the prior year was primarily due to:included the following:


higher earnings at our•COVID-19 related impacts to consolidated results included $3.6 million of lower Electric Utilities of $8.2 millionand Gas Utility margin driven primarily by returnslower volumes and waived customer late payment fees, $2.6 million of costs due to sequestration of essential employees and $3.3 million of additional bad debt expense which were partially offset by $3.8 million of lower travel, training, and outside services related expenses;
•Electric Utilities’ operating income decreased $6.7 million due to higher depreciation and amortization expense as a result of additional plant placed in service including new wind assets, expense from the early retirement of certain non-regulated assets, lower commercial and industrial demand and COVID-19 impacts partially offset by increased revenue from our non-regulated power generation and mining businesses, benefits from the release of TCJA revenue reserves and increased rider revenues;
•Gas Utilities’ operating income increased $26 million primarily due to new customer rates in Wyoming and Nebraska and increased rider revenues, customer growth, mark-to-market gains on generation investments;non-utility natural gas commodity contracts and a 2019 amortization of excess deferred income taxes partially offset by higher depreciation and amortization expense as a result of additional plant placed in service, COVID-19 impacts and unfavorable weather;
higher earnings at•Corporate and Other expenses decreased $3.0 million primarily due to an unallocated favorable true-up of employee costs;
•A $6.9 million pre-tax non-cash impairment in 2020 of our Gas Utilitiesinvestment in equity securities of approximatelya privately held oil and gas company compared to a similar $20 million which include earningsimpairment in 2019;
•Interest expense increased $5.8 million primarily due to higher debt balances partially offset by lower rates;
•Other expense decreased $3.4 million due to the 2019 expensing of $15 million from our acquired SourceGas utilities since the acquisition date of February 12, 2016;
tax benefits of approximately $5.1 million from the re-measurement of uncertain tax positions’ liability predicated on an agreement reached with IRS Appeals;
Increased corporate expenses which included approximately $30$5.4 million of after-tax incremental acquisition and transitiondevelopment costs related to SourceGas;projects we no longer intend to construct partially offset by increased pension non-service costs in 2020; and
Lower earnings at our Power Generation segment•Income tax expense increased $3.3 million primarily due to nethigher pre-tax income attributable to noncontrolling interests of $9.6 million;
Lower earnings at our Mining segment due to an extended 2016 outage at the Wyodak plant.

Net income (loss) available for common stock was $73 million, or $1.37 per diluted share in 2016, compared to $(32) million or $(0.71) per diluted share in 2015. BHEP has been reclassified and is included in discontinued operations. (Loss) from discontinued operations was $(64) million or $(1.20) per diluted share in 2016 compared to $(174) million or $(3.83) per diluted share. Discontinued operations in 2016 included non-cash after-tax oil and gas property impairment charges of $67 million compared to non-cash after-tax ceiling test impairments of our oil and gas properties of $158 million in 2015.

2016 Overview of Business Segments and Corporate Activity

Electric Utilities

In our Electric Utilities service territories, mild winter weather in 2016 partially offset by a hotter than normal summer. Heating degree days were 2% lower than the prior year and 13% lower than normal. Offsetting this decrease was weather related demand during the peak summer months. Cooling degree days for the full year of 2016 were 9% higher than the same period in the prior year and 26% higher than normal.effective tax rate.


On December 19, 2016, Colorado Electric received approval from the CPUC to increase its annual revenues by $1.2 million to recover investments in a $63 million, 40 MW natural gas-fired combustion turbine. This turbine was completed in the fourth quarter of 2016, achieving commercial operation on December 29, 2016. The approval allowed a return on rate base of 6.02% for this turbine, with a 9.37% return on equity and a capital structure of 67.34% debt and 32.66% equity. Whereas, an authorized return on rate base of 7.4% was received for the remaining system investments, with a return on equity of 9.37% and an approved capital structure of 47.6% debt and 52.4% equity.
Construction riders related to the project increased gross margins by approximately $5.1 million for the year ended December 31, 2016.

On November 8, 2016, Colorado Electric completed the purchase of Peak View, a $109 million, 60 MW Wind Project located near Colorado Electric's Busch Ranch Wind Farm. Peak View achieved commercial operation on November 7, 2016 and was purchased through progress payments throughout 2016 under a commission approved third-party build- transfer and settlement agreement. This renewable energy project was originally submitted in response to Colorado Electric's all-source generation request on May 5, 2014. The Commission’s settlement agreement provides for recovery of the costs of the project through Colorado Electric’s Electric Cost Adjustments, Renewable Energy Standard Surcharge and Transmission Cost Adjustment for 10 years, after which Colorado Electric can propose base rate recovery.



During the first quarter of 2016, South Dakota Electric commenced construction of the $54 million, 230-kV, 144 mile-long transmission line that connects the Teckla Substation in northeast Wyoming to the Lange Substation near Rapid City, South Dakota. Recovery is concurrent through the FERC transmission tariff. The first segment of this project connecting Teckla to Osage, WY was placed in service on August 31, 2016. The second segment connecting Osage to Lange was placed in service in May of 2017.

Gas Utilities

On February 12, 2016, Black Hills Utility Holdings acquired SourceGas Holdings, LLC pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in long-term debt at closing. See additional information below under Corporate activities.

Gas Utilities were unfavorably impacted by milder weather in 2016 compared to 2015. Our service territories reported warmer than normal winter weather as measured by heating degree days, compared to the 30-year average, and compared to 2015. Heating degree days for the full year in 2016 were 11% less than normal and 1% less than the same period in 2015.

Power Generation

Black Hills Colorado IPP owns and operates a 200 MW, combined cycle natural gas generating facility located in Pueblo, Colorado. On April 14, 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million. FERC approval of the sale was received on March 29, 2016. Proceeds from the sale were used to pay down short-term debt. Black Hills Electric Generation continues to be the majority owner and operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric.

Corporate Activities

In 2016, we implemented a $750 million, unsecured CP Program that is backstopped by our Revolving Credit Facility, we amended and restated our corporate Revolving Credit Facility to increase total commitments to $750 million from $500 million and extended the term through August 9, 2021 and we entered into a new $500 million term loan expiring August 9, 2019. We completed the permanent financing for the SourceGas Acquisition. In addition to the net proceeds of $536 million from our November 2015 equity issuances, we completed the Acquisition financing with $546 million of net proceeds from our January 2016 debt offering. We also refinanced the long-term debt assumed with the SourceGas Acquisition primarily through $693 million of net proceeds from our August 19, 2016 debt offerings. In addition to our debt refinancings, we issued 1.97 million shares of common stock for approximately $119 million through our ATM equity offering program, and sold a 49.9% noncontrolling interest in Black Hills Colorado IPP for $216 million. On June 7, 2016, we issued a $29 million, declining balance five-year term loan maturing June 7, 2021, to finance the early termination of a gas supply agreement. See Footnotes 6 and 7 of the Notes to the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional information relating to our long-term debt and notes payable.

On December 9, 2016, Moody’s issued a Baa2 rating with a Stable outlook, which reflects the higher debt leverage resulting from the incremental debt used to fund the SourceGas Acquisition.

During the first quarter of 2016, we reached an agreement in principle with IRS Appeals with respect to our liability for unrecognized tax benefits attributable to the like-kind exchange effectuated in connection with the 2008 IPP Transaction and the 2008 Aquila Transaction. This agreement resulted in a tax benefit of approximately $5.1 million in the first quarter of 2016. See Note 15 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional details on this agreement.

On February 12, 2016, Black Hills Utility Holdings acquired SourceGas Holdings, LLC pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in long-term debt at closing.

On February 12, 2016, S&P affirmed the BHC credit rating of BBB and maintained a stable outlook after our acquisition of SourceGas, reflecting their expectation that management will continue to focus on the core utility operations while maintaining an excellent business risk profile following the acquisition.



On February 12, 2016, Fitch affirmed the BHC credit rating of BBB+ and maintained a negative outlook after our acquisition of SourceGas, which reflects the initial increased leverage associated with the SourceGas Acquisition.

On January 20, 2016, we executed a 10-year, $150 million notional, forward starting pay fixed interest rate swap at an all-in interest rate of 2.09%, and on October 2, 2015, we executed a 10-year, $250 million notional forward starting pay fixed interest rate swap at an all-in rate of 2.29%, to hedge the risks of interest rate movement between the hedge dates and pricing date for long-term debt refinancings occurring in August 2016. On August 19, 2016, we settled and terminated these interest rate swaps for a loss of $29 million. The loss recorded in AOCI is being amortized over the 10-year life of the associated debt.

Segment Operating Results


A discussion of operating results from our business segments follows.


All amounts are presented on a pre-tax basis unless otherwise indicated.


Non-GAAP Financial MeasureGas 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 Customers202120202019
Residential853,908 844,999 831,351 
Commercial84,234 83,135 82,912 
Industrial2,158 2,235 2,208 
Transportation153,929 152,568 149,971 
Total Natural Gas Retail Customers at End of Year1,094,229 1,082,937 1,066,442 

As of December 31,
Retail Customers202120202019
Arkansas180,216 178,281 174,447 
Colorado202,747 197,817 191,950 
Iowa161,905 160,952 159,641 
Kansas117,862 116,973 115,846 
Nebraska298,832 296,778 293,576 
Wyoming132,667 132,136 130,982 
Total Natural Gas Retail Customers at End of Year1,094,229 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 discussion includestable summarizes certain information regarding our company-owned regulated underground gas storage facilities as of December 31, 2021:
StateWorking Capacity (Mcf)Cushion Gas
(Mcf)		Total Capacity (Mcf)Maximum Daily Withdrawal Capability (Mcfd)
Arkansas9,273,700 12,318,040 21,591,740 196,000 
Colorado2,361,495 6,164,715 8,526,210 30,000 
Wyoming5,733,900 17,145,600 22,879,500 36,000 
Total17,369,095 35,628,355 52,997,450 262,000 

15
The following table summarizes certain information regarding our system infrastructure as of December 31, 2021:

StateIntrastate Gas
Transmission Pipelines
(in line miles)		Gas Distribution
Mains
(in line miles)		Gas Distribution
Service Lines
(in line miles)
Arkansas874 4,972 1,275 
Colorado693 6,990 2,303 
Iowa172 2,863 2,486 
Kansas330 2,980 1,374 
Nebraska1,311 8,443 2,773 
Wyoming1,352 3,532 1,653 
Total4,732 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:
SubsidiaryJurisdic-tionAuthorized Rate of Return on EquityAuthorized Return on Rate BaseAuthorized Capital Structure Debt/EquityAuthorized Rate Base (in millions)Effective DateAdditional Regulatory Mechanisms
Arkansas Gas (c)
AR9.61%
6.82% (a)
51%/49%
$451.5 (b)
10/2018GCA, Main Replacement Program, At-Risk Meter Relocation Program, Legislative or Regulatory Mandated Expenditures, EECR, Weather Normalization Adjustment, Billing Determinant Adjustment
Colorado Gas (c)
CO9.20%6.56%50%/50%$303.21/2022GCA, SSIR, EECR/DSM
RMNGCO9.90%6.71%53%/ 47%$118.76/2018SSIR, Liquids/Off-system/Market Center Services Revenue Sharing
Iowa Gas (c)
IA9.60%6.75%50%/50%$300.91/2022GCA, EECR, System Safety and Maintenance Adjustment Rider, Gas Supply Optimization revenue sharing
Kansas Gas (c)
KSGlobal SettlementGlobal SettlementGlobal SettlementGlobal Settlement1/2022GCA, 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)
NE9.50%6.71%50%/50%$504.23/2021GCA, 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)
WY9.40%6.98%50%/50%$354.43/2020GCA, 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 JurisdictionCost Recovery Mechanisms
DSM/Energy EfficiencyIntegrity AdditionsBad DebtWeather NormalPension RecoveryGas CostRevenue Decoupling
Arkansas Gasþþþþþ
Colorado Gasþþþ
RMNG (a)
þ
Iowa Gasþþþ
Kansas Gasþþþþþ
Nebraska Gasþþþ
Wyoming Gasþþþ
____________________
(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.
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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 TeamAs of December 31, 2021As of December 31, 2020
Total employees2,8843,011
Women in executive leadership positions (a)
30%31%
Gender diversity (women as a % of total employees)26%26%
Represented by a union25%25%
Military veterans14%16%
Ethnic diversity (non-white employees as a % of total)12%11%
For the year ended December 31, 2021For the year ended December 31, 2020
Number of external hires214299
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 rate3%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 Utilities420 
Gas Utilities1,191 
Corporate and Other1,273 
Total2,884 

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.
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UtilityNumber of EmployeesUnion AffiliationExpiration Date of Collective Bargaining Agreement
Colorado Electric94 IBEW Local 667April 15, 2023
South Dakota Electric128 IBEW Local 1250March 31, 2022
Wyoming Electric25 IBEW Local 111June 30, 2024
Total Electric Utilities247 
Iowa Gas132 IBEW Local 204January 31, 2026
Kansas Gas16 Communications Workers of America, AFL-CIO Local 6407December 31, 2024
Nebraska Gas92 IBEW Local 244March 13, 2022
Nebraska Gas140 CWA Local 7476October 30, 2023
Wyoming Gas15 IBEW Local 111June 30, 2024
Wyoming Gas78 CWA Local 7476October 30, 2023
Total Gas Utilities473 
Total720 

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%
____________________
(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 preparedand 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. 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, or these risks and losses.

In May and July 2021, the TSA issued security directives 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 are currently implementing several of these directives and 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.

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.

Weather conditions, including the impacts of climate change, may cause fluctuation in customer usage.

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, customers’ energy use could increase or decrease. 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 and income 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.
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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, if at all. 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.

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 as well as anothermay 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 measure, gross 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. Gross margin (revenue less cost of sales) is a non-GAAP financial measureresults due to mark-to-market accounting treatment.

To the exclusionextent 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 depreciationdebt. 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 measure. The presentation of gross margin is intendedsubsidiaries.

As a holding company, our investments in our subsidiaries are our primary assets. Our operating cash flow and ability to supplement investors’ understandingservice our indebtedness depend on the operating cash flow of our operating performance.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.


In our ManagementThere 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 gross marginin 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.

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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 the capital markets and the costs and terms of available financing depend on many factors, including changes in our credit ratings, changes in the federal or state regulatory environment affecting energy companies, volatility in commodity or electricity prices and general economic and market conditions.

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.

National and regional economic conditions may cause increased counterparty credit risk, late payments and uncollectible accounts.

A future recession or pandemic, if one occurs, may lead to an increase in late payments or non-payment from retail residential, commercial and industrial utility customers, as well as from our non-utility customers. If late payments and uncollectible accounts increase, earnings and cash flows from our continuing operations may be reduced.

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 the Company may be subject, including liability and losses associated with climate change, wildfire, 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.

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.

PANDEMIC RISK

The ongoing COVID-19 pandemic, including its variants, or any other pandemic and the associated impact on business and economic conditions could negatively affect our business operations, results of operations, financial condition and cash flows.

The scale and scope of the COVID-19 outbreak, the resulting pandemic or any other future pandemic, and the associated impact on the economy and financial markets could adversely affect the Company’s business, results of operations and financial condition. As a provider of essential services, the Company has an obligation to provide electric and natural gas 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.
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Although the impact of the COVID-19 pandemic and its variants to our 2021 results of operation was not significant, we cannot ultimately predict whether it will have a material impact on our future liquidity, financial condition or results of operations. We also cannot predict the impact of COVID-19 on the health of our employees, our supply chain or our ability to mitigate higher costs associated with managing through the COVID-19 pandemic.

As recovery from the COVID-19 pandemic continues, additional uncertainties have emerged, including the impacts of:
•vaccine mandates and testing requirements on our workforce;
•inflation increasing prices of commodities and materials, outside services, employee costs and interest rates;
•supply chain disruptions on the availability and cost of materials; and
•labor shortages and increased turnover on costs of retaining and attracting employees.

The situation remains fluid and it is difficult to predict with certainty the potential impact of the COVID-19 pandemic, or any other future pandemic, on our financial operating results including earnings, cash flows and 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 59, 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 20 years of experience with the Company.

Brian G. Iverson, age 59, 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 18 years of experience with the Company.

Erik D. Keller, age 58, 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 56, 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 22 years of experience with the Company.

Jennifer C. Landis, age 47, 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 20 years of experience with the Company.

Stuart A. Wevik, age 60, has been Senior Vice President - Utility Operations since August 26, 2019. He served as Group Vice President - Electric Utilities from 2016 to August 2019, Vice President - Utility Operations from 2008 to 2016, Vice President - Operations from 2004 to 2008 and Vice President and General Manager from 2003 to 2004. Mr. Wevik has 36 years of experience with the Company. Mr. Wevik intends to retire on June 1, 2022.
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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, 2022, we had 3,475 common shareholders of record and 60,937 beneficial owners, representing all 50 states, the District of Columbia and 7 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, 2016, 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.

bkh-20211231_g1.jpg

Years ended December 31,
201620172018201920202021
Black Hills Corporation$100.00 $100.77 $108.81 $139.91 $113.21 $134.59 
S&P 500100.00 121.83 116.49 153.17 181.35 233.41 
S&P 500 Utilities100.00 112.11 116.71 147.46 148.18 174.36 
Performance Peer Group (a)
100.00 113.59 119.17 143.70 123.74 140.78 
____________________
(a)    Performance Peer Group represents the list of 20 utility and energy industry companies used in our 2021 Proxy Statement which was filed with the SEC on March 18, 2021.

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 2021.

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.
29

ISSUER PURCHASES OF EQUITY SECURITIES

The following table contains monthly information about our acquisitions of equity securities for the three months ended December 31, 2021:
Period
Total Number of Shares Purchased (a)
Average Price Paid per ShareTotal Number of Shares Purchased as Part of Publicly Announced Plans or ProgramsMaximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
October 1, 2021 - October 31, 20211$63.15 — — 
November 1, 2021 - November 30, 202177766.10 — — 
December 1, 2021 - December 31, 20218,68068.40 — — 
Total9,458$68.21 — — 
____________________
(a)    Shares were acquired under the share withholding provisions of the 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 that invests in our communities’ safety, sustainability and growth with a mission of Improving Life with Energy and a vision to be the Energy Partner of Choice. The Company’s core mission— and our primary focus — is to provide safe, reliable and cost-effective electric and natural gas service to 1.3 million utility customers in over 800 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming.

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. The Company conducts its utility operations under the name Black Hills Energy predominantly in rural areas of the Rocky Mountains and Midwestern states. The Company considers itself a domestic electric and natural gas utility company.

The Company has provided energy and served customers for 138 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.

An important 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. For this important work, we are Ready to serve. 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 1,481.5 MW of generation capacity and 8,900 miles of transmission and distribution lines and our Gas Utilities own and operate 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 285-mile, multi-phase transmission expansion project will serve the growing needs of customers enhancing the resiliency of its overall electric system and expanding access to power markets and renewable energy resources. The project will enable Wyoming Electric to maintain top-quartile reliability and support further economic growth in the Cheyenne area. Wyoming Electric plans to file an application with the WPSC seeking approval for the project in the first quarter of 2022. Following approval, construction would commence in early 2023.

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, 2021, we estimate our five-year capital investment to be approximately $3.2 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 2021 and forecasted capital expenditures for the next five years from 2022 through 2026 are as follows (in millions):

Actual (a)
Forecasted
Capital Expenditures By Segment :
202120222023202420252026
(in millions)
Electric Utilities$286 $239 $205 $285 $231 $155 
Gas Utilities383 363 383 386 349 346 
Corporate and Other11 9 12 13 13 13 
Incremental projects (b)
— — — — 60 140 
Total$680 $611 $600 $684 $653 $654 
____________________
(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. In the fourth quarter of 2021, we revised our operating segments to align with our vertically integrated business model for our Electric Utilities. Our power generation and mining businesses, which were previously presented as separate operating segments, are now part of our vertically integrated Electric Utilities segment.

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Our power production strategy focuses on low-cost construction and efficient operation of our generating facilities. Our low power production costs result from a variety of factors including low fuel costs (operations located near energy hubs), efficiency in converting fuel into energy and low per unit operating and maintenance costs. In addition, we operate our plants with high levels of Availability as compared to industry benchmarks.

Rate 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 contains 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. This 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 Top of Iowa, 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 only 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. The small coal mine provides approximately 3.5 million tons of low-sulfur coal directly to these 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 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 of 40% by 2030 and 70% by 2040 and achieve GHG reductions of 50% by 2035 for our Gas Utilities. Our goals are based on existing technology and computed from 2005 baseline levels of GHG emissions intensity for our electric operations and natural gas distribution system. Since 2005, we have reduced GHG emissions intensity from our Gas Utilities by more than 33% and achieved a 30% reduction from our Electric Utilities (an additional 5% reduction since announcing our goal in 2020 for our Electric Utilities). Additionally, our Electric Utilities have reduced nitrogen oxide and sulfur dioxide emissions by more than 75% since 2005. Our electric utility in Colorado has achieved a nearly 50% reduction in GHG emissions since 2005 and is calculatedon track to reach the State of Colorado’s 80% carbon reduction goal by 2030. Our goals are based on prudent and proven solutions to reduce our emissions while minimizing cost impacts to our customers. This keeps our customers at the forefront of our decision-making, which is central to our values.

More of our customers, particularly our larger customers, are demanding cleaner sources of energy to meet their sustainability goals. In addition, there is more interest from consumers, regulators and legislators to increase the use of renewable and other alternative energy sources. To support this interest:

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•We created the Renewable Ready program for South Dakota and Wyoming 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, on November 30, 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 the near-term planning period through 2026 propose the addition of 100 MW of renewable generation, the conversion of Neil Simpson II to natural gas in 2025 and consideration of up to 20 MW of battery storage.

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.

Explore opportunities as operating revenue less costan 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, crypto miners and other blockchain opportunities; exploring energy markets such as RTOs; and expanding our transmission capabilities. As an example, we have supported enabling legislation in Wyoming for the growing blockchain and digital currency businesses while implementing our own Blockchain Interruptible Service Tariff to serve these customers. We are also re-focusing on our product and services offerings to our natural gas customers.

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

•Electric Vehicles (EV): 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 will investigate 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 (RNG): Our teams are developing RNG/carbon offset offerings for our retail customers, evaluating multiple RNG investment opportunities and exploring value generation with our natural gas storage assets. We also continue to expand our RNG interconnections, with several projects actively injecting RNG into our natural gas system.

Execute disciplined capital allocation and explore small strategic opportunities. We are planning a disciplined capital investment program of approximately $600 million annually over the next two years 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. 2021 represented our 51st consecutive year of increasing dividends. In January 2022, our Board of Directors declared a quarterly dividend of $0.595 per share, equivalent to an annual dividend of $2.38 per share. We intend to continue our record of annual dividend increases with a targeted dividend payout ratio of 50% to 60%.

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.


33
Recent Developments

Winter Storm Uri

In February 2021, a prolonged period of historic cold temperatures across the central United States covered all of our Utilities’ service territories, 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 of Winter Storm Uri, we incurred significant incremental natural gas and fuel costs.

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. Proceeds from the August 26, 2021 debt transaction were used to repay amounts outstanding under this term loan. See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further information.

During the second quarter, our Utilities submitted cost recovery applications with the utility commissions in our state jurisdictions to recover incremental costs associated with Winter Storm Uri. To date, several of gas sold. Gross marginour Utilities have received interim or final Commission Orders and have begun recovering costs from customers. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further information on our regulatory activity.

COVID-19 Pandemic

For the year ended December 31, 2021, we did not experience significant impacts to our financial results, liquidity or operational activities due to COVID-19. We continue to monitor loads, customers’ ability to pay, the potential for supply chain disruption or inflation that may impact our capital and maintenance project plans, the availability of third-party resources to execute our business plans and the capital markets to ensure we have the liquidity necessary to support our financial needs. State Orders lifting temporarily suspended disconnections have been issued in all of our jurisdictions.

As we look forward, our operating results could be affected by COVID-19 as discussed in detail in our Risk Factors.

Business Segment Highlights and Corporate Activity

Electric Utilities

•On January 26, 2022, Colorado Electric agreed to join SPP’s Western Energy Imbalance Service Market. Colorado Electric, PRPA, and the Colorado subsidiary of Xcel Energy Inc. will join the market in April 2023 and will continue to study long-term solutions for joining or developing an organized wholesale market. The expansion allows the utilities to participate in a real-time market to dispatch energy at lower costs.

•On January 5, 2022, South Dakota Electric and Wyoming Electric set new winter peak loads. This is the fourth new winter peak for Wyoming Electric since 2015. Wyoming Electric’s new winter peak load of 253 MW surpasses the previous peak of 247 MW set in December 2019. South Dakota Electric’s new winter peak of 327 MW surpasses the previous winter peak of 326 MW set in February 2021.

•In November 2021, Wyoming Electric announced its Ready Wyoming electric transmission expansion initiative. See Key Elements of our Business Strategy above for further information.

•On October 5, 2021, our Electric Utilities and several other utilities in the western United States formed the Western Markets Exploratory Group to research the potential for an organized wholesale market in the western interconnect, including expanding transmission systems and other grid-related services. The group plans to identify market solutions that can help achieve carbon reduction goals while supporting reliable, cost-effective services for customers.

•On September 19, 2021, Wygen I experienced an unplanned outage that continued until mid-December 2021. For the year ended December 31, 2021, the outage had an $11 million negative impact to Operating income. We are currently assessing insurance recovery opportunities.

•On August 24, 2021, Wyoming Electric issued a request for proposals under its Blockchain Interruptible Service tariff. We have narrowed the bidder’s list and selected finalists for contract negotiations.

•On July 28, 2021, Wyoming Electric set a new all-time and summer peak load of 274 MW, exceeding the previous peak of 271 MW set in July 2020.

•On July 27, 2021, South Dakota Electric set a new all-time and summer peak load of 397 MW, exceeding the previous peak of 378 MW set in August 2020.

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•On June 30, 2021, South Dakota Electric and Wyoming Electric submitted an IRP to the SDPUC and WPSC. See Key Elements of our Business Strategy above for further information.

•On February 19, 2021, Colorado Electric entered into a PPA with TC Colorado Solar, LLC (TC Solar) to purchase up to 200 MW of renewable energy upon construction of a new solar facility, to be owned by TC Solar. On January 31, 2022, TC Solar provided termination notice of the PPA to Colorado Electric. Colorado Electric has disputed TC Solar’s right to termination and pursuant to the agreement, has initiated discussions with TC Solar.

Gas Utilities

•See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for recent regulatory activity for our Gas Utilities is calculated as operating revenues less costin Arkansas, Colorado, Iowa, Kansas and Nebraska.

Corporate and Other

•On August 26, 2021, we completed a public debt offering which consisted of gas sold. Our gross margin is impacted by$600 million, 1.037% 3-year senior unsecured notes due August 23, 2024. The proceeds from the fluctuationsoffering were used to repay amounts outstanding under our term loan entered into on February 24, 2021. See Note 8 of the Notes to Consolidated Financial Statements in power purchasesthis Annual Report on Form 10-K for further information.

•On July 19, 2021, we amended and natural gas and other fuel supply costs. However, while these fluctuating costs impact gross margin as a percentagerestated our corporate Revolving Credit Facility. See Note 8 of revenue, they only impact total gross margin if the costs cannot be passed throughNotes to our customers.Consolidated Financial Statements in this Annual Report on Form 10-K for further information.



35
Results of Operations

Our gross margin measure may not be comparable to other companies’ gross margin measure. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.



Electric Utilities

Operating resultsdiscussion and analysis for the yearsyear ended December 31, 2021 compared to 2020 as well as discussion and analysis of the results of operations for the year ended December 31, 2020 compared to 2019, is included herein. For further discussion and analysis that remains unchanged for the year ended December 31, 2020 compared to 2019, 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, 2020, which was filed with the SEC on February 26, 2021.

In the fourth quarter of 2021, we integrated our power generation and mining businesses within the Electric Utilities were as follows (in thousands):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.

 2017Variance2016Variance2015
      
Revenue$704,650
$27,369
$677,281
$(2,562)$679,843
      
Total fuel and purchased power268,405
7,056
261,349
(8,060)269,409
      
Gross margin436,245
20,313
415,932
5,498
410,434
      
Operations and maintenance172,307
14,173
158,134
(2,790)160,924
Depreciation and amortization93,315
8,670
84,645
3,716
80,929
Total operating expenses265,622
22,843
242,779
926
241,853
      
Operating income170,623
(2,530)173,153
4,572
168,581
      
Interest expense, net(52,274)(1,983)(50,291)754
(51,045)
Other income (expense), net1,730
(1,463)3,193
1,977
1,216
Income tax expense(9,997)30,231
(40,228)945
(41,173)
      
Net income (loss) available for common stock$110,082
$24,255
$85,827
$8,248
$77,579
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
 201720162015
Regulated power plant fleet availability:   
Coal-fired plants  (a) (b) (c)
88.9%90.2%91.5%
Natural gas fired plants and Other plants96.1%95.1%95.4%
Wind (d)
93.3%79.3%99.3%
Total availability93.6%93.5%94.0%
    
Wind capacity factor36.7%36.6%32.4%
For the Years Ended December 31,
202120202019
(in thousands, except per share amounts)
Operating income (loss):
Electric Utilities$202,676 $210,974 $217,677 
Gas Utilities211,157 215,889 189,971 
Corporate and Other(4,404)1,440 (1,606)
Operating Income409,429 428,303 406,042 
Interest expense, net(152,404)(143,470)(137,659)
Impairment of investment— (6,859)(19,741)
Other income (expense), net1,404 (2,293)(5,740)
Income tax (expense)(7,169)(32,918)(29,580)
Net income251,260 242,763 213,322 
Net income attributable to non-controlling interest(14,516)(15,155)(14,012)
Net income available for common stock$236,744 $227,608 $199,310 
Total earnings per share of common stock, Diluted$3.74 $3.65 $3.28 
____________________
(a) 2017 reflects planned outages at Neil Simpson II, Wyodak, and Wygen II.    
(b) 2016 reflects a planned outage at Wygen III, an extended planned outage at Wyodak and2021 Compared to 2020

The variance to the prior year included the following:

•Electric Utilities’ operating income decreased $8.3 million primarily due to Colorado Electric’s TCJA-related bill credits to customers (which is offset by reduced tax expense), unfavorable impacts from an unplanned outage at Neil Simpson II.
(c)2015 reflects planned outages at Neil Simpson II, Wygen II and Wygen III.
(d)2017 and 2016 were lower due to the addition of Peak View Wind Project with ownership transfer in November, 2016.




2017 Compared to 2016

Gross margin increased over the prior year primarily reflecting a $7.8 million return on investment from the Peak View Wind Project, a $7.4 million increase in rider revenues primarily related to transmission investment recovery,Wygen I and a $2.1 million increase in commercial and industrial margins driven by increased demand largely associated with data centers in Cheyenne, Wyoming. A variety of smaller items contribute to the remainder of the net increase.

Operations and maintenance increased primarily due to $4.8 million of higher employee costsdepreciation as a result of additional plant placed in service, partially offset by increased power marketing and wholesale revenues, increased rider revenues, increased commercial and industrial demand, a prior year integration activitiesexpense related to the early retirement of certain non-regulated generation assets, residential customer growth and transitionincreased usage, and prior year COVID-19 impacts;
•Gas Utilities’ operating income decreased $4.7 million primarily due to Winter Storm Uri costs incurred by Black Hills Energy Services, lower heating demand from milder weather (primarily in the fourth quarter of 2021), Nebraska Gas TCJA-related bill credits to customers and higher operating expenses charged to partially offset by new rates and customer growth;
•Corporate and Other $2.6expenses increased $5.8 million of higher generation outage expenses, $1.9 million of higher property taxes with an increased asset base, and $1.7 million of higher operating expenses from the Peak View Wind Project and the 40-megawatt gas turbine at the Pueblo Airport Generating Station. An additional $1.3 million of indirect corporate costs are included at the electric utilities; these costs were previously charged to our Oil and Gas segment, now reported as discontinued operations.

Depreciation and amortization increased primarily due to a higher asset base driven partially by the addition of the Peak View Wind Project and the 40-megawatt gas turbine at the Pueblo Airport Generating Station.

Interest expense, net increased primarily due to higher intercompany debt resulting from additional investments as compared to theemployee costs driven by a prior year.year favorable true-up;

Other (expense) income, net decreased•Interest expense increased $8.9 million primarily due to reduced AFUDC withhigher debt balances partially offset by lower capital spend.rates;

•A prior year $6.9 million pre-tax non-cash impairment in 2020 of our investment in equity securities of a privately held oil and gas company;
•Other income increased $3.7 million primarily due to lower non-service pension costs driven by a lower discount rate, lower costs for our non-qualified benefit plans which were driven by market performance and recognition of death benefits from Company-owned life insurance; and
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•Income tax benefit (expense): Theexpense decreased $26 million primarily due to lower pre-tax income and a lower effective tax rate was lower in 2017driven primarily due to a $23 million benefit resultingby tax benefits from revaluation of net deferredColorado Electric and Nebraska Gas TCJA-related bill credits (which is offset by reduced revenue), flow-through tax liabilities in accordance with ASC 740 and the enactment of the TCJA on December 22, 2017. This benefit was primarilybenefits related to the revaluation of net operating lossesrepairs and othergain deferral and increased tax basis items not included in the ratemaking construct. Productionbenefits from federal production tax credits associated with the Peak View Wind Project increased by $4.0 million reflecting a full year of production tax credits comparednew wind assets.

2020 Compared to two months in 2016. 2019

The variance to the prior year included a $1.3the following:

•COVID-19 related impacts to consolidated results included $3.6 million benefit related to the flow-through treatment of a treasury grant related to the Busch Ranch Wind Project.

2016 Compared to 2015

Grosslower Electric and Gas Utility margin increased over the prior year reflecting increased rider margins of $4.9 million driven primarily by our constructionlower volumes and TCA riders, an increasewaived customer late payment fees, $2.6 million of $2.4costs due to sequestration of essential employees and $3.3 million in commercialof additional bad debt expense which were partially offset by $3.8 million of lower travel, training, and industrial margins driven by increased demand, a $1.5outside services related expenses;
•Electric Utilities’ operating income decreased $6.7 million return on investment from the Peak View Wind Project,due to higher depreciation and a $1.4 million increase in residential margins driven by favorable weather. Offsetting these increases was a $2.1 million prior-year benefitamortization expense as a result of a one-time settlement withadditional plant placed in service including new wind assets, expense from the Colorado Public Utilities Commissionearly retirement of certain non-regulated assets, lower commercial and industrial demand and COVID-19 impacts partially offset by increased revenue from our non-regulated power generation and mining businesses, benefits from the release of TCJA revenue reserves and increased rider revenues;
•Gas Utilities’ operating income increased $26 million primarily due to new customer rates in Wyoming and Nebraska and increased rider revenues, customer growth, mark-to-market gains on our renewable energy standard adjustment related to the Busch Ranch wind farm, a prior-year increase in return on invested capital of $1.2 million from South Dakota Electric’s rate case,non-utility natural gas commodity contracts and a $1.3 million decrease due to third-party billing true-ups relating to the current2019 amortization of excess deferred income taxes partially offset by higher depreciation and prior years.

Operations and maintenance decreased primarilyamortization expense as a result of approximately $5.8additional plant placed in service, COVID-19 impacts and unfavorable weather;
•Corporate and Other expenses decreased $3.0 million lower employee costs primarily driven by a change in expense allocations impacting the electric utilities as a result of integrating the acquired SourceGas utilities. This decrease is partially offset by higher operating costs from the Peak View Wind Project, which commenced commercial operation in November 2016, and increased vegetation management costs.

Depreciation and amortization increased primarily due to an unallocated favorable true-up of employee costs;
•A $6.9 million pre-tax non-cash impairment in 2020 of our investment in equity securities of a higher asset base driven partially by the addition of Peak View Wind Project.privately held oil and gas company compared to a similar $20 million impairment in 2019;

•Interest expense net decreasedincreased $5.8 million primarily due to higher AFUDC interest income drivendebt balances partially offset by constructionlower rates;
•Other expense decreased $3.4 million due to the 2019 expensing of $5.4 million of development costs related to projects we no longer intend to construct partially offset by increased pension non-service costs in process as compared to prior year.2020; and

Other (expense) income, net•Income tax expense increased $3.3 million primarily due to higher AFUDC equity in the current period compared to prior year.

Income tax benefit (expense): Thepre-tax income partially offset by a lower effective tax rate was lower than prior year primarily due to the accelerated recognitionrate.


Segment Operating Results

A discussion of benefits associated with certain tax incentives.operating results from our business segments follows.






Gas Utilities


Operating resultsWe 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 Customers202120202019
Residential853,908 844,999 831,351 
Commercial84,234 83,135 82,912 
Industrial2,158 2,235 2,208 
Transportation153,929 152,568 149,971 
Total Natural Gas Retail Customers at End of Year1,094,229 1,082,937 1,066,442 

As of December 31,
Retail Customers202120202019
Arkansas180,216 178,281 174,447 
Colorado202,747 197,817 191,950 
Iowa161,905 160,952 159,641 
Kansas117,862 116,973 115,846 
Nebraska298,832 296,778 293,576 
Wyoming132,667 132,136 130,982 
Total Natural Gas Retail Customers at End of Year1,094,229 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:
StateWorking Capacity (Mcf)Cushion Gas
(Mcf)		Total Capacity (Mcf)Maximum Daily Withdrawal Capability (Mcfd)
Arkansas9,273,700 12,318,040 21,591,740 196,000 
Colorado2,361,495 6,164,715 8,526,210 30,000 
Wyoming5,733,900 17,145,600 22,879,500 36,000 
Total17,369,095 35,628,355 52,997,450 262,000 

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

StateIntrastate Gas
Transmission Pipelines
(in line miles)		Gas Distribution
Mains
(in line miles)		Gas Distribution
Service Lines
(in line miles)
Arkansas874 4,972 1,275 
Colorado693 6,990 2,303 
Iowa172 2,863 2,486 
Kansas330 2,980 1,374 
Nebraska1,311 8,443 2,773 
Wyoming1,352 3,532 1,653 
Total4,732 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.

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The following table provides regulatory information for each of our natural gas utilities:
SubsidiaryJurisdic-tionAuthorized Rate of Return on EquityAuthorized Return on Rate BaseAuthorized Capital Structure Debt/EquityAuthorized Rate Base (in millions)Effective DateAdditional Regulatory Mechanisms
Arkansas Gas (c)
AR9.61%
6.82% (a)
51%/49%
$451.5 (b)
10/2018GCA, Main Replacement Program, At-Risk Meter Relocation Program, Legislative or Regulatory Mandated Expenditures, EECR, Weather Normalization Adjustment, Billing Determinant Adjustment
Colorado Gas (c)
CO9.20%6.56%50%/50%$303.21/2022GCA, SSIR, EECR/DSM
RMNGCO9.90%6.71%53%/ 47%$118.76/2018SSIR, Liquids/Off-system/Market Center Services Revenue Sharing
Iowa Gas (c)
IA9.60%6.75%50%/50%$300.91/2022GCA, EECR, System Safety and Maintenance Adjustment Rider, Gas Supply Optimization revenue sharing
Kansas Gas (c)
KSGlobal SettlementGlobal SettlementGlobal SettlementGlobal Settlement1/2022GCA, 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)
NE9.50%6.71%50%/50%$504.23/2021GCA, 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)
WY9.40%6.98%50%/50%$354.43/2020GCA, 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 JurisdictionCost Recovery Mechanisms
DSM/Energy EfficiencyIntegrity AdditionsBad DebtWeather NormalPension RecoveryGas CostRevenue Decoupling
Arkansas Gasþþþþþ
Colorado Gasþþþ
RMNG (a)
þ
Iowa Gasþþþ
Kansas Gasþþþþþ
Nebraska Gasþþþ
Wyoming Gasþþþ
____________________
(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.
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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.
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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 TeamAs of December 31, 2021As of December 31, 2020
Total employees2,8843,011
Women in executive leadership positions (a)
30%31%
Gender diversity (women as a % of total employees)26%26%
Represented by a union25%25%
Military veterans14%16%
Ethnic diversity (non-white employees as a % of total)12%11%
For the year ended December 31, 2021For the year ended December 31, 2020
Number of external hires214299
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 rate3%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 Utilities420 
Gas Utilities1,191 
Corporate and Other1,273 
Total2,884 

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.
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UtilityNumber of EmployeesUnion AffiliationExpiration Date of Collective Bargaining Agreement
Colorado Electric94 IBEW Local 667April 15, 2023
South Dakota Electric128 IBEW Local 1250March 31, 2022
Wyoming Electric25 IBEW Local 111June 30, 2024
Total Electric Utilities247 
Iowa Gas132 IBEW Local 204January 31, 2026
Kansas Gas16 Communications Workers of America, AFL-CIO Local 6407December 31, 2024
Nebraska Gas92 IBEW Local 244March 13, 2022
Nebraska Gas140 CWA Local 7476October 30, 2023
Wyoming Gas15 IBEW Local 111June 30, 2024
Wyoming Gas78 CWA Local 7476October 30, 2023
Total Gas Utilities473 
Total720 

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%
____________________
(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;
23

•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 vendors’ information systems, could further add to a full or partial disruption of our operations. 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, or these risks and losses.

In May and July 2021, the TSA issued security directives 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 are currently implementing several of these directives and 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.

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.

Weather conditions, including the impacts of climate change, may cause fluctuation in customer usage.

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, customers’ energy use could increase or decrease. 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 and income 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.
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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, if at all. 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.

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.

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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 the capital markets and the costs and terms of available financing depend on many factors, including changes in our credit ratings, changes in the federal or state regulatory environment affecting energy companies, volatility in commodity or electricity prices and general economic and market conditions.

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.

National and regional economic conditions may cause increased counterparty credit risk, late payments and uncollectible accounts.

A future recession or pandemic, if one occurs, may lead to an increase in late payments or non-payment from retail residential, commercial and industrial utility customers, as well as from our non-utility customers. If late payments and uncollectible accounts increase, earnings and cash flows from our continuing operations may be reduced.

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 the Company may be subject, including liability and losses associated with climate change, wildfire, 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.

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.

PANDEMIC RISK

The ongoing COVID-19 pandemic, including its variants, or any other pandemic and the associated impact on business and economic conditions could negatively affect our business operations, results of operations, financial condition and cash flows.

The scale and scope of the COVID-19 outbreak, the resulting pandemic or any other future pandemic, and the associated impact on the economy and financial markets could adversely affect the Company’s business, results of operations and financial condition. As a provider of essential services, the Company has an obligation to provide electric and natural gas 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.
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Although the impact of the COVID-19 pandemic and its variants to our 2021 results of operation was not significant, we cannot ultimately predict whether it will have a material impact on our future liquidity, financial condition or results of operations. We also cannot predict the impact of COVID-19 on the health of our employees, our supply chain or our ability to mitigate higher costs associated with managing through the COVID-19 pandemic.

As recovery from the COVID-19 pandemic continues, additional uncertainties have emerged, including the impacts of:
•vaccine mandates and testing requirements on our workforce;
•inflation increasing prices of commodities and materials, outside services, employee costs and interest rates;
•supply chain disruptions on the availability and cost of materials; and
•labor shortages and increased turnover on costs of retaining and attracting employees.

The situation remains fluid and it is difficult to predict with certainty the potential impact of the COVID-19 pandemic, or any other future pandemic, on our financial operating results including earnings, cash flows and 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 59, 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 20 years of experience with the Company.

Brian G. Iverson, age 59, 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 18 years of experience with the Company.

Erik D. Keller, age 58, 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 56, 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 22 years of experience with the Company.

Jennifer C. Landis, age 47, 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 20 years of experience with the Company.

Stuart A. Wevik, age 60, has been Senior Vice President - Utility Operations since August 26, 2019. He served as Group Vice President - Electric Utilities from 2016 to August 2019, Vice President - Utility Operations from 2008 to 2016, Vice President - Operations from 2004 to 2008 and Vice President and General Manager from 2003 to 2004. Mr. Wevik has 36 years of experience with the Company. Mr. Wevik intends to retire on June 1, 2022.
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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, 2022, we had 3,475 common shareholders of record and 60,937 beneficial owners, representing all 50 states, the District of Columbia and 7 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, 2016, 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.

bkh-20211231_g1.jpg

Years ended December 31,
201620172018201920202021
Black Hills Corporation$100.00 $100.77 $108.81 $139.91 $113.21 $134.59 
S&P 500100.00 121.83 116.49 153.17 181.35 233.41 
S&P 500 Utilities100.00 112.11 116.71 147.46 148.18 174.36 
Performance Peer Group (a)
100.00 113.59 119.17 143.70 123.74 140.78 
____________________
(a)    Performance Peer Group represents the list of 20 utility and energy industry companies used in our 2021 Proxy Statement which was filed with the SEC on March 18, 2021.

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 2021.

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.
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ISSUER PURCHASES OF EQUITY SECURITIES

The following table contains monthly information about our acquisitions of equity securities for the three months ended December 31, 2021:
Period
Total Number of Shares Purchased (a)
Average Price Paid per ShareTotal Number of Shares Purchased as Part of Publicly Announced Plans or ProgramsMaximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
October 1, 2021 - October 31, 20211$63.15 — — 
November 1, 2021 - November 30, 202177766.10 — — 
December 1, 2021 - December 31, 20218,68068.40 — — 
Total9,458$68.21 — — 
____________________
(a)    Shares were acquired under the share withholding provisions of the 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 that invests in our communities’ safety, sustainability and growth with a mission of Improving Life with Energy and a vision to be the Energy Partner of Choice. The Company’s core mission— and our primary focus — is to provide safe, reliable and cost-effective electric and natural gas service to 1.3 million utility customers in over 800 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming.

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. The Company conducts its utility operations under the name Black Hills Energy predominantly in rural areas of the Rocky Mountains and Midwestern states. The Company considers itself a domestic electric and natural gas utility company.

The Company has provided energy and served customers for 138 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.

An important 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. For this important work, we are Ready to serve. 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 1,481.5 MW of generation capacity and 8,900 miles of transmission and distribution lines and our Gas Utilities were as follows (in thousands):own and operate 47,000 miles of natural gas transmission and distribution pipelines.

 2017Variance2016Variance2015
Revenue:     
Natural gas - regulated$865,831
$96,749
$769,082
$249,084
$519,998
Other - non-regulated81,799
12,538
69,261
37,959
31,302
Total revenue947,630
109,287
838,343
287,043
551,300
      
Cost of natural gas sold:     
Natural gas - regulated381,259
65,641
315,618
31,985
283,633
Other - non-regulated28,344
(8,203)36,547
20,535
16,012
Total cost of natural gas sold409,603
57,438
352,165
52,520
299,645
      
Gross margin:     
Natural gas - regulated484,572
31,108
453,464
217,099
236,365
Other - non-regulated53,455
20,741
32,714
17,424
15,290
Total gross margin538,027
51,849
486,178
234,523
251,655
      
Operations and maintenance269,190
23,364
245,826
105,103
140,723
Depreciation and amortization83,732
5,397
78,335
46,009
32,326
Total operating expenses352,922
28,761
324,161
151,112
173,049
      
Operating income185,105
23,088
162,017
83,411
78,606
      
Interest expense, net(78,575)(3,562)(75,013)(57,702)(17,311)
Other income (expense), net(829)(1,013)184
(131)315
Income tax expense(39,799)(12,337)(27,462)(5,158)(22,304)
      
Net income (loss)65,902
6,176
59,726
20,420
39,306
Net income attributable to noncontrolling interest(107)(5)(102)(102)—
Net income (loss) available for common stock$65,795
$6,171
$59,624
$20,318
$39,306
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.


2017 ComparedWe rigorously comply with all applicable federal, state and local regulations and strive to 2016consistently 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.


Gross margin increased primarily dueTo 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 additional marginsensure the timely repair and replacement of approximately $51 million contributed byaging infrastructure. In alignment with this program, in November 2021, Wyoming Electric announced its Ready Wyoming electric transmission expansion initiative. The 285-mile, multi-phase transmission expansion project will serve the SourceGas utilitiesgrowing needs of customers enhancing the resiliency of its overall electric system and expanding access to power markets and renewable energy resources. The project will enable Wyoming Electric to maintain top-quartile reliability and support further economic growth in the Cheyenne area. Wyoming Electric plans to file an application with the WPSC seeking approval for the project in the first quarter of 2017 compared2022. Following approval, construction would commence in early 2023.

Our Gas Utilities utilize a programmatic approach to system-wide pipeline replacement, particularly in high consequence areas. Under the firstprogrammatic 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, 2021, we estimate our five-year capital investment to be approximately $3.2 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 2021 and forecasted capital expenditures for the next five years from 2022 through 2026 are as follows (in millions):

Actual (a)
Forecasted
Capital Expenditures By Segment :
202120222023202420252026
(in millions)
Electric Utilities$286 $239 $205 $285 $231 $155 
Gas Utilities383 363 383 386 349 346 
Corporate and Other11 9 12 13 13 13 
Incremental projects (b)
— — — — 60 140 
Total$680 $611 $600 $684 $653 $654 
____________________
(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. In the fourth quarter of 20162021, we revised our operating segments to align with our vertically integrated business model for our Electric Utilities. Our power generation and mining businesses, which included approximately 1.5 monthswere previously presented as separate operating segments, are now part of SourceGas results. 2017 reflectsour vertically integrated Electric Utilities segment.

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Our power production strategy focuses on low-cost construction and efficient operation of our generating facilities. Our low power production costs result from a full twelve monthsvariety of SourceGas resultsfactors 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 approximately 10.5 monthsindustry benchmarks.

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 2016.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;


Operations•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 maintenance increased primarilyinvestors 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 contains 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. This 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 Top of Iowa, 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 only 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. The small coal mine provides approximately 3.5 million tons of low-sulfur coal directly to these 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 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 of 40% by 2030 and 70% by 2040 and achieve GHG reductions of 50% by 2035 for our Gas Utilities. Our goals are based on existing technology and computed from 2005 baseline levels of GHG emissions intensity for our electric operations and natural gas distribution system. Since 2005, we have reduced GHG emissions intensity from our Gas Utilities by more than 33% and achieved a 30% reduction from our Electric Utilities (an additional operating costs5% reduction since announcing our goal in 2020 for our Electric Utilities). Additionally, our Electric Utilities have reduced nitrogen oxide and sulfur dioxide emissions by more than 75% since 2005. Our electric utility in Colorado has achieved a nearly 50% reduction in GHG emissions since 2005 and is on track to reach the State of Colorado’s 80% carbon reduction goal by 2030. Our goals are based on prudent and proven solutions to reduce our emissions while minimizing cost impacts to our customers. This keeps our customers at the forefront of our decision-making, which is central to our values.

More of our customers, particularly our larger customers, are demanding cleaner sources of energy to meet their sustainability goals. In addition, there is more interest from consumers, regulators and legislators to increase the use of renewable and other alternative energy sources. To support this interest:

32
•We created the Renewable Ready program for South Dakota and Wyoming 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, on November 30, 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 the near-term planning period through 2026 propose the addition of 100 MW of renewable generation, the conversion of Neil Simpson II to natural gas in 2025 and consideration of up to 20 MW of battery storage.

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.

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, crypto miners and other blockchain opportunities; exploring energy markets such as RTOs; and expanding our transmission capabilities. As an example, we have supported enabling legislation in Wyoming for the growing blockchain and digital currency businesses while implementing our own Blockchain Interruptible Service Tariff to serve these customers. We are also re-focusing on our product and services offerings to our natural gas customers.

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

•Electric Vehicles (EV): 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 will investigate 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 (RNG): Our teams are developing RNG/carbon offset offerings for our retail customers, evaluating multiple RNG investment opportunities and exploring value generation with our natural gas storage assets. We also continue to expand our RNG interconnections, with several projects actively injecting RNG into our natural gas system.

Execute disciplined capital allocation and explore small strategic opportunities. We are planning a disciplined capital investment program of approximately $19$600 million annually over the next two years 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. 2021 represented our 51st consecutive year of increasing dividends. In January 2022, our Board of Directors declared a quarterly dividend of $0.595 per share, equivalent to an annual dividend of $2.38 per share. We intend to continue our record of annual dividend increases with a targeted dividend payout ratio of 50% to 60%.

We require access to the acquired SourceGas utilities, reflectingcapital 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.


33
Recent Developments

Winter Storm Uri

In February 2021, a full twelve monthsprolonged period of resultshistoric cold temperatures across the central United States covered all of our Utilities’ service territories, caused a substantial increase in 2017 as comparedheating and energy demand and contributed to approximately 10.5 months in 2016. Employee-related expenses increased $6.2 millionunforeseeable and unprecedented market prices for the Black Hills legacynatural gas utilities asand electricity. As a result of prior year integration activitiesWinter Storm Uri, we incurred significant incremental natural gas and transition expenses chargedfuel costs.

On February 24, 2021, we entered into a nine-month, $800 million unsecured term loan to Corporateprovide additional liquidity and Other. An additional $1.6 million of indirect corporate costs are included at the gas utilities; these costs were previously charged to meet our Oil and Gas segment, now reported as discontinued operations. A variety of smaller items contribute to the partially offsetting decrease in operations and maintenance expenses.

Depreciation and amortization increased primarily due to additional depreciation from the acquired SourceGas utilities.



Interest expense, net increased primarily due to additional interest expense from the acquired SourceGas utilities.

Other (expense) income, net was comparable to the same period in the prior year.

Income tax: The effective tax rate increased in 2017 primarily due to additional tax expense of $6.8 million as a result of the TCJA enacted on December 22, 2017 and from a $2.2 million tax benefit recognized in the prior year primarily related to favorable flow-through adjustments recognized in accordance with prescribed regulatory treatment. Partially offsetting these is a $4.1 million tax benefit recognized in the current year from a true-up to the filed 2016 SourceGas tax returnscash needs related to the SourceGas acquisition.

2016 Compared to 2015

Gross margin increased primarily due to margins of approximately $236 million contributed by the SourceGas utilities acquired on Feb. 12, 2016incremental fuel, purchased power and Energy West Wyoming utility acquired on July 1, 2015. Partially offsetting this increase is a $2.0 million decrease due to weather. Heating degree days were 1% lower than the prior year and 11% lower than normal.

Operations and maintenance increased primarily due to additional operatingnatural gas costs of approximately $111 million for the acquired SourceGas utilities and Energy West Wyoming utility. Partially offsetting this increase were approximately $7.4 million lower employee costs primarily driven by a change in expense allocations impacting the gas utilities as a result of integrating the acquired SourceGas utilities.

Depreciation and amortization increased primarily due to additional depreciationfrom Winter Storm Uri. Proceeds from the acquired SourceGas and Energy West Wyoming utilitiesAugust 26, 2021 debt transaction were used to repay amounts outstanding under this term loan. See Note 8 of approximately $45 million, and duethe Notes to a higher asset base atConsolidated Financial Statements in this Annual Report on Form 10-K for further information.

During the second quarter, our other gas utilities overUtilities submitted cost recovery applications with the same periodutility commissions in the prior year.

Interest expense, net increased primarily dueour state jurisdictions to additional interest expense of approximately $58 million from the debtrecover incremental costs associated with the acquired SourceGas utilities.

Income tax: The effective tax rate for 2016, including the impactWinter Storm Uri. To date, several of our Utilities have received interim or final Commission Orders and have begun recovering costs from customers. See Note 2 of the acquired SourceGas and Energy West Wyoming utilities, reflects additional tax benefits related primarilyNotes to a favorable flow through adjustment. Such adjustments are related to certain tax benefits that are recognized currentlyConsolidated Financial Statements in accordance with prescribedthis Annual Report on Form 10-K for further information on our regulatory treatment.activity.




COVID-19 Pandemic
Power Generation

Our Power Generation segment operating results for the years ended December 31 were as follows (in thousands):
 2017Variance2016Variance2015
      
Revenue$91,546
$415
$91,131
$341
$90,790
      
Operations and maintenance32,382
(254)32,636
496
32,140
Depreciation and amortization5,993
1,889
4,104
(225)4,329
Total operating expenses38,375
1,635
36,740
271
36,469
      
Operating income53,171
(1,220)54,391
70
54,321
      
Interest expense, net(2,836)(1,061)(1,775)1,428
(3,203)
Other income (expense), net(54)(56)2
(69)71
Income tax benefit (expense)10,333
27,462
(17,129)1,410
(18,539)
      
Net income (loss)60,614
25,125
35,489
2,839
32,650
Net income attributable to noncontrolling interest(14,135)(4,576)(9,559)(9,559)—
Net income (loss) available for common stock$46,479
$20,549
$25,930
(6,720)$32,650

On April 14, 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million. Black Hills Electric Generation continues to be the majority owner and operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric. Net income available for common stock forFor the year ended December 31, 2017 was reduced2021, we did not experience significant impacts to our financial results, liquidity or operational activities due to COVID-19. We continue to monitor loads, customers’ ability to pay, the potential for supply chain disruption or inflation that may impact our capital and maintenance project plans, the availability of third-party resources to execute our business plans and the capital markets to ensure we have the liquidity necessary to support our financial needs. State Orders lifting temporarily suspended disconnections have been issued in all of our jurisdictions.

As we look forward, our operating results could be affected by $14 million,COVID-19 as discussed in detail in our Risk Factors.

Business Segment Highlights and reduced by $9.6 millionCorporate Activity

Electric Utilities

•On January 26, 2022, Colorado Electric agreed to join SPP’s Western Energy Imbalance Service Market. Colorado Electric, PRPA, and the Colorado subsidiary of Xcel Energy Inc. will join the market in April 2023 and will continue to study long-term solutions for joining or developing an organized wholesale market. The expansion allows the utilities to participate in a real-time market to dispatch energy at lower costs.

•On January 5, 2022, South Dakota Electric and Wyoming Electric set new winter peak loads. This is the fourth new winter peak for Wyoming Electric since 2015. Wyoming Electric’s new winter peak load of 253 MW surpasses the previous peak of 247 MW set in December 2019. South Dakota Electric’s new winter peak of 327 MW surpasses the previous winter peak of 326 MW set in February 2021.

•In November 2021, Wyoming Electric announced its Ready Wyoming electric transmission expansion initiative. See Key Elements of our Business Strategy above for further information.

•On October 5, 2021, our Electric Utilities and several other utilities in the western United States formed the Western Markets Exploratory Group to research the potential for an organized wholesale market in the western interconnect, including expanding transmission systems and other grid-related services. The group plans to identify market solutions that can help achieve carbon reduction goals while supporting reliable, cost-effective services for customers.

•On September 19, 2021, Wygen I experienced an unplanned outage that continued until mid-December 2021. For the year ended December 31, 2016. The net income allocable2021, the outage had an $11 million negative impact to Operating income. We are currently assessing insurance recovery opportunities.

•On August 24, 2021, Wyoming Electric issued a request for proposals under its Blockchain Interruptible Service tariff. We have narrowed the bidder’s list and selected finalists for contract negotiations.

•On July 28, 2021, Wyoming Electric set a new all-time and summer peak load of 274 MW, exceeding the previous peak of 271 MW set in July 2020.

•On July 27, 2021, South Dakota Electric set a new all-time and summer peak load of 397 MW, exceeding the previous peak of 378 MW set in August 2020.

34
•On June 30, 2021, South Dakota Electric and Wyoming Electric submitted an IRP to the noncontrolling interest holders is based on ownership interestsSDPUC and WPSC. See Key Elements of our Business Strategy above for further information.

•On February 19, 2021, Colorado Electric entered into a PPA with TC Colorado Solar, LLC (TC Solar) to purchase up to 200 MW of renewable energy upon construction of a new solar facility, to be owned by TC Solar. On January 31, 2022, TC Solar provided termination notice of the exception of certain agreed upon adjustments.

 201720162015
Contracted fleet plant availability:   
Gas-fired plants99.2%99.2%99.1%
Coal-fired plants (a)
96.9%95.5%98.4%
Total98.6%98.3%98.9%
___________
(a)Wygen I experienced an unplanned outage in 2016 and a planned outage in 2017.

2017 ComparedPPA to 2016

Net income available for common stock for the Power Generation segment was $46 million for the year ended December 31, 2017, comparedColorado Electric. Colorado Electric has disputed TC Solar’s right to Net income available for common stock of $26 million for the same period in 2016. Revenuetermination and operating expenses were comparablepursuant to the same period in the prior year and depreciation expense increased on non-leased assets. The variance to the prior year was primarily driven by a $24 million current year tax benefit recognized from the revaluation of deferred tax liabilities in accordanceagreement, has initiated discussions with the TCJA enacted on December 22, 2017.TC Solar.


2016 Compared to 2015Gas Utilities


Net income available for common stock for the Power Generation segment was $26 million for the year ended December 31, 2016, compared to Net income available for common stock of $33 million for the same period in 2015. The variance to the prior year was primarily attributable to the increase in noncontrolling interest of $9.6 million as a result•See Note 2 of the noncontrolling interest saleNotes to Consolidated Financial Statements in April 2016.





Mining

Mining operating resultsthis Annual Report on Form 10-K for the years ended December 31 were as follows (in thousands):
 2017Variance2016Variance2015
      
Revenue$66,621
$6,341
$60,280
$(4,786)$65,066
      
Operations and maintenance44,882
5,306
39,576
(2,054)41,630
Depreciation, depletion and amortization8,239
(1,107)9,346
(460)9,806
Total operating expenses53,121
4,199
48,922
(2,514)51,436
      
Operating income (loss)13,500
2,142
11,358
(2,272)13,630
      
Interest (expense) income, net(205)172
(377)22
(399)
Other income, net2,191
(18)2,209
(38)2,247
Income tax benefit (expense)(1,100)2,037
(3,137)471
(3,608)
      
Net income (loss) available for common stock$14,386
$4,333
$10,053
$(1,817)$11,870

The following table provides certain operating statistics for the Mining segment (in thousands):
 2017 2016 2015 
Tons of coal sold4,183
 3,817
 4,140
 
       
Cubic yards of overburden moved (a)
9,018
 7,916
 6,088
 
       
Coal reserves at year-end194,909
 199,905
 203,849
 
____________
(a)Increase in overburden was due to relocating mining operations to areas of the mine with higher overburden.

2017 Compared to 2016

Revenue increased primarily due to a 10 percent increase in tons sold driven primarily by an 11-week outage at the Wyodak plant in the prior year.

Operations and maintenance increased due to higher equipment major maintenance, higher overburden moved and higher royalties and production taxes on increased revenues.

Depreciation, depletion and amortization decreased primarily due to lower plant in service and lower asset retirement obligation costs.

Interest (expense) income, net was comparable to the same period in the prior year.

Income tax: The effective tax rate is lower in 2017 primarily due to a $2.7 million benefit resulting from revaluation of net deferred tax liabilities in accordance with the enactment of the TCJA on December 22, 2017.



2016 Compared to 2015

Revenuedecreased primarily due to an 8 percent decrease in tons sold resulting from a planned five-week outage in the second quarter of 2016, which was extended by an additional six weeks at Wyodak plant due to an unplanned major repair of a turbine rotor. Pricing was comparable to the same period in the prior year. Approximately 50 percent of our coal production was sold under contracts that are priced based on actual mining costs, including income taxes, as compared to 46 percent for the same period in the prior year.

Operations and maintenancedecreased due to lower major maintenance requirements, fuel costs, and employee costs, as well as decreased royalties and revenue-related taxes driven by decreased revenue compared to the same period in the prior year.

Depreciation, depletion and amortizationdecreased primarily due to revised cost estimatesrecent regulatory activity for our asset retirement obligation driving lower accretionGas Utilities in Arkansas, Colorado, Iowa, Kansas and depreciation.Nebraska.


Interest (expense) income, net is comparable to the same period in the prior year.

Income tax: The effective tax rate was comparable to the same period in the prior year.




Corporate and Other


•On August 26, 2021, we completed a public debt offering which consisted of $600 million, 1.037% 3-year senior unsecured notes due August 23, 2024. The proceeds from the offering were used to repay amounts outstanding under our term loan entered into on February 24, 2021. See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further information.

•On July 19, 2021, we amended and restated our corporate Revolving Credit Facility. See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further information.


35
Results of Operations

Our discussion and analysis for the year ended December 31, 2021 compared to 2020 as well as discussion and analysis of the results of operations for the year ended December 31, 2020 compared to 2019, is included herein. For further discussion and analysis that remains unchanged for the year ended December 31, 2020 compared to 2019, 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, 2020, which was filed with the SEC on February 26, 2021.

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.

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,
202120202019
(in thousands, except per share amounts)
Operating income (loss):
Electric Utilities$202,676 $210,974 $217,677 
Gas Utilities211,157 215,889 189,971 
Corporate and Other(4,404)1,440 (1,606)
Operating Income409,429 428,303 406,042 
Interest expense, net(152,404)(143,470)(137,659)
Impairment of investment— (6,859)(19,741)
Other income (expense), net1,404 (2,293)(5,740)
Income tax (expense)(7,169)(32,918)(29,580)
Net income251,260 242,763 213,322 
Net income attributable to non-controlling interest(14,516)(15,155)(14,012)
Net income available for common stock$236,744 $227,608 $199,310 
Total earnings per share of common stock, Diluted$3.74 $3.65 $3.28 


2021 Compared to 2020

The variance to the prior year included the following:

•Electric Utilities’ operating income decreased $8.3 million primarily due to Colorado Electric’s TCJA-related bill credits to customers (which is offset by reduced tax expense), unfavorable impacts from an unplanned outage at Wygen I and higher depreciation as a result of additional plant placed in service, partially offset by increased power marketing and wholesale revenues, increased rider revenues, increased commercial and industrial demand, a prior year expense related to the early retirement of certain non-regulated generation assets, residential customer growth and increased usage, and prior year COVID-19 impacts;
•Gas Utilities’ operating income decreased $4.7 million primarily due to Winter Storm Uri costs incurred by Black Hills Energy Services, lower heating demand from milder weather (primarily in the fourth quarter of 2021), Nebraska Gas TCJA-related bill credits to customers and higher operating expenses partially offset by new rates and customer growth;
•Corporate and Other representsexpenses increased $5.8 million primarily due to higher employee costs driven by a prior year favorable true-up;
•Interest expense increased $8.9 million primarily due to higher debt balances partially offset by lower rates;
•A prior year $6.9 million pre-tax non-cash impairment in 2020 of our investment in equity securities of a privately held oil and gas company;
•Other income increased $3.7 million primarily due to lower non-service pension costs driven by a lower discount rate, lower costs for our non-qualified benefit plans which were driven by market performance and recognition of death benefits from Company-owned life insurance; and
36
•Income tax expense decreased $26 million primarily due to lower pre-tax income and a lower effective tax rate driven primarily by tax benefits from Colorado Electric and Nebraska Gas TCJA-related bill credits (which is offset by reduced revenue), flow-through tax benefits related to repairs and gain deferral and increased tax benefits from federal production tax credits associated with new wind assets.

2020 Compared to 2019

The variance to the prior year included the following:

•COVID-19 related impacts to consolidated results included $3.6 million of lower Electric and Gas Utility margin driven primarily by lower volumes and waived customer late payment fees, $2.6 million of costs due to sequestration of essential employees and $3.3 million of additional bad debt expense which were partially offset by $3.8 million of lower travel, training, and outside services related expenses;
•Electric Utilities’ operating income decreased $6.7 million due to higher depreciation and amortization expense as a result of additional plant placed in service including new wind assets, expense from the early retirement of certain non-regulated assets, lower commercial and industrial demand and COVID-19 impacts partially offset by increased revenue from our non-regulated power generation and mining businesses, benefits from the release of TCJA revenue reserves and increased rider revenues;
•Gas Utilities’ operating income increased $26 million primarily due to new customer rates in Wyoming and Nebraska and increased rider revenues, customer growth, mark-to-market gains on non-utility natural gas commodity contracts and a 2019 amortization of excess deferred income taxes partially offset by higher depreciation and amortization expense as a result of additional plant placed in service, COVID-19 impacts and unfavorable weather;
•Corporate and Other expenses decreased $3.0 million primarily due to an unallocated favorable true-up of employee costs;
•A $6.9 million pre-tax non-cash impairment in 2020 of our investment in equity securities of a privately held oil and gas company compared to a similar $20 million impairment in 2019;
•Interest expense increased $5.8 million primarily due to higher debt balances partially offset by lower rates;
•Other expense decreased $3.4 million due to the 2019 expensing of $5.4 million of development costs related to projects we no longer intend to construct partially offset by increased pension non-service costs in 2020; and
•Income tax expense increased $3.3 million primarily due to higher pre-tax income partially offset by a lower effective tax rate.


Segment Operating Results

A discussion of operating results from our business segments follows.

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, for corporatedepreciation 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 administrative activitiesfuel supply costs. However, while these fluctuating costs impact Electric and interestGas Utility margin as a percentage of revenue, they only impact total Electric and taxes that supportGas Utility margin if the costs cannot be passed through to our reportablecustomers.

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 segments. Below is a summaryincome as determined in accordance with GAAP as an indicator of operating expenses and tax (expenses) benefits included in Corporate and Otherperformance.

37
Electric Utilities

Operating results for the years ended December 31:31 for the Electric Utilities were as follows (in thousands):
202120202021 vs 2020 Variance20192020 vs 2019 Variance
Revenue:
Electric - regulated$800,747 $699,712 $101,035 $698,807 $905 
Other - non-regulated41,511 39,145 2,366 40,548 (1,403)
Total revenue842,258 738,857 103,401 739,355 (498)
Fuel and Purchased Power:
Electric - regulated244,504 136,374 108,130 143,668 (7,294)
Other - non-regulated3,514 2,198 1,316 2,305 (107)
Total fuel and purchased power248,018 138,572 109,446 145,973 (7,401)
Electric Utility margin (non-GAAP)594,240 600,285 (6,045)593,382 6,903 
Operations and maintenance260,036 265,679 (5,643)259,167 6,512 
Depreciation and amortization131,528 123,632 7,896 116,538 7,094 
Total operating expenses391,564 389,311 2,253 375,705 13,606 
Operating income$202,676 $210,974 $(8,298)$217,677 $(6,703)
(in thousands)2017Variance2016Variance2015
      
Tax Reform Impact (a)
$(28,402)$(28,402)$—
$—
$—
Tax Reform Impact - AOCI (a)
(7,000)(7,000)—
—
—
External acquisition costs, after-tax (b)
(2,489)27,231
(29,720)(23,020)(6,700)
Internal acquisition labor, after-tax (b)
(500)8,566
(9,066)(6,066)(3,000)
Discontinued operations operating expense reallocation (c)
(948)2,540
(3,488)764
(4,252)
Discontinued operations interest expense reallocation (c)
(3,215)397
(3,612)(1,369)(2,243)
Tax benefit (d)
—
(4,400)4,400
4,400
—
Other corporate expenses(55)2,761
(2,816)846
(3,662)
Net (Loss) from Corporate and Other$(42,609)$1,693
$(44,302)$(24,445)$(19,857)

____________2021 Compared to 2020

Electric Utility margin decreased over the prior year as a result of:
(a)
Represents the revaluation of deferred tax balances not attributable to our operating segments or discontinued operations due to the decrease (in the statutory Federal income tax rate as a result of the TCJA. Deferred taxes originally recorded to AOCI were also revalued to reflect the decrease in the statutory Federal income tax rate. See Notes 15 and 16 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more details.millions)
TCJA-related bill credits (a)
$(10.2)
(b)Wygen I unplanned outageAcquisition and transition costs attributed to SourceGas acquisition including incremental transaction costs consisting of professional fees, financing fees, employee-related expenses and other miscellaneous costs and internal labor costs attributable to the acquisition that would otherwise have been charged to the other business segments.
(8.5)
(c)Prior year release of TCJA revenue reservesReallocated indirect corporate operating costs and interest expenses previously allocated to BHEP which are not reclassified to discontinued operations in accordance with GAAP as they have a continuing impact on the Company. After-tax 2017 operating expenses of approximately $2.0 million were reallocated to our other business segments in 2017. See Note 21 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more details.
(2.2)
(d)WeatherWe recognized a $4.4 million tax benefit during 2016 as a result of an agreement reached with IRS Appeals relating to the release of the reserve for after-tax interest expense previously accrued with respect to the liability for uncertain tax positions involving a like-kind exchange transaction from 2008.(1.2)
Winter Storm Uri impacts (b)
(0.4)
Power marketing and wholesale5.9 
Residential customer growth and increased usage per customer5.1 
Rider recovery4.2 
Prior year COVID-19 impacts1.8 
Other(0.5)
Total decrease in Electric Utility margin$(6.0)

2017 Compared____________________
(a)    In February and April 2021, Colorado Electric delivered TCJA-related bill credits to 2016its customers. These bill credits were offset by a reduction in income tax expense and resulted in a minimal impact to Net income.

Net (loss) available for common stock for the twelve months ended December 31, 2017, was $(43) million compared to net (loss) available for common stock of $(44) million for the same period in the prior year. The variance from the prior year was due to:
Tax expense of $35 million not attributable to our operating segments reflecting the revaluation of deferred tax balances, including those originally recorded in AOCI, as a result of the TCJA;
A decrease in acquisition and transition expenses of approximately $36 million driven by lower external acquisition costs and lower internal labor attributed to the SourceGas Acquisition;
(b)    As a result of the Oil and Gas segment being reported as discontinued operations in 2017, indirect operatingWinter Storm Uri, our Electric Utilities incurred $2.1 million of incremental fuel costs that would have been chargedare not recoverable through our fuel cost recovery mechanisms which were mostly offset by $1.7 million of increased Electric Utility margin realized under Black Hills Wyoming’s Economy Energy PSA.

Operations and maintenance expense decreased primarily due to this segment were reallocateda $3.1 million prior year expense related to the early retirement of certain non-regulated generation assets, $2.7 million of lower overburden, production taxes and other business segments in 2017. These same costs in 2016 are reported as Corporateoperating expenses on decreased mining volumes, $2.0 million of prior year COVID-19 expenses and Other;$1.7 million of decreased bad debt expense associated with lower expected credit losses, partially offset by $2.7 million of increased expenses related to planned and unplanned outages at our generation facilities and $1.0 million of increased operating expenses from new wind assets.
A decrease
38
Depreciation and amortization increased primarily due to higher asset base driven by prior and current year capital expenditures.
A decrease in other corporate expenses.

20162020 Compared to 20152019


Net (loss) availableElectric Utility margin increased in 2020 over 2019 as a result of:
(in millions)
Integrated Generation (a)
$3.3 
Rider recovery2.3 
Release of TCJA revenue reserves (b)
2.2 
Transmission services1.4 
Residential customer growth0.9 
Lower commercial and industrial demand(2.7)
COVID-19 impacts (c)
(1.8)
Weather(0.3)
Other1.6 
Total increase in Electric Utility margin$6.9 
____________________
(a)    Primarily driven by revenue from Busch Ranch II, which was placed in service in November 2019.
(b)    In July 2020, regulatory proceedings resolved the last of the Company's open dockets seeking approval of its TCJA plans. As a result, the Company reversed certain TCJA-related liabilities, which resulted in an increase to Electric Utility margin of $2.2 million. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for common stockadditional details.
(c)    The impacts to Electric Utility margin from COVID-19 were primarily driven by reduced commercial volumes and waived customer late payment fees partially offset by higher residential usage.

Operations and maintenance expense increased primarily due to a $3.1 million expense related to the early retirement of certain non-regulated assets, $2.0 million of higher maintenance expense from new wind assets and $2.0 million of unfavorable net impacts from COVID-19 which included $2.6 million of expenses related to the sequestration of essential employees and $0.8 million of additional bad debt expense which were partially offset by $1.4 million of lower travel, training and outside services related expenses. Additionally, lower employee costs of $1.9 million were partially offset by $1.0 million of higher property taxes due to a higher asset base driven by capital expenditures.

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

Operating Statistics
Revenue (in thousands)Quantities Sold (MWh)
For the year ended December 31,202120202019202120202019
Residential$244,589 $221,530 $216,108 1,494,028 1,477,515 1,440,551 
Commercial275,998 239,166 246,704 2,075,690 1,974,043 2,055,253 
Industrial149,040 131,154 131,831 1,751,344 1,794,795 1,787,412 
Municipal19,092 16,860 17,206 162,903 158,222 157,298 
Subtotal Retail Revenue - Electric688,719 608,710 611,849 5,483,965 5,404,575 5,440,514 
Contract Wholesale16,128 17,847 19,078 574,137 492,637 368,360 
Off-system/Power Marketing Wholesale41,682 15,511 17,886 638,923 437,288 507,042 
Other (a)
54,218 57,644 49,994 — — — 
Total Regulated800,747 699,712 698,807 6,697,025 6,334,500 6,315,916 
Non-Regulated (b)
41,511 39,145 40,548 269,558 258,399 238,415 
Total Revenue and Quantities Sold842,258 738,857 739,355 6,966,583 6,592,899 6,554,331 
Other Uses, Losses or Generation, net (c)
475,280 406,422 393,573 
Total Energy7,441,863 6,999,321 6,947,904 
____________________
(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.

39
Electric Revenue (in thousands)Quantities Sold (MWh)
For the year ended December 31,202120202019202120202019
Colorado Electric$302,896 $252,094 $246,197 2,574,016 2,243,034 2,046,728 
South Dakota Electric319,362 280,431 288,120 2,389,407 2,363,776 2,519,448 
Wyoming Electric180,413 169,179 167,345 1,733,602 1,727,690 1,749,740 
Integrated Generation39,587 37,153 37,693 269,558 258,399 238,415 
Total Revenue and Quantities Sold$842,258 $738,857 $739,355 6,966,583 6,592,899 6,554,331 


For the year ended December 31,
Quantities Generated and Purchased by Fuel Type (MWh)202120202019
Generated:
Coal2,546,926 2,817,846 2,783,147 
Natural Gas and Oil1,817,133 1,753,568 1,535,999 
Wind842,616 614,236 406,295 
Total Generated5,206,675 5,185,650 4,725,441 
Purchased:
Coal, Natural Gas, Oil and Other Market Purchases1,866,382 1,478,536 2,019,359 
Wind368,806 335,135 203,104 
Total Purchased2,235,188 1,813,671 2,222,463 
Total Generated and Purchased7,441,863 6,999,321 6,947,904 


For the year ended December 31,
Quantities Generated and Purchased (MWh)202120202019
Generated:
Colorado Electric412,127 265,552 443,770 
South Dakota Electric1,980,660 1,901,009 1,768,456 
Wyoming Electric883,596 851,522 852,803 
Integrated Generation1,842,377 2,085,042 1,660,412 
Total Generated5,118,760 5,103,125 4,725,441 
Purchased:
Colorado Electric1,027,728 714,139 741,666 
South Dakota Electric563,603 489,457 896,901 
Wyoming Electric643,857 610,075 509,697 
Integrated Generation87,915 82,525 74,199 
Total Purchased2,323,103 1,896,196 2,222,463 
Total Generated and Purchased7,441,863 6,999,321 6,947,904 
40

For the year ended December 31,
Degree Days202120202019
ActualVariance from NormalActualVariance from NormalActualVariance from Normal
Heating Degree Days:
Colorado Electric5,023 (11)%5,103 (9)%5,453 (3)%
South Dakota Electric6,819 (5)%6,910 (3)%8,284 16%
Wyoming Electric6,702 (6)%6,771 (5)%7,406 1%
Combined (a)
5,974 (7)%6,056 (6)%6,813 5%
Cooling Degree Days:
Colorado Electric1,245 39%1,384 54%1,226 37%
South Dakota Electric827 30%682 7%404 (36)%
Wyoming Electric604 74%594 71%462 33%
Combined (a)
973 40%985 41%791 14%
____________________
(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)
202120202019
Coal (b)
86.7%94.3%92.4%
Natural gas and diesel oil (c)
95.5%84.6%90.5%
Wind95.8%95.1%89.5%
Total availability93.2%89.2%90.9%
Wind Capacity Factor34.0%31.8%30.9%
____________________
(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.
(c)    2020 included a planned outage at Cheyenne Prairie and unplanned outages at Pueblo Airport Generation and Lange CT. 2019 included planned outages at Neil Simpson CT and Lange CT.


41
Gas Utilities

Operating results for the twelve monthsyears ended December 31 2016, was $(44) million compared to net (loss) available for common stock of $(20) million for the same period in the prior year. The variance fromGas Utilities were as follows (in thousands):
202120202021 vs 2020 Variance20192020 vs 2019 Variance
Revenue:
Natural gas - regulated$1,051,610 $900,637 $150,973 $932,111 $(31,474)
Other - non-regulated services73,255 74,033 (778)77,919 (3,886)
Total revenue1,124,865 974,670 150,195 1,010,030 (35,360)
Cost of natural gas sold:
Natural gas - regulated480,293 347,611 132,682 406,643 (59,032)
Other - non-regulated services14,445 7,034 7,411 19,255 (12,221)
Total cost of natural gas sold494,738 354,645 140,093 425,898 (71,253)
Gas Utility margin (non-GAAP)630,127 620,025 10,102 584,132 35,893 
Operations and maintenance314,810 303,577 11,233 301,844 1,733 
Depreciation and amortization104,160 100,559 3,601 92,317 8,242 
Total operating expenses418,970 404,136 14,834 394,161 9,975 
Operating income$211,157 $215,889 $(4,732)$189,971 $25,918 

2021 Compared to 2020

Gas Utility margin increased over the prior year wasas a result of:
(in millions)
New rates$20.5 
Carrying costs on Winter Storm Uri regulatory asset (a)
4.0 
Increased transport and transmission2.2 
Prior year COVID-19 impacts1.8 
Mark-to-market on non-utility natural gas commodity contracts0.9 
Black Hills Energy Services Winter Storm Uri costs (b)
(8.2)
Weather(6.8)
TCJA-related bill credits (c)
(2.9)
Other(1.4)
Total increase in Gas Utility margin$10.1 
____________________
(a)    In certain jurisdictions, we have Commission approval to recover carrying costs on Winter Storm Uri regulatory assets which offset increased interest expense.
(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 is not recoverable through a regulatory mechanism.
(c)    In June 2021, Nebraska Gas 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.

Operations and maintenance expense increased primarily due to:
Anto $9.6 million of higher employee costs, $3.3 million of higher property taxes due to a higher asset base driven by prior and current year capital expenditures and $2.0 million of higher outside services expenses. The increase in acquisitionexpense was partially offset by $4.4 million of decreased bad debt expense associated with lower expected credit losses.

Depreciation and transition expenses of approximately $29 millionamortization increased primarily due to a higher asset base driven by prior and current year capital expenditures partially offset by lower depreciation rates approved in the Nebraska Gas and Colorado Gas rate reviews.
42

2020 Compared to 2019

Gas Utility margin increased in 2020 over 2019 as a result of:
(in millions)
New rates$25.4 
Customer growth - distribution5.6 
Mark-to-market on non-utility natural gas commodity contracts3.3 
Amortization of excess deferred income taxes in 20192.6 
Weather(1.8)
COVID-19 impacts (a)
(1.8)
Other2.6 
Total increase in Gas Utility margin$35.9 
____________________
(a)    The impacts to Gas Utility margin from COVID-19 were primarily driven by reduced volumes from certain transport customers and waived customer late payment fees.

Operations and maintenance expense increased primarily due to higher externalproperty taxes due to a higher asset base driven by capital expenditures. Lower employee costs were mostly offset by various other 2020 expenses. COVID-19 impacts to operations and an increasemaintenance expense included $2.5 million of additional bad debt expense which was partially offset by $2.4 million of lower travel, training, and outside services related expenses.

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


Operating Statistics
Revenue (in thousands)Quantities Sold and Transported (Dth)
For the year ended December 31,For the year ended December 31,
202120202019202120202019
Residential$613,475 $527,518 $551,701 60,080,805 61,962,171 66,956,080 
Commercial242,115 193,017 212,229 29,091,657 28,784,319 32,241,441 
Industrial33,368 24,014 24,832 6,260,235 6,881,354 6,548,023 
Other3,816 582 (1,361)— — — 
Total Distribution892,774 745,131 787,401 95,432,697 97,627,844 105,745,544 
Transportation and Transmission158,836 155,506 144,710 154,570,280 149,062,476 153,101,264 
Total Regulated1,051,610 900,637 932,111 250,002,977 246,690,320 258,846,808 
Non-regulated Services (a)
73,255 74,033 77,919 — — — 
Total Revenue and Quantities Sold$1,124,865 $974,670 $1,010,030 250,002,977 246,690,320 258,846,808 
____________________
(a)    Includes Black Hills Energy Services and non-regulated services under the Service Guard Comfort Plan, Tech Services and HomeServe.
43

Revenue (in thousands)Quantities Sold and Transported (Dth)
For the year ended December 31,For the year ended December 31,
202120202019202120202019
Arkansas$218,497 $184,849 $185,201 31,478,303 28,572,621 30,496,243 
Colorado208,019 186,085 199,369 32,247,042 32,077,083 33,908,529 
Iowa171,673 137,982 151,619 38,022,801 36,824,548 41,795,729 
Kansas121,603 101,118 105,906 34,475,799 33,732,897 32,650,854 
Nebraska273,361 246,381 255,622 81,035,572 80,202,783 81,481,192 
Wyoming131,712 118,255 112,313 32,743,460 35,280,388 38,514,261 
Total Revenue and Quantities Sold$1,124,865 $974,670 $1,010,030 250,002,977 246,690,320 258,846,808 

For the year ended December 31,
202120202019
Heating Degree DaysActualVariance From NormalActualVariance From NormalActualVariance From Normal
Arkansas (a)
3,565 (12)%3,442 (15)%3,897 (4)%
Colorado5,866 (11)%6,068 (8)%6,672 1%
Iowa6,239 (8)%6,504 (4)%7,200 6%
Kansas (a)
4,508 (8)%4,648 (5)%5,190 6%
Nebraska5,599 (9)%5,853 (5)%6,578 7%
Wyoming7,074 (7)%7,289 (4)%8,010 7%
Combined (b)
5,948 (8)%6,038 (6)%6,840 5%
____________________
(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 internal labor attributed to the SourceGas acquisition;effect from November through April.
An increase in allocated expenses from discontinued operations;
An increase of approximately $4.4 million in tax benefits;
Corporate and Other
A decrease in other corporate expenses.



Discontinued Operations

OilCorporate and GasOther operating results included in discontinued operations for the years ended December 31 were as follows (in thousands):
(in thousands)202120202021 vs 2020 Variance20192020 vs 2019 Variance
Operating income (loss)$(4,404)$1,440 $(5,844)$(1,606)$3,046 

2021 Compared to 2020

The variance in Operating income (loss) was primarily due to a prior year favorable true-up of employee costs which was allocated to our subsidiaries in the current year. This allocation was offset in our business segments and had no impact to consolidated results.

2020 Compared to 2019

The variance in Operating income (loss) was primarily due to a 2020 unallocated favorable true-up of employee costs.


44
 2017Variance2016Variance2015
      
Revenue$25,382
$(8,676)$34,058
$(9,225)$43,283
      
Operations and maintenance22,872
(4,315)27,187
(8,274)35,461
Depreciation, depletion and amortization7,521
(5,989)13,510
(15,328)28,838
Impairment of long-lived assets20,385
(86,572)106,957
(142,651)249,608
Total operating expenses50,778
(96,876)147,654
(166,253)313,907
      
Operating (loss)(25,396)88,200
(113,596)157,028
(270,624)
      
Interest income (expense), net181
(517)698
(233)931
Other income (expense), net(297)(407)110
488
(378)
Impairment of equity investments—
—
—
4,405
(4,405)
Income tax benefit (expense)8,413
(40,213)48,626
(52,191)100,817
      
(Loss) from discontinued operations available for common stock$(17,099)$47,063
$(64,162)$109,497
$(173,659)

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

(in thousands)202120202021 vs 2020 Variance20192020 vs 2019 Variance
Interest expense, net$(152,404)$(143,470)$(8,934)$(137,659)$(5,811)
Impairment of investment— (6,859)6,859 (19,741)12,882 
Other income (expense), net1,404 (2,293)3,697 (5,740)3,447 
Income tax benefit (expense)(7,169)(32,918)25,749 (29,580)(3,338)

2021 Compared to 2020

Interest expense, net

The increase in Interest expense, net was due to higher debt balances driven by the August 2021 senior unsecured notes and February 2021 term loan, partially offset by lower interest rates.

Impairment of investment

In the prior year, we recorded a pre-tax non-cash write-down of $6.9 million in our investment in equity securities of a privately held oil and gas company. The impairment was triggered by continued adverse changes in future natural gas prices and liquidity concerns at the privately held oil and gas company.

Other income (expense), net

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

Income tax benefit (expense)

For the year ended December 31, 2021, the effective tax rate was 2.8% compared to 11.9% in 2020. The lower effective tax rate is primarily due to $10 million of increased tax benefits from Colorado Electric and Nebraska Gas TCJA-related bill credits to customers (which is offset by reduced revenue), $6.6 million of increased flow-through tax benefits related to repairs and gain deferral, $4.6 million of increased tax benefits from federal production tax credits associated with new wind assets, $2.9 million of increased tax benefits from amortization of excess deferred income taxes and $2.6 million from various statutory rate changes. These current year tax benefits were greater than prior year tax benefits from one-time research and development tax credits and the reversal of accrued excess deferred income taxes as part of resolving the last of the Company’s open dockets seeking approval of its TCJA plans. See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.


2020 Compared to 2019

Interest expense, net

The increase in Interest expense, net was driven by higher debt balances partially offset by lower interest rates.

Impairment of investment

In 2020, we recorded a pre-tax non-cash write-down of $6.9 million in our investment in equity securities of a privately held oil and gas company, compared to a $20 million write-down in 2019. The impairments in both years were triggered by continued adverse natural gas prices and liquidity concerns at the privately held oil and gas company.

Other income (expense), net

The variance in Other income (expense), net was primarily due to the 2019 expensing of $5.4 million of development costs related to projects we no longer intend to construct which was partially offset by higher 2020 non-service defined benefit plan costs primarily driven by lower discount rates.
45

Income tax benefit (expense)

For the year ended December 31, 2020, the effective tax rate was 11.9% compared to 12.2% in 2019. The lower effective tax rate is primarily due to increased tax benefits from federal production tax credits associated with new wind assets and one-time research and development tax credits partially offset by a 2019 tax benefit from a federal tax loss carry-back claim including interest. See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.


Liquidity and Capital Resources

OVERVIEW

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.

In response to Winter Storm Uri, we took steps to maintain adequate liquidity to operate our businesses and fund our capital investment program as discussed in the Recent Developments section above.

The following tables providetable provides an informational summary of our financial position as of December 31 (dollars in thousands):
Financial Position Summary20212020
Cash and cash equivalents$8,921$6,356
Restricted cash and equivalents$4,889$4,383
Notes payable$420,180$234,040
Current maturities of long-term debt$—$8,436
Long-term debt (a)
$4,126,923$3,528,100
Stockholders’ equity$2,787,094$2,561,385
Ratios
Long-term debt ratio60 %58 %
Total debt ratio62 %60 %
____________________
(a)    Carrying value of long-term debt is net of deferred financing costs.


CASH FLOW ACTIVITIES

The following table summarizes our cash flows for the years ended December 31 (in thousands):
202120202019
Cash provided by (used in)
Operating activities$(64,565)$541,863 $505,513 
Investing activities$(664,230)$(761,664)$(816,210)
Financing activities$731,866 $216,882 $300,210 

46
2021 Compared to 2020

Operating Activities:

Net cash used in operating activities was $606 million higher than in 2020. The variance to the prior year was primarily attributable to:

•Cash earnings (income from continuing operations plus non-cash adjustments) were $21 million lower than prior year driven primarily by negative impacts from the unplanned outage at Wygen I, lower Electric and Gas Utility margin from Winter Storm Uri and unfavorable weather, higher operating expenses and higher interest expenses;

•Net outflows from changes in certain operating statisticsassets and liabilities were $593 million higher than prior year, primarily attributable to:

•Cash outflows increased by approximately $508 million primarily as a result of changes in our regulatory assets and liabilities primarily driven by incremental fuel, purchased power and natural gas costs due to Winter Storm Uri;

•Cash inflows decreased by approximately $71 million primarily as a result of changes in accounts receivable and other current assets driven by decreased collections of accounts receivable and increased purchases of natural gas in storage;

•Cash inflows decreased by approximately $14 million as a result of changes in accounts payable and other current liabilities driven by payment timing related to payroll taxes;

•Cash outflows decreased by $13 million due to pension contributions made in the prior year; and

•Cash inflows decreased $4.5 million for Oilother operating activities.

Investing Activities:

Net cash used in investing activities was $97 million lower than in 2020. This variance to the prior year was primarily attributable to:

•Capital expenditures of approximately $677 million in 2021 compared to $767 million in 2020. Lower current year expenditures are driven by lower programmatic safety, reliability and integrity spending at our Gas results includedUtilities segments and the prior year Corriedale wind project at our Electric Utilities segment; and

•Cash inflows increased $7.5 million for other investing activities primarily driven by the sales of transmission assets and facilities, none of which were individually significant.

Financing Activities:

Net cash provided by financing activities was $515 million higher than in discontinued operations:2020. This variance to the prior year was primarily attributable to:

•Cash inflows increased $502 million due to long and short-term borrowings in excess of repayments;

•Cash inflows increased $20 million due to higher issuances of common stock;

•Cash outflows increased $10 million due to increased dividends paid on common stock; and

•Cash outflows decreased by $3.0 million for other financing activities.


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.
47
Crude Oil and Natural Gas Production201720162015
Bbls of oil sold181,408
318,613
371,493
Mcf of natural gas sold8,700,612
9,430,288
10,057,378
Bbls of NGL sold113,233
133,304
101,684
Mcf equivalent sales10,468,458
12,141,790
12,896,440


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.

Average Price Received (a)
201720162015
Gas/Mcf$1.49
$1.36
$1.78
Oil/Bbl$46.50
$57.34
$60.69
NGL/Bbl$22.28
$12.27
$13.66
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.
__________________________
Our Revolving Credit Facility and CP Program had the following borrowings, outstanding letters of credit, and available capacity (in millions):
CurrentShort-term borrowings at
Letters of Credit (a) at
Available Capacity at
Credit FacilityExpirationCapacityDecember 31, 2021December 31, 2021December 31, 2021
Revolving Credit Facility and CP ProgramJuly 19, 2026$750 $420 $27 $303 
____________________
(a)    Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit. For more information on these letters of credit, see Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

The weighted average interest rate on short-term borrowings at December 31, 2021 was 0.30%. Short-term borrowing activity for the year ended December 31, 2021 was:
(dollars in millions)
Maximum amount outstanding (based on daily outstanding balances)$440 
(a)Average amount outstanding (based on daily outstanding balances)Net of hedge settlement gains/losses$258 

 201720162015
Depletion expense/Mcfe (a)
$0.39
$0.79
$1.91
___________
(a)Weighted average interest rateFull cost accounting was no longer applicable at November 1, 2017 and depletion was not recorded after November 1, 2017. The average depletion rate per Mcfe is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented. See Note 22 of Notes to the Consolidated Financial Statements included in this Annual Report filed on Form 10-K.0.22 %




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.
The following is
Term Loan

See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for more information related to our term loan.

Utility Money Pool

As a summaryutility 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 via a utility money pool at market-based rates. While the utility money pool may borrow funds from the Company (as ultimate parent company), the money pool arrangement does not allow loans from our utility subsidiaries to the Company (as ultimate parent company) or to non-regulated affiliates.

Long-term Debt

Our Long-term debt and associated interest payments due by year are shown below (in thousands). For more information on our long-term debt, see Note 8 of certain annual averagethe Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Payments Due by Period
20222023202420252026ThereafterTotal
Principal payments on Long-term debt including current maturities (a)
$— $525,000 $600,000 $— $300,000 $2,735,000 $4,160,000 
Interest payments on Long-term debt (a)
147,720 147,772 125,460 119,238 113,313 1,095,879 1,749,382 
____________________
(a)Long-term debt amounts do not include deferred financing costs per Mcfe ator discounts or premiums on debt. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31:31, 2021.
48
 LOE
Gathering, Compression, Processing and Transportation
Production TaxesTotal
2017 Average$0.96
$1.33
$0.23
$2.52
2016 Average$1.05
$1.20
$0.18
$2.43
2015 Average$1.03
$1.23
$0.32
$2.58


Covenant Requirements
In
The Revolving Credit Facility and Wyoming Electric’s financing agreements contain covenant requirements. We were in compliance with these covenants as of December 31, 2021. See additional information in Note 8 of the Piceance and San Juan Basins, our natural gas is transported through our own and third-party gathering systems and pipelines, forNotes 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 incur processing, gathering, compressionmay issue, from time to time, senior debt securities, subordinated debt securities, common stock, preferred stock, warrants and transportation fees.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 sales price for natural gas, condensateshelf registration expires in August 2023. Our articles of incorporation authorize the issuance of 100 million shares of common stock and NGLs is reduced for these third-party costs,25 million shares of preferred stock. As of December 31, 2021, we had approximately 65 million shares of common stock outstanding and the costno shares of operating our own gathering systems is included in operations and maintenance. The gathering, compression, processing and transportation costs shown in the tables above include amounts paidpreferred stock outstanding.

ATM

Our ATM allows us to third parties, as well as costs incurred in operations associated with our own gas gathering, compression, processing and transportation.

The ten-year gas gathering and processing contract for natural gas production in the Piceance Basin in Colorado that became effective in 2014 is part of the salesell shares of our Piceance property. We won’t have any further commitment on this contract when the Piceance asset is sold, which we expectcommon stock with an aggregate value of up to $400 million. The shares may be before March 31, 2018. This take-or-pay contract requires a minimum fee based on a throughput of 20,000 Mcf per day, regardless of the volume delivered. Gathering, compression and processing costs on a per Mcfe basis, as shown in the tables above, were higher in periods when the minimum contract requirements were not met.

2017 Comparedoffered from time to 2016

Revenue decreased primarily duetime pursuant to a decrease in production fromsales agreement dated August 4, 2020. Shares of common stock are offered pursuant to our shelf registration statement filed with the current year and prior year property sales and a decrease inSEC. During the average price received, including hedges, for crude oil sold, partially offset by an increase in the average price received, including hedges, for natural gas sold.

Operations and maintenance decreased primarily due to lower employee costs as a result of the reduction in staffing and lower production taxes and ad valorem taxes on lower production and lower revenue driven by property sales.

Depreciation, depletion and amortization decreased due to the reduction of our full cost pool resulting from the prior year ceiling test impairments and no depletion recorded on assets held for sale beginning on November 1, 2017.

Impairment of long-lived assets represents a $20 million non-cash fair value impairment of assets held for sale in 2017 compared to prior year impairments that included a $14 million write-down of depreciable properties excluded from our full-cost pool and a ceiling test write-down of $93 million.

Interest income (expense), net decreased primarily due to lower capitalized interest expense.

Income tax (expense) benefit: Each period reflects a tax benefit. The effective tax rate for 2016 was impacted by a benefit of approximately $5.8 million from additional percentage depletion deductions being claimed with respect to a change in estimate for tax purposes. Such deductions are primarily the result of a change in the application of the maximum daily limitation of 1,000 Bbls of oil equivalent allowed under the Internal Revenue Code.

2016 Compared to 2015

Revenue decreased primarily due to lower commodity prices for both crude oil and natural gas, resulting in a 24 percent decrease in the average price received, including hedges, for natural gas sold and a 6 percent decrease in the average price received, including hedges, for crude oil sold. In addition, production decreased by 6 percent as compared to prior year as we limited natural gas production to meet minimum daily quantity contractual gas processing commitments in the Piceance. Crude oil production also decreased due to non-core property sales in the fourth quarter of 2016.

Operations and maintenancedecreased primarily due to lower employee costs as a result of the reduction in staffing in the prior year, and lower production taxes and ad valorem taxes on lower revenue.



Depreciation, depletion and amortizationdecreased primarily due to a reduction of our full cost pool resulting from the ceiling test impairments incurred in current and prior years.

Impairment of long-lived assets represents a non-cash write-down in the value of our natural gas and crude oil properties driven by low natural gas and crude oil prices and movement of certain unevaluated assets into the full-cost pool. The write-down of $107 million included a $14 million write-down of depreciable properties excluded from our full-cost pool and a ceiling test write-down of $93 million. The ceiling test write-down for the 12twelve months ended December 31, 2016 used2021, we issued a total of 1,812,197 shares of common stock under the ATM for $119 million, net of $1.1 million in issuance costs.

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

Future Financing Plans

We will continue to assess debt and equity needs to support our capital investment plans and other key strategic objectives. In 2022, we expect to fund our capital plan and strategic objectives by using cash generated from operating activities, our Revolving Credit Facility and CP Program, and issuing $100 million to $120 million of common stock under the ATM.


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, 2021:
Rating AgencySenior Unsecured RatingOutlook
S&P (a)
BBB+Stable
Moody’s (b)
Baa2Stable
Fitch (c)
BBB+Stable
____________________
(a)    On October 20, 2021, S&P reported BBB+ rating and maintained a Stable outlook.
(b)    On December 20, 2021, Moody’s reported Baa2 rating and maintained a Stable outlook.
(c)    On September 17, 2021, Fitch reported BBB+ rating and maintained a Stable outlook.

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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, 2021:
Rating AgencySenior Secured Rating
S&P (a)
A
Fitch (b)
A
____________________
(a)    On July 1, 2021, S&P reported A rating.
(b)    On September 17, 2021, Fitch reported A rating.

We do not have any trigger events (i.e., an average NYMEXacceleration of repayment of outstanding indebtedness, an increase in interest costs, or the posting of additional cash collateral) tied to our stock price and have not executed any transactions that require us to issue equity based on our credit ratings.


CAPITAL REQUIREMENTS

Capital Expenditures

Capital expenditures are a substantial portion of our cash requirements each year and we continue to forecast a robust capital expenditure program during the next five years. See above in Key Elements of our Business Strategy for forecasted capital expenditure requirements. A significant portion of our capital expenditures are for safety, reliability and integrity of our system and is included in utility rate base and eligible for recovery from our utility customers with regulatory approval. Those capital expenditures also earn a rate of return authorized by the commissions in the jurisdictions in which we operate.

Our capital expenditures for the three years ended December 31 were as follows (in thousands):
202120202019
Capital Expenditures By Segment (a) :
Electric Utilities$285,770 $288,683 $316,687 
Gas Utilities383,320 449,209 512,366 
Corporate and Other10,500 17,500 20,702 
Total capital expenditures$679,590 $755,392 $849,755 
____________________
(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.

Repayments of Indebtedness

For information relating to repayments of our short- and long-term debt and associated interest payments, see the Capital Resources section above and 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 3of $2.48 per Mcf, adjustedthe Notes to $2.25 per Mcf atConsolidated Financial Statements in this Annual Report on Form 10-K.

Defined Benefit Pension Plan

We have one defined benefit pension plan, the wellhead, and $42.75 per barrel for crude oil, adjusted to $37.35 per barrel atBlack Hills Retirement Plan (Pension Plan). The unfunded status of the wellhead,Pension Plan is defined as the amount the projected benefit obligation exceeds the plan assets. The unfunded status of the plan is $20 million as of December 31, 2021, compared to $40 million as of December 31, 2020. While we do not have required contributions, we expect to make $3.9 million in contributions to our Pension Plan in 2022. See further information in Note 13 of the $250 million ceiling test write-downNotes to Consolidated Financial Statements in this Annual Report on Form 10-K.
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Common Stock Dividends

Future cash dividends, if any, will be dependent on our results of operations, financial position, cash flows, reinvestment opportunities and other factors, and will be evaluated and approved by our Board of Directors.

Additionally, there are certain statutory limitations that could affect future cash dividends paid. Federal law places limits on the ability of public utilities within a holding company structure to declare dividends. Specifically, under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries’ dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants. See additional information in Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

On January 26, 2022, our Board of Directors declared a quarterly dividend of $0.595 per share, equivalent to an annual dividend rate of $2.38 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:
202120202019
Common Stock Dividends Paid$145,023 $135,439 $124,647 
Dividend Payout Ratio61 %60 %63 %
Dividends Per Share$2.29 $2.17 $2.05 

Our three-year compound annualized dividend growth rate was 5.9%.

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 same periodfuture is dependent on the amount of the prior year which used an average NYMEX natural gasinitial transaction, changes in the market price, of $2.59 per Mcf, adjusted to $1.27 per Mcf atopen positions and the wellhead, and $50.82 per barrel for crude oil, adjusted to $44.72 per barrel at the wellhead.

Interest income (expense), netincreased primarily due to higher capitalized interest comparedamounts owed by or to the same period in the prior year.counterparty. At December 31, 2021, 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, 2021 was not material.


ImpairmentGuarantees

We provide various guarantees, which represent off-balance sheet commitments, supporting certain of equity investments represents a prior year non-cash write-down in equity investments related to interests in a pipeline and gathering system. The impairment resulted from continued declining performance, market conditions, and a change in viewour subsidiaries under specified agreements or transactions. For more information on these guarantees, see Note 3 of the economics of the facilities that we consideredNotes to be other than temporary.Consolidated Financial Statements in this Annual Report on Form 10-K.


Income tax (expense) benefit: Each period reflects a tax benefit. The effective tax rate for 2016 was impacted by a benefit of approximately $5.8 million from additional percentage depletion deductions being claimed with respect to a change in estimate for tax purposes. Such deductions are primarily the result of a change in the application of the maximum daily limitation of 1,000 Bbls of oil equivalent allowed under the Internal Revenue Code.

Critical Accounting Policies Involving Significant 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 impacts of COVID-19 and Winter Storm Uri on our critical accounting estimates including, but not limited to, collectibility of customer receivables, recoverability of regulatory assets, impairment risk of goodwill and long-lived assets, valuation of pension assets and liabilities 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 ourthe Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.


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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, 2021 and 2020, we had total regulatory assets of $797 million and $278 million, respectively, and total regulatory liabilities of $503 million and $533 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. Beginning in 2016, we changed ourOur annual goodwill impairment testing date from November 30 tois as of October 1, to better align the testing datewhich aligns with our financial planning process.   We believe that the change in the date of the annual goodwill impairment test from November 30 to October 1 is not a material change in the application of an accounting principle.  The new and old testing dates are close in proximity and both are in the fourth quarter of the year. We would not expect a materially different outcome as a result of testing on October 1 as compared to November 30. The change in assessment date does not have a material effect on the financial statements.


Accounting standards for testing goodwill for impairment require the application of either a two-step process be performedqualitative or quantitative assessment to analyze whether or not goodwill has been impaired. Goodwill is tested for impairment at the reporting unit level. The first step of this test, used to identify potential impairment, comparesUnder 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, under the first step, then the second step of thean impairment test is performedloss would be recognized in an amount equal to measurethat excess, limited to the amount of any impairment loss.goodwill allocated to that reporting unit.


Application of the goodwill impairment test requires judgment, including the identification of reporting units and determining the fair value of the reporting unit. We have determined that the reporting units for goodwill impairment testing are our operating segments, or components of an operating segment, that constitute a business for which discrete financial information


is available and for which segment managementthe Chief Operating Decision Maker (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,calculation; 2) estimates of long-term growth rates for our businesses,businesses; 3) the determination of an appropriate weighted-average cost of capital or discount rate,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 5%4.9% to 8%5.1% and long-term growth rate projections in the 1% to 2% rangeof 1.75% were utilized in the goodwill impairment test performed in the fourth quarteras of 2017.October 1, 2021. Although 1% to 2%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, as well as other improved efficiency and cost reduction initiatives.reviews. Under the market approach, we estimate fair value using multiples derived from comparable sales transactions and enterprise value to EBITDA for comparative peer companies for each respective reporting unit. These multiples are applied to operating data for each reporting unit to arrive at an indication of fair value. In addition, we add a reasonable control premium when calculating fair value utilizing the peer multiples, which is estimated as the premium that would be received in a sale in an orderly transaction between market participants.


The estimates and assumptions used in the 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, 2017, 2016,2021, 2020, and 2015,2019, there were no significant impairment losses recorded. At December 31, 2017,2021, the fair value substantially exceeded the carrying value at all reporting units.


Accounting for Oil and Gas Activities
52


We are in the process of divesting our Oil and Gas segment; therefore, we performed a fair value assessment of the assets and liabilities classified as held for sale. We evaluated our disposal groups classified as held for sale based on the lower of carrying value or fair value less cost to sell. For the assets that have not yet been sold, the estimated fair value of our oil and gas assets was determined using the market approaches. The market approach was based on our recent fourth quarter 2017 sale of our Powder River Basin assets and pending sale transactions of our other properties.

There is risk involved when determining the fair value of assets, as there may be unforeseen events and changes in circumstances and market conditions that have a material impact on the estimated amount and timing of future cash flows. In addition, the fair value of the assets and liabilities could be different using different estimates and assumptions in the valuation techniques used. We believe that the estimates used in calculating the fair value of our assets and liabilities held for sale are reasonable based on the information that was known when the estimates were made.

At December 31, 2017, the fair value of our held-for-sale assets was less than our carrying value, which required an after-tax write down of $13 million. For additional information, see Note 21 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Full Cost Method of Accounting for Oil and Gas Activities

Prior to the November 1, 2017 decision to divest our oil and gas business, we accounted for oil and gas activities under the full cost method of accounting, whereby all productive and nonproductive costs related to acquisition, exploration, development, abandonment and reclamation activities were capitalized. Accounting for oil and gas activities is subject to industry-specific rules. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonments of properties, are generally treated as adjustments to the cost of the properties with no gain or loss recognized. Net capitalized costs are subject to a ceiling test that limits such costs to the aggregate of the present value of future net revenues of proved reserves and the lower of cost or fair value of unproved properties. This method values the reserves based upon SEC-defined prices for oil and gas as of the end of each reporting period adjusted for contracted price changes. The prices, as well as costs and development capital, are assumed to remain constant for the remaining life of the properties. If the net capitalized costs exceed the full-cost ceiling, then a permanent non-cash write-down is required to be charged to earnings in that reporting period. Under these SEC-defined product prices, our net capitalized costs were more than the full cost ceiling throughout 2016 and 2015, which required after-tax write-downs of $58 million and $158 million for the years ended December 31, 2016 and 2015, respectively. Reserves in 2016 and 2015 were


determined consistent with SEC requirements using a 12-month average price calculated using the first-day-of-the-month price for each of the 12 months in the reporting period held constant for the life of the properties adjusted for contracted price changes.

Oil, Natural Gas, and Natural Gas Liquids Reserve Estimates

Estimates of our proved crude oil, natural gas and NGL reserves are based on the quantities of each that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Prior to November 1, 2017, an independent petroleum engineering company prepared reports that estimate our proved oil, natural gas and NGL reserves annually. The accuracy of any crude oil, natural gas and NGL reserve estimate is a function of the quality of available data, engineering judgment and geological interpretation. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs and work over costs, all of which may in fact vary considerably from actual results. In addition, as crude oil, natural gas and NGL prices and cost levels change from year to year, the estimate of proved reserves may also change. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves.

Estimates for our crude oil, natural gas, and NGL reserves are used throughout our financial statements. For example, since we used the unit-of-production method of calculating depletion expense, the amortization rate of our capitalized oil and gas properties incorporated the estimated unit-of-production attributable to the estimates of proved reserves. Under full-cost accounting, the net book value of our crude oil and gas properties was also subject to a “ceiling” limitation based in large part on the value of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures.

PensionLiquidity and Other Postretirement BenefitsCapital Resources


As describedOVERVIEW

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.

In response to Winter Storm Uri, we took steps to maintain adequate liquidity to operate our businesses and fund our capital investment program as discussed in the Recent Developments section above.

The following table provides an informational summary of our financial position as of December 31 (dollars in thousands):
Financial Position Summary20212020
Cash and cash equivalents$8,921$6,356
Restricted cash and equivalents$4,889$4,383
Notes payable$420,180$234,040
Current maturities of long-term debt$—$8,436
Long-term debt (a)
$4,126,923$3,528,100
Stockholders’ equity$2,787,094$2,561,385
Ratios
Long-term debt ratio60 %58 %
Total debt ratio62 %60 %
____________________
(a)    Carrying value of long-term debt is net of deferred financing costs.


CASH FLOW ACTIVITIES

The following table summarizes our cash flows for the years ended December 31 (in thousands):
202120202019
Cash provided by (used in)
Operating activities$(64,565)$541,863 $505,513 
Investing activities$(664,230)$(761,664)$(816,210)
Financing activities$731,866 $216,882 $300,210 

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2021 Compared to 2020

Operating Activities:

Net cash used in operating activities was $606 million higher than in 2020. The variance to the prior year was primarily attributable to:

•Cash earnings (income from continuing operations plus non-cash adjustments) were $21 million lower than prior year driven primarily by negative impacts from the unplanned outage at Wygen I, lower Electric and Gas Utility margin from Winter Storm Uri and unfavorable weather, higher operating expenses and higher interest expenses;

•Net outflows from changes in certain operating assets and liabilities were $593 million higher than prior year, primarily attributable to:

•Cash outflows increased by approximately $508 million primarily as a result of changes in our regulatory assets and liabilities primarily driven by incremental fuel, purchased power and natural gas costs due to Winter Storm Uri;

•Cash inflows decreased by approximately $71 million primarily as a result of changes in accounts receivable and other current assets driven by decreased collections of accounts receivable and increased purchases of natural gas in storage;

•Cash inflows decreased by approximately $14 million as a result of changes in accounts payable and other current liabilities driven by payment timing related to payroll taxes;

•Cash outflows decreased by $13 million due to pension contributions made in the prior year; and

•Cash inflows decreased $4.5 million for other operating activities.

Investing Activities:

Net cash used in investing activities was $97 million lower than in 2020. This variance to the prior year was primarily attributable to:

•Capital expenditures of approximately $677 million in 2021 compared to $767 million in 2020. Lower current year expenditures are driven by lower programmatic safety, reliability and integrity spending at our Gas Utilities segments and the prior year Corriedale wind project at our Electric Utilities segment; and

•Cash inflows increased $7.5 million for other investing activities primarily driven by the sales of transmission assets and facilities, none of which were individually significant.

Financing Activities:

Net cash provided by financing activities was $515 million higher than in 2020. This variance to the prior year was primarily attributable to:

•Cash inflows increased $502 million due to long and short-term borrowings in excess of repayments;

•Cash inflows increased $20 million due to higher issuances of common stock;

•Cash outflows increased $10 million due to increased dividends paid on common stock; and

•Cash outflows decreased by $3.0 million for other financing activities.


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.
47

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.

Our Revolving Credit Facility and CP Program had the following borrowings, outstanding letters of credit, and available capacity (in millions):
CurrentShort-term borrowings at
Letters of Credit (a) at
Available Capacity at
Credit FacilityExpirationCapacityDecember 31, 2021December 31, 2021December 31, 2021
Revolving Credit Facility and CP ProgramJuly 19, 2026$750 $420 $27 $303 
____________________
(a)    Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit. For more information on these letters of credit, see Note 188 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

The weighted average interest rate on short-term borrowings at December 31, 2021 was 0.30%. Short-term borrowing activity for the year ended December 31, 2021 was:
(dollars in millions)
Maximum amount outstanding (based on daily outstanding balances)$440 
Average amount outstanding (based on daily outstanding balances)$258 
Weighted average interest rate0.22 %

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.

Term Loan

See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for more information related to our term loan.

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 via a utility money pool at market-based rates. While the utility money pool may borrow funds from the Company (as ultimate parent company), the money pool arrangement does not allow loans from our utility subsidiaries to the Company (as ultimate parent company) or to non-regulated affiliates.

Long-term Debt

Our Long-term debt and associated interest payments due by year are shown below (in thousands). For more information on our long-term debt, see Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Payments Due by Period
20222023202420252026ThereafterTotal
Principal payments on Long-term debt including current maturities (a)
$— $525,000 $600,000 $— $300,000 $2,735,000 $4,160,000 
Interest payments on Long-term debt (a)
147,720 147,772 125,460 119,238 113,313 1,095,879 1,749,382 
____________________
(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, 2021.
48

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, 2021. 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, 2021, we had approximately 65 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. During the twelve months ended December 31, 2021, we issued a total of 1,812,197 shares of common stock under the ATM for $119 million, net of $1.1 million in issuance costs.

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

Future Financing Plans

We will continue to assess debt and equity needs to support our capital investment plans and other key strategic objectives. In 2022, we expect to fund our capital plan and strategic objectives by using cash generated from operating activities, our Revolving Credit Facility and CP Program, and issuing $100 million to $120 million of common stock under the ATM.


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, 2021:
Rating AgencySenior Unsecured RatingOutlook
S&P (a)
BBB+Stable
Moody’s (b)
Baa2Stable
Fitch (c)
BBB+Stable
____________________
(a)    On October 20, 2021, S&P reported BBB+ rating and maintained a Stable outlook.
(b)    On December 20, 2021, Moody’s reported Baa2 rating and maintained a Stable outlook.
(c)    On September 17, 2021, Fitch reported BBB+ rating and maintained a Stable outlook.

49
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, 2021:
Rating AgencySenior Secured Rating
S&P (a)
A
Fitch (b)
A
____________________
(a)    On July 1, 2021, S&P reported A rating.
(b)    On September 17, 2021, 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.

Our capital expenditures for the three years ended December 31 were as follows (in thousands):
202120202019
Capital Expenditures By Segment (a) :
Electric Utilities$285,770 $288,683 $316,687 
Gas Utilities383,320 449,209 512,366 
Corporate and Other10,500 17,500 20,702 
Total capital expenditures$679,590 $755,392 $849,755 
____________________
(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, we10-K.

Repayments of Indebtedness

For information relating to repayments of our short- and long-term debt and associated interest payments, see the Capital Resources section above and 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 plan is $20 million as of December 31, 2021, compared to $40 million as of December 31, 2020. While we do not have required contributions, we expect to make $3.9 million in contributions to our Pension Plan in 2022. See further information in Note 13 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
50

Common Stock Dividends

Future cash dividends, if any, will be dependent on our results of operations, financial position, cash flows, reinvestment opportunities and several defined post-retirement healthcare plansother factors, and non-qualified retirement plans. A Master Trust holdswill 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 assetsability of public utilities within a holding company structure to declare dividends. Specifically, under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries’ dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants. See additional information in Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

On January 26, 2022, our Board of Directors declared a quarterly dividend of $0.595 per share, equivalent to an annual dividend rate of $2.38 per share. The table below provides our dividends paid (in thousands), dividend payout ratio and dividends paid per share for the pension plan. Truststhree years ended December 31:
202120202019
Common Stock Dividends Paid$145,023 $135,439 $124,647 
Dividend Payout Ratio61 %60 %63 %
Dividends Per Share$2.29 $2.17 $2.05 

Our three-year compound annualized dividend growth rate was 5.9%.

Collateral Requirements

Our Utilities maintain wholesale commodity contracts for the funded portionpurchases and sales of electricity and natural gas which have performance assurance provisions that allow the post-retirement healthcare plans have also been established.

Accounting for pension and other postretirement benefit obligations involves numerous assumptions,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 most significant of which relate to the discount rates, health care cost trend rates, expected return on plan assets, compensation increases, retirement rates and mortality rates. The determination of our obligation and expenses for pension and other postretirement benefitsfuture 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, 2021, 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, 2021 was not material.

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.


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 determined by management and used by actuaries in calculating the amounts. Althoughthat we believe are reasonable based upon the information available. We continue to closely monitor the impacts of COVID-19 and Winter Storm Uri on our critical accounting estimates including, but not limited to, collectibility of customer receivables, recoverability of regulatory assets, impairment risk of goodwill and long-lived assets, valuation of pension assets and liabilities and contingent liabilities. These estimates and assumptions are appropriate, significant differences in our actual experience or significant changes in our assumptions may materially affect our pensionthe reported amounts of assets and other postretirement obligations and our future expense.

The pension benefit cost for 2018 for our non-contributory funded pension plan is expected to be $6.3 million compared to $2.1 million in 2017. The increase in pension benefit cost is driven primarily by a decrease inliabilities at the discount rate.

Beginning in 2016, the Company changed the method used to estimate the service and interest cost componentsdate of the net periodic pension, supplemental non-qualified defined benefitfinancial statements and other postretirement benefit costs. 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 new method used the spot yield curve approach to estimate the servicefollowing discussion of our critical accounting estimates should be read in conjunction with Note 1, “Business Description and interest costs by applying the specific spot rates along the yield curve used to determine the benefit obligations to relevant projected cash outflows. Prior to 2016, the service and interest costs were determined using a single weighted-average discount rate based on hypothetical AA Above Median yield curves used to measure the benefit obligation at the beginningSignificant Accounting Policies” of the period. The change does not affect the measurementNotes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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The Company changed to the new method to provide a more precise measure of service and interest costs by improving the correlation between the projected benefit cash flows and the discrete spot yield curve rates. The Company accounted for this change as a change in estimate prospectively beginning in 2016.



The effect of hypothetical changes to selected assumptions on the pension and other postretirement benefit plans would be as follows in thousands of dollars:
December 31,
AssumptionsPercentage Change
2017
Increase/(Decrease)
PBO/APBO (a)
2018
 Increase/(Decrease) Expense - Pretax
Pension
Discount rate (b)
 +/- 0.5(28,825)/31,769(3,477)/3,784
Expected return on assets +/- 0.5N/A(1,978)/1,981
OPEB
Discount rate (b)

 +/- 0.5(3,025)/3,299(119)/147
Expected return on assets +/- 0.5N/A(40)/40
Health care cost trend rate (b)
 +/- 1.02,968/(2,534)377/(322)
__________________________
(a)Projected benefit obligation (PBO) for the pension plan and accumulated postretirement benefit obligation (APBO) for OPEB plans.
(b)Impact on service cost, interest cost and amortization of gains or losses.

Regulation


Our utility operationsregulated Electric and Gas Utilities are subject to cost-of-service regulation with respectand 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 service area, accounting,are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of our costs, as reviewed and various other matters by stateapproved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and federal regulatory authorities. The accounting regulations provide that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effects of the manner in which independent third-party regulators establish rates. Regulatory assets generally represent incurred or accrued costs that have been deferred when future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.allowed return on invested capital at any given time.


Management continually assesses the probability of future recoveries and obligations 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.


Income Taxes

The CompanyTo some degree, each of our Electric and its subsidiaries file consolidated federal income tax returns. AsGas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs) outside of a result ofbase rate review. To the SourceGas transaction, certain acquired subsidiaries file asextent we are able to pass through such costs to our customers, and a separate consolidated group. Each tax-paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss.

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA makes broad and complex changes to the U.S. tax code, including, butstate regulatory commission subsequently determines that such costs should not limited to reducing the U.S. federal corporate tax rate from 35% to 21%. 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. 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 actionsbeen paid by the rate regulators, which could have a material impact on the Company’s future results of operations, cash flows or financial position.customers, we may be required to refund such costs.


The Company has revalued the deferred income taxes at the 21% federal tax rate asAs of December 31, 20172021 and as a result, deferred tax2020, we had total regulatory assets of $797 million and $278 million, respectively, and total regulatory liabilities were reduced by approximately $309 million. Of the $309of $503 million approximately $301and $533 million, is related to our regulated utilities and is reclassified to a regulatory liability. This regulatory liability will generally be amortized over the remaining liferespectively. See Note 2 of the related assets using the normalization principles as specifically prescribed in the TCJA.



As allowed under SEC Staff Accounting Bulletin No. 118 (SAB 118), the Company has recorded provisional income tax amounts as of December 31, 2017 for changes pursuant to the TCJA related to depreciation, for which the impacts could not be finalized upon issuance of the Company���s financial statements but reasonable estimates could be determined.  The provisional amounts may change as the Company finalizes the analysis and computations and such changes could be material to the Company’s future results of operations, cash flows or financial position.

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 charged to income in the period such determination was made. 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 in the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additionalfurther information.


Business CombinationsGoodwill


We record acquisitionsperform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in accordancecircumstances that indicate that the asset might be impaired. Our annual goodwill impairment testing date is as of October 1, which aligns with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recordedour 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 their estimated fair values on the acquisition date. The excess ofreporting unit level. Under either the purchase price overqualitative or quantitative assessment, the estimated fair valuesvalue of a reporting unit is compared with its carrying amount, including goodwill. If the carrying amount exceeds fair value, then an impairment loss would be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit.

Application of the net tangiblegoodwill impairment test requires judgment, including the identification of reporting units and net intangible assets acquired is recorded as goodwill. The application of ASC 805, Business Combinations requires management to make significant estimates and assumptions in the determination ofdetermining the fair value of assets acquiredthe 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 liabilities assumed in order to properly allocate purchase price consideration between goodwill and assets that are depreciated and amortized. Pertaining to our 2016 acquisition of SourceGas, substantially all of SourceGas’ operations are subject tofor which the rate-setting authority of state regulatory commissions, and are accounted for in accordance with GAAP for regulated operations. SourceGas’ assets and liabilities subject to rate setting provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such,Chief Operating Decision Maker (CODM) regularly reviews the operating results. We estimate the fair value of theseour 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 liabilities equal their historical net book values.energy industries. Varying by reporting unit, weighted average cost of capital in the range of 4.9% to 5.1% and long-term growth rate projections of 1.75% were utilized in the goodwill impairment test performed as of October 1, 2021. 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.


OurThe estimates and assumptions used in the impairment assessments are based on historical experience,available market information obtained from the managementand we believe they are reasonable. However, variations in any of the acquired companiesassumptions could result in materially different calculations of fair value and when appropriate, include assistance from independent third-party appraisal firms. These estimates are inherently uncertaindeterminations of whether or not an impairment is indicated. For the years ended December 31, 2021, 2020, and unpredictable. In addition, unanticipated events or circumstances may occur which may affect2019, there were no impairment losses recorded. At December 31, 2021, the accuracy or validityfair value substantially exceeded the carrying value at all reporting units.

52

Liquidity and Capital Resources


OVERVIEW


Our company requires significant cash to support and grow our businesses. Our predominant sourceprimary sources of cash is supplied byare generated from our operationsoperating activities, five-year Revolving Credit Facility, CP Program, ATM and supplemented with corporate financings.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. As discussed in more detail below under income taxes, we expect an increase in working capital requirements as a result of complying with the TCJA and the impact of providing TCJA benefits to customers.


The most significant uses of cash are our capital expenditures, the purchase of natural gas for our Gas Utilities and our Power Generation segment, as well as the payment of dividends to our shareholders. We experience significant cash requirements during peak months of the winter heating season due to higher natural gas consumption, and during periods of high natural gas prices, as well asand during the summer construction season.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.



In response to Winter Storm Uri, we took steps to maintain adequate liquidity to operate our businesses and fund our capital investment program as discussed in the Recent Developments section above.


The following table provides an informational summary of our financial position as of December 31 (dollars in thousands):

Financial Position Summary20212020
Cash and cash equivalents$8,921$6,356
Restricted cash and equivalents$4,889$4,383
Notes payable$420,180$234,040
Current maturities of long-term debt$—$8,436
Long-term debt (a)
$4,126,923$3,528,100
Stockholders’ equity$2,787,094$2,561,385
Ratios
Long-term debt ratio60 %58 %
Total debt ratio62 %60 %
____________________
(a)    Carrying value of long-term debt is net of deferred financing costs.


CASH FLOW ACTIVITIES
Financial Position Summary20172016
Cash and cash equivalents$15,420
$13,518
Restricted cash and equivalents$2,820
$2,274
Short-term debt, including current maturities of long-term debt$217,043
$102,343
Long-term debt (a)
$3,109,400
$3,211,189
Stockholders’ equity$1,708,974
$1,614,639
   
Ratios  
Long-term debt ratio64%67%
Total debt ratio66%67%

______________
(a)Carrying amount of long-term debt is net of deferred financing costs.

Significant Factors Affecting Liquidity

Although we believe we have sufficient resources to fundThe following table summarizes our cash requirements, there are many factors with the potential to influence our cash flow position, including seasonality, commodity prices, significant capital projects and acquisitions, requirements imposed by state and federal agencies and economic market conditions. We have implemented risk mitigation programs, where possible, to stabilize cash flow. However, the potential for unforeseen events affecting cash needs will continue to exist.

Our Utilities maintain wholesale commodity contractsflows 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, 2017, we had sufficient liquidity to cover collateral that could be required to be posted under these wholesale commodity contracts.

Weather Seasonality, Commodity Pricing and Associated Hedging Strategies

We manage liquidity needs through hedging activities, primarily in connection with seasonal needs of our utility operations (including seasonal peaks in fuel requirements), interest rate movements and commodity price movements.

Utility Factors

Our cash flows, and in turn liquidity needs in many of our regulated jurisdictions, can be subject to fluctuations in weather and commodity prices. Since weather conditions are uncontrollable, we have implemented commission-approved natural gas hedging and storage programs in many of our regulated jurisdictions to mitigate significant changes in natural gas commodity pricing. We target hedging of approximately 40% to 70% of our forecasted natural gas supply using options, futures and basis swaps.

Interest Rates

Several of our debt instruments have a variable interest rate component which can change significantly depending on the economic climate. We don’t have any interest rate swap agreements at December 31, 2017; 84% of our interest rate exposure has been mitigated through fixed interest rates.



Federal and State Regulations

Federal

We are structured as a utility holding company which owns several regulated utilities. Within this structure, we are subject to various regulations by our commissions that can influence our liquidity. As an example, the issuance of debt by our regulated subsidiaries and the use of our utility assets as collateral generally require the prior approval of the state regulators in the state in which the utility assets are located. Furthermore, as a result of our holding company structure, our right as a common shareholder to receive assets of any of our direct or indirect subsidiaries upon a subsidiary's liquidation or reorganization is subordinate to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders.

Income Tax

The TCJA legislation was signed into law on December 22, 2017. The new tax law required revaluation of federal deferred tax assets and liabilities using the new lower corporate tax rate of 21%. As a result of the revaluation, deferred tax assets and liabilities were reduced by approximately $309 million. Of the $309 million, approximately $301 million is related to our regulated utilities and is reclassified to a regulatory liability. This regulatory liability will generally be amortized over the remaining life of the related assets as specifically prescribed in the TCJA.

We are working with utility regulators in each of the states we serve to provide benefits from tax reform to our customers. We expect an increase in working capital requirements as a result of complying with the TCJA and the impact of providing TCJA benefits to customers. We estimate the lower tax rate will negatively impact the company’s cash flows by approximately $35 million to $45 million annually for the next several years.

Acceleration of depreciation for tax purposes, including 50% bonus depreciation, was previously available for certain property placed in service through September 27, 2017. The TCJA, signed into law on December 22, 2017, enacted 100% bonus depreciation generally to qualifying property acquired and placed in service after September 27, 2017 and before January 1, 2023. After 2022, bonus depreciation would reduce 20% per year with 80% bonus depreciation generally to qualifying property placed in serving during 2023, 60% bonus depreciation generally to qualifying property placed in service during 2024, 40% bonus depreciation generally to qualifying property placed in service during 2025 and 20% generally to qualifying property placed in service after December 31, 2025 and before January 1, 2027. The provision would expand the property that is eligible for this immediate expensing by repealing the requirement that the original use of the property begin with the taxpayer. Instead, the property would be eligible for the additional depreciation if it is the taxpayer’s first use. Under the provision, qualified property eligible for bonus depreciation, including immediate expensing, would not include any property used by a regulated public utility company or any property used in a real property trade or business. These depreciation provisions resulted in cash tax benefits for BHC as indicated in the table below:
(in millions)201720162015
Tax benefit$37$81$33

In addition, bonus depreciation will apply to qualifying property whose construction and completion period encompasses multiple tax years. The exception being with respect to costs that would be incurred in 2027 when, under current law, bonus depreciation is scheduled to expire.

The effect of additional depreciation deductions as a result of bonus depreciation will serve to reduce taxable income and contribute to extending the tax loss carryforwards from being fully utilized until 2022 based on current projections.

See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.



CASH GENERATION AND CASH REQUIREMENTS

Cash Generation

Our primary sources of cash are generated from operating activities, our five-year Revolving Credit Facility expiring August 9, 2021, our CP Program and our ability to access the public and private capital markets through debt and securities offerings when necessary.

Cash Collateral

Under contractual agreements and exchange requirements, BHC or its subsidiaries have collateral requirements, which if triggered, require us to post cash collateral positions with the counterparty to meet these obligations.

We have posted the following amounts of cash collateral with counterparties atyears ended December 31 (in thousands):
202120202019
Cash provided by (used in)
Operating activities$(64,565)$541,863 $505,513 
Investing activities$(664,230)$(761,664)$(816,210)
Financing activities$731,866 $216,882 $300,210 

46
Purpose of Cash Collateral20172016
Natural Gas Futures and Basis Swaps Pursuant to Utility Commission Approved Hedging Programs$7,694
$12,722
Natural Gas Over-the-Counter Swaps Pursuant to Master Agreements for Derivative Instruments$562
$—
2021 Compared to 2020


Operating Activities:
DEBT

Net cash used in operating activities was $606 million higher than in 2020. The variance to the prior year was primarily attributable to:

•Cash earnings (income from continuing operations plus non-cash adjustments) were $21 million lower than prior year driven primarily by negative impacts from the unplanned outage at Wygen I, lower Electric and Gas Utility margin from Winter Storm Uri and unfavorable weather, higher operating expenses and higher interest expenses;

•Net outflows from changes in certain operating assets and liabilities were $593 million higher than prior year, primarily attributable to:

•Cash outflows increased by approximately $508 million primarily as a result of changes in our regulatory assets and liabilities primarily driven by incremental fuel, purchased power and natural gas costs due to Winter Storm Uri;

•Cash inflows decreased by approximately $71 million primarily as a result of changes in accounts receivable and other current assets driven by decreased collections of accounts receivable and increased purchases of natural gas in storage;

•Cash inflows decreased by approximately $14 million as a result of changes in accounts payable and other current liabilities driven by payment timing related to payroll taxes;

•Cash outflows decreased by $13 million due to pension contributions made in the prior year; and

•Cash inflows decreased $4.5 million for other operating activities.

Investing Activities:

Net cash used in investing activities was $97 million lower than in 2020. This variance to the prior year was primarily attributable to:

•Capital expenditures of approximately $677 million in 2021 compared to $767 million in 2020. Lower current year expenditures are driven by lower programmatic safety, reliability and integrity spending at our Gas Utilities segments and the prior year Corriedale wind project at our Electric Utilities segment; and

•Cash inflows increased $7.5 million for other investing activities primarily driven by the sales of transmission assets and facilities, none of which were individually significant.

Financing TransactionsActivities:

Net cash provided by financing activities was $515 million higher than in 2020. This variance to the prior year was primarily attributable to:

•Cash inflows increased $502 million due to long and Short-Term Liquidityshort-term borrowings in excess of repayments;


Our principal sources•Cash inflows increased $20 million due to meet day-to-day operating cash requirements are cash from operations, our CP Programhigher issuances of common stock;

•Cash outflows increased $10 million due to increased dividends paid on common stock; and our corporate Revolving Credit Facility.


•Cash outflows decreased by $3.0 million for other financing activities.


CAPITAL RESOURCES

Short-term Debt

Revolving Credit Facility and CP Program


On August 9, 2016, we amended and restated our corporateWe have a $750 million Revolving Credit Facility to increase total commitments to $750 million from $500 million and extended the term through August 9, 2021that matures on July 19, 2026 with two one-year extension options.options (subject to consent from lenders). This facility is similar to the former agreement, which includes an accordion feature that allows us to increase total commitments up to $1.0 billion with the consent of the administrative agent, andthe issuing agents to increase total commitments of the facility to up to $1 billion. Borrowings continue to be available underand each bank increasing or providing 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 most favorable Corporate credit rating from S&P or Moody’s for our unsecured debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.250%, 1.250%, and 1.250%, respectively, at December 31, 2017. A 0.200% commitment fee is charged on the unused amount of the Revolving Credit Facility.

On December 22, 2016, we implementednew 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 notes issued under the CP Program may have maturities not to exceed 397 days from the date
47

Our Revolving Credit Facility had the following borrowings, outstanding letters of credit, and available capacity (in millions):
Contents
  CurrentRevolver Borrowings atCP Program Borrowings atLetters of Credit atAvailable Capacity at
Credit FacilityExpirationCapacityDecember 31, 2017December 31, 2017December 31, 2017December 31, 2017
Revolving Credit FacilityAugust 9, 2021$750
$—
$211
$27
$512



The weighted average interest rate on CP Program borrowings at December 31, 2017 was 1.76%. Revolving Credit Facility and CP Program financing activity for the twelve months ended December 31, 2017 was (dollars in millions):
 For the Twelve Months Ended December 31, 2017
Maximum amount outstanding - commercial paper (based on daily outstanding balances)$282
Maximum amount outstanding - revolving credit facility (based on daily outstanding balances) (a)
$97
Average amount outstanding - commercial paper (based on daily outstanding balances)$139
Average amount outstanding - revolving credit facility (based on daily outstanding balances) (a)
$55
Weighted average interest rates - commercial paper1.34%
Weighted average interest rates - revolving credit facility (a)
2.07%
__________
(a)Averages for the Revolving Credit Facility are for the first 29 days of the year after which all borrowings were through the CP Program.

The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on certain liens, restrictions on certain transactions, and maintenance of a certain Consolidated Indebtedness to Capitalization Ratio. Under the Revolving Credit Facility, our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness, which includes letters of credit, certain guarantees issued and excludes RSNs by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interests in subsidiaries and includes the aggregate outstanding amount of the RSNs. 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 these covenants as of December 31, 2017.


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.


Capital ResourcesThe 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.


Our principal sources forRevolving Credit Facility and CP Program had the following borrowings, outstanding letters of credit, and available capacity (in millions):
CurrentShort-term borrowings at
Letters of Credit (a) at
Available Capacity at
Credit FacilityExpirationCapacityDecember 31, 2021December 31, 2021December 31, 2021
Revolving Credit Facility and CP ProgramJuly 19, 2026$750 $420 $27 $303 
____________________
(a)    Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our long-term capital needs have been issuancescorporate Revolving Credit. For more information on these letters of long-term debt securities bycredit, see Note 8 of the Company and its subsidiaries along with proceeds obtained from public and private offerings of equity and proceeds from our ATM equity offering program.Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.


Financing Activities

Financing activities for 2017 consisted ofThe weighted average interest rate on short-term borrowings fromat December 31, 2021 was 0.30%. Short-term borrowing activity for the year ended December 31, 2021 was:
(dollars in millions)
Maximum amount outstanding (based on daily outstanding balances)$440 
Average amount outstanding (based on daily outstanding balances)$258 
Weighted average interest rate0.22 %

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.

Term Loan

See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for more information related to our term loan.

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 also made principalhave 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 via a utility money pool at market-based rates. While the utility money pool may borrow funds from the Company (as ultimate parent company), the money pool arrangement does not allow loans from our utility subsidiaries to the Company (as ultimate parent company) or to non-regulated affiliates.

Long-term Debt

Our Long-term debt and associated interest payments of $50 million each on May 16, 2017 and July 17, 2017due by year are shown below (in thousands). For more information on our Corporate term loan due August 9, 2019. Short-term borrowings from our CP program were usedlong-term debt, see Note 8 of the Notes to fund theConsolidated Financial Statements in this Annual Report on Form 10-K.

Payments Due by Period
20222023202420252026ThereafterTotal
Principal payments on Long-term debt including current maturities (a)
$— $525,000 $600,000 $— $300,000 $2,735,000 $4,160,000 
Interest payments on Long-term debt (a)
147,720 147,772 125,460 119,238 113,313 1,095,879 1,749,382 
____________________
(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 Corporate term loan. On August 4, 2017, we renewed the ATM equity offering program which reset the sizeapplicable rates as of December 31, 2021.
48

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, 2021. 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, 2021, we had approximately 65 million shares of common stock outstanding and no shares of preferred stock outstanding.

ATM

Our ATM equity offering programallows us to sell shares of our common stock with an aggregate value of up to $300$400 million. We did not issue anyThe 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. During the twelve months ended December 31, 2021, we issued a total of 1,812,197 shares of common stock under ourthe ATM equity offering program during 2017.

Financing activities from the prior year consisted of completing the permanent financing for the SourceGas Acquisition. In addition to the net proceeds of $536 million from our November 2015 equity issuances, we completed the Acquisition financing with $546 million of net proceeds from our January 2016 debt offering. We also refinanced the long-term debt assumed with the SourceGas Acquisition primarily through $693 million of net proceeds from our August 19, 2016 debt offerings. In addition to our debt refinancings, we issued a total of 1.97 million shares of common stock throughout 2016 for net proceeds of approximately $119 million, through our ATM equity offering program, and sold a 49.9% noncontrolling interest in Black Hills Colorado IPP for $216net of $1.1 million in April 2016.issuance costs.



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


Future Financing Plans


We anticipate the following financing activities:

Remarketing the junior subordinated notes maturing in 2018;

Evaluating an extension ofwill continue to assess debt and equity needs to support our capital investment plans and other key strategic objectives. In 2022, we expect to fund our capital plan and strategic objectives by using cash generated from operating activities, our Revolving Credit Facility and CP program;Program, and

Evaluating refinancing options for term loan and short-term borrowings under our Revolving Credit Facility and CP program.

Cross-Default Provisions

Our $300 issuing $100 million and $19to $120 million corporate term loans contain cross-default provisions that could result in a default under such agreements if BHC or its material subsidiaries failed to make timely payments of debt obligations or triggered other default provisions under any debt agreement totaling, in the aggregate principal amount of $50 million or more that permits the acceleration of debt maturities or mandatory debt prepayment. Our Revolving Credit Facility contains the same provisions and a threshold principal amount is $50 million.

The Revolving Credit Facility prohibits us from paying cash dividends if we are in default or if paying dividends would cause us to be in default.

Equity

Based on our current capital spending forecast, we do not anticipate the need to further access the equity capital markets in the next three years.

Shelf Registration

We have an effective automatic 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. We renewed our shelf registration on August 4, 2017. 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, 2017, we had approximately 55 million shares of common stock outstanding and no shares of preferred stock outstanding.

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.

On January 31, 2018, our Board of Directors declared a quarterly dividend of $0.475 per share or an annualized equivalent dividend rate of $1.90 per share. The table below provides our historical three-year dividend payout ratio and dividends paid per share:

 201720162015
Dividend Payout Ratio50%65%52%
Dividends Per Share$1.81$1.68$1.62

Our three-year compound annualized dividend growth rate was 5.1% and all dividends were paid out of available operating cash flows.



Dividend Restrictions

As a utility holding company which owns several regulated utilities, we are subject to various regulations that could influence our liquidity. For example, the issuance of debt by our utility subsidiaries (including the ability of Black Hills Utility Holdings to issue debt) and the use of our utility assets as collateral generally requires the prior approval of the state regulators in the state in which the utility assets are located. As a result of our holding company structure, our right as a common shareholder to receive assets from any of our direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders.
Our credit facilities and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be deemed to have occurred if we did not comply with certain financial or other covenants. At December 31, 2016, our Revolving Credit Facility and Corporate term loans included a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.70 to 1.00, changing to 0.65 to 1.00 in subsequent quarters, beginning March 31, 2017. As of December 31, 2017, we were in compliance with these covenants.

In addition, the agreements governing our equity units generally restrict the payment of cash dividends at any time we have exercised our right to defer payment of contract adjustment payments under the purchase contracts or interest payments under the junior subordinated notes included in such equity units. Moreover, holders of purchase contracts will be entitled to additional shares of our common stock upon settlement of the purchase contracts if we pay regular quarterly dividends in excess of $0.405 per share while the purchase contracts are outstanding. As of December 31, 2017, we haven’t exercised our right to defer payment. On January 31, 2018, we declared a quarterly dividend of $0.475 per share.ATM.


Covenants within Wyoming Electric's financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of no more than .60 to 1.00. Our utilities in Arkansas, Colorado, Iowa, Kansas and Nebraska have regulatory agreements in which they cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40% of their total capitalization; and neither Black Hills Utility Holdings nor its utility subsidiaries can extend credit to the Company except in the ordinary course of business and upon reasonable terms consistent with market terms. Additionally, our utility subsidiaries may generally be limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may have further restrictions under the Federal Power Act. As of December 31, 2017, the restricted net assets at our Electric and Gas Utilities were approximately $257 million.

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 utility subsidiaries 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 via a utility money pool at market-based rates (1.962% at December 31, 2017). 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.

At December 31, money pool balances included (in thousands):
 
Borrowings From
(Loans To) Money Pool Outstanding
Subsidiary20172016
Black Hills Utility Holdings$35,693
$52,370
South Dakota Electric13,397
(28,409)
Wyoming Electric15,290
20,737
Total Money Pool borrowings from Parent$64,380
$44,698

CASH FLOW ACTIVITIES

The following table summarizes our cash flows (in thousands):
 201720162015
Cash provided by (used in)   
Operating activities$428,261
$320,479
$424,383
Investing activities$(317,664)$(1,588,742)$(476,389)
Financing activities$(108,695)$840,998
$483,702

2017 Compared to 2016

Operating Activities:

Net cash provided by operating activities was $108 million higher than in 2016. The variance to the prior year was primarily attributable to:

Cash earnings (income from continuing operations plus non-cash adjustments) were $68 million higher than prior year;

Net outflow from operating assets and liabilities was $16 million lower than prior year, primarily attributable to:

Cash outflows decreased by approximately $4.8 million as a result of changes in accounts payable and accrued liabilities driven by changes in working capital requirements;

Cash outflows decreased by approximately $20 million compared to the prior year as a result of lower accounts receivable due to warmer weather partially offset by higher natural gas inventory; and

Cash outflows increased by approximately $9.5 million primarily as a result of changes in our current regulatory assets and liabilities driven by differences in fuel cost adjustments and commodity price impacts compared to the same period in the prior year;

Cash outflows decreased by approximately $29 million as a result of a prior year interest rate swap settlement;

Cash outflows increased by approximately $14 million due to additional pension contributions made in the current year;

Cash outflows increased approximately $7.8 million for other operating activities compared to the prior year; and

Cash inflows increased approximately $17 million due to operating activities of discontinued operations.

Investing Activities:

Net cash used in investing activities was $318 million in 2017, compared to net cash used in investing activities of $1.6 billion in 2016 for a variance of $1.3 billion. This variance was primarily due to:

The prior year’s cash outflows included approximately $1.1 billion for the acquisition of SourceGas, net of $760 million long-term debt assumed (see Note 2 in Item 8 of Part II of this Annual Report on Form 10-K);

Capital expenditures of approximately $326 million in 2017 compared to $455 million in 2016. The $129 million variance to the prior year was due primarily to higher prior year capital expenditures at our Electric Utilities from generation investments at Colorado Electric; and

Cash inflows increased approximately $16 million due to investing activities of discontinued operations.



Financing Activities:

Net cash used in financing activities was $109 million in 2017, an increase of $950 million from 2016 primarily due to the following:

Long-term borrowings decreased by $1.8 billion due to the 2016 financings which consisted of $693 million of net proceeds from the August 19, 2016 public debt offering used to refinance the debt assumed in the SourceGas Acquisition, $500 million of proceeds from the August 9, 2016 term loan, $546 million of net proceeds from our January 13, 2016 public debt offering used to partially finance the SourceGas Acquisition and proceeds from a $29 million term loan used to fund the early settlement of a gas gathering contract;

Payments on long-term debt decreased by $1.1 billion due to the 2016 refinancing of the $760 million of long-term debt assumed in the SourceGas Acquisition and lower current year payments on term loans, $106 million paid on term loans in 2017 compared to $400 million paid on term loans in 2016;

Proceeds of $216 million from the sale of a 49.9% noncontrolling interest of Black Hills Colorado IPP that took place in 2016 (see Note 12 in Item 8 of Part II of this Annual Report on Form 10-K);

Proceeds from common stock issuances decreased by $117 million primarily from issuing common stock under our ATM equity offering program in 2016;

Net short-term borrowings increased by $95 million primarily due to CP borrowings used to pay down long-term debt;

Cash dividends on common stock of $97 million were paid in 2017 compared to $88 million paid in 2016;

Distributions to noncontrolling interests increased by $8.8 million compared to prior year; and

Cash outflows for other financing activities decreased by approximately $16 million driven primarily by higher financing costs incurred in the prior year from the 2016 debt offerings and refinancings compared to a payment of $5.6 million for a redeemable noncontrolling interest in March 2017.

2016 Compared to 2015

Operating Activities:

Net cash provided by operating activities was $104 millionlower than in 2015 primarily attributable to the SourceGas acquisition and the following:

Cash earnings (income from continuing operations plus non-cash adjustments) were $62 million higher than prior year.

Net outflow from operating assets and liabilities was $59 million higher than prior year, primarily attributable to:

Cash outflows increased by approximately $66 million compared to the prior year as a result of higher materials, supplies and fuel and higher accounts receivable partially due to colder weather and higher natural gas volumes sold;

Cash outflows increased by approximately $34 million primarily as a result of changes in our current regulatory assets and liabilities driven by differences in fuel cost adjustments and commodity price impacts compared to the same period in the prior year;

Cash outflows decreased by approximately $42 million as a result of changes in accounts payable and accrued liabilities driven primarily by acquisition and transition costs, partially offset by an increase in accrued interest;

Cash outflows increased by approximately $29 million as a result of interest rate swap settlements;

Cash outflows increased by $4.0 million due to pension contributions;

Cash outflows decreased approximately $8.4 million for other operating activities compared to the prior year; and



Cash inflows decreased approximately $83 million due to operating activities of discontinued operations.

Investing Activities:

Net cash used in investing activities was $1.6 billion in 2016, which was an increase in outflows of $1.1 billion from 2015 primarily due to the following:

Cash outflows of $1.1 billion for the acquisition of SourceGas, net of $11 million cash received from a working capital adjustment and $760 million of long term debt assumed (see Note 2 in Item 8 of Part II of this Annual Report on Form 10-K);

In 2016, we had higher capital expenditures of $189 million primarily at our Electric Utilities and Gas Utilities, driven by 2016 wind and natural gas generation additions at our Electric Utilities, and additional capital at our acquired SourceGas Utilities;

In 2015, we acquired the net assets of two natural gas utilities for $22 million; and

Cash outflows decreased approximately $179 million due to investing activities of discontinued operations.

Financing Activities:

Net cash provided by financing activities was $841 million in 2016, an increase of $357 million from 2015 primarily due to the following:

Proceeds of $216 million from the sale of a 49.9% noncontrolling interest of Black Hills Colorado IPP (see Note 12 in Item 8 of Part II of this Annual Report on Form 10-K);

Long-term borrowings increased due to the $693 million of net proceeds from our August 19, 2016 public debt offering used to refinance the debt assumed in the SourceGas Acquisition, the $500 million of proceeds from our new term loan on August 9, 2016 used to pay off existing debt, the $546 million of net proceeds from our January 13, 2016 public debt offering used to partially finance the SourceGas Acquisition, and proceeds from a $29 million term loan used to fund the early settlement of a gas gathering contract, compared to proceeds of $300 million from long-term borrowings from a term loan in the prior year;

Payments on long term borrowings increased due to payments made in the current year to refinance the $760 million of long-term debt assumed in the SourceGas Acquisition and $404 million of current year payments made on term loans compared to the payment of $275 million made as part of a term-loan refinancing in the prior year;

In 2015, we received net proceeds of $290 million from the issuance of our RSNs;

Proceeds of $120 million primarily from issuing common stock under our ATM equity offering program. 2015 included net proceeds from common stock issuances of $246 million;

Net short-term borrowings under the revolving credit facility for the year ended December 31, 2016 were $18 million higher than the prior year primarily due to higher working capital requirements in the current year;

Distributions to noncontrolling interests of $9.6 million;

Cash outflows for other financing activities increased by approximately $14 million driven primarily by approximately $22 million of financing costs and make whole payments made in 2016 compared to $7 million of bridge facility fees paid in 2015; and

Cash dividends on common stock of $88 million were paid in 2016 compared to $73 million paid in 2015.



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 three years.

Historically, a significant portion of our capital expenditures relate primarily to assets that may be included in utility rate base, and if considered prudent by regulators, can be recovered from our utility customers. Those capital expenditures also earn a rate of return authorized by the commissions in the jurisdictions in which we operate and are subject to rate agreements. During 2017, our Electric Utilities’ capital expenditures included improvements to generating stations, transmission and distribution lines. Capital expenditures associated with our Gas Utilities are primarily to improve or expand the existing gas distribution network. We believe that cash generated from operations and borrowing on our CP Program and our existing Revolving Credit Facility will be adequate to fund ongoing capital expenditures.

Historical Capital Requirements

Our primary capital requirements for the three years ended December 31 were as follows (in thousands):
 2017 2016 2015
Property additions: (a)
     
Electric Utilities$138,060
 $258,739
 $171,897
Gas Utilities184,389
 173,930
 99,674
Power Generation1,864
 4,719
 2,694
Mining6,708
 5,709
 5,767
Corporate and Other6,668
 17,353
 9,864
Capital expenditures before discontinued operations337,689
 460,450
 289,896
Discontinued operations23,222
 6,669
 168,925
Total capital expenditures360,911
 467,119
 458,821
Common stock dividends96,744
 87,570
 72,604
Maturities/redemptions of long-term debt105,743
 1,164,308
 275,000
 $563,398
 $1,718,997
 $806,425
____________________________
(a)Includes accruals for property, plant and equipment.

Forecasted Capital Expenditure Requirements

Our primary capital expenditure requirements for the three years ended December 31 are expected to be as follows (in thousands):
 2018 2019 2020
      
Electric Utilities$149,000
 $193,000
 $141,000
Gas Utilities263,000
 279,000
 245,000
Power Generation2,000
 14,000
 5,000
Mining7,000
 7,000
 7,000
Corporate and Other10,000
 13,000
 8,000
 $431,000
 $506,000
 $406,000

We continue to evaluate potential future acquisitions and other growth opportunities which are dependent upon the availability of economic opportunities and, as a result, capital expenditures may vary significantly from the estimates identified above.



CREDIT RATINGS AND COUNTERPARTIES


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. The inabilityIn order to operate and grow our business, we need to consistently maintain the ability to raise capital on favorable terms could negatively affect the Company’s ability to maintain or expand its businesses.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. BHC notesWe 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, 2017:
2021:
Rating AgencySenior Unsecured RatingOutlook
S&P (a)
BBBBBB+Stable
Moody’s (b)
Baa2Stable
Fitch (c)
BBB+Stable
__________
(a)On July 21, 2017, S&P affirmed BBB rating and maintained a Stable outlook.
(b)
On December 12, 2017, Moody's affirmed our Baa2 rating and maintained a Stable outlook.
(c)On October 4, 2017, Fitch affirmed BBB+ rating and maintained a Stable outlook.

____________________
Our(a)    On October 20, 2021, S&P reported BBB+ rating and maintained a Stable outlook.
(b)    On December 20, 2021, Moody’s reported Baa2 rating and maintained a Stable outlook.
(c)    On September 17, 2021, Fitch reported BBB+ rating and maintained a Stable outlook.

49
Certain fees and interest paymentsrates under various corporate debt agreementsour Revolving Credit Facility are based on our credit ratings at all three rating agencies. If all of our ratings are at the higher credit ratingsame 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 Moody’s. If either S&P or Moody’s downgradeddowngrades our senior unsecured debt, we maywill be required to pay additionalhigher fees and incur higher interest rates under current bank credit agreements.our Revolving Credit Facility.


The following table represents the credit ratings of South Dakota Electric at December 31, 2017:
2021:
Rating AgencySenior Secured Rating
S&P(a)
A-A
Moody’s
Fitch (b)
A1
FitchA

____________________
(a)    On July 1, 2021, S&P reported A rating.
(b)    On September 17, 2021, 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 or other trigger events.ratings.





CONTRACTUAL OBLIGATIONS AND OTHER COMMITMENTS

CAPITAL REQUIREMENTS
Contractual
Capital Expenditures

Capital expenditures are a substantial portion of our cash requirements each year and we continue to forecast a robust capital expenditure program during the next five years. See above in Key Elements of our Business Strategy for forecasted capital expenditure requirements. A significant portion of our capital expenditures are for safety, reliability and integrity of our system and is included in utility rate base and eligible for recovery from our utility customers with regulatory approval. Those capital expenditures also earn a rate of return authorized by the commissions in the jurisdictions in which we operate.

Our capital expenditures for the three years ended December 31 were as follows (in thousands):
202120202019
Capital Expenditures By Segment (a) :
Electric Utilities$285,770 $288,683 $316,687 
Gas Utilities383,320 449,209 512,366 
Corporate and Other10,500 17,500 20,702 
Total capital expenditures$679,590 $755,392 $849,755 
____________________
(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.

Repayments of Indebtedness

For information relating to repayments of our short- and long-term debt and associated interest payments, see the Capital Resources section above and Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Unconditional Purchase Obligations


In addition toWe have unconditional purchase obligations which include the energy and capacity costs associated with our capital expenditure programs, wePPAs, transmission services agreements, and natural gas capacity, transportation and storage agreements. Additionally, our Gas Utilities have contractual obligations and other commitments that will need to be funded in the future. The following information summarizes our cash obligations and commercial commitments at December 31, 2017. Actual future obligations may differ materially from these estimated amounts (in thousands):
 Payments Due by Period
Contractual ObligationsTotal
Less Than
1 Year
1-3
Years
4-5
Years
After 5
Years
Long-term debt(a)(b)
$3,137,519
$5,743
$761,485
$8,436
$2,361,855
Unconditional purchase obligations(c)
819,635
149,526
253,357
207,717
209,035
Operating lease obligations(d)
15,638
5,030
5,797
1,726
3,085
Other long-term obligations(e)
52,024
—
—
—
52,024
Employee benefit plans(f)
195,524
18,778
58,564
39,391
78,791
Liability for unrecognized tax benefits in accordance with accounting guidance for uncertain tax positions3,263
48
3,215
—
—
CP Program211,300
211,300
—
—
—
Total contractual cash obligations(g)
$4,434,903
$390,425
$1,082,418
$257,270
$2,704,790
__________
(a)Long-term debt amounts do not include discounts or premiums on debt.
(b)
The following amounts are estimated for interest payments over the next five years based on a mid-year retirement date for long-term debt expiring during the identified period and are not included within the long-term debt balances presented: $127 million in 2018, $122 million in 2019, $113 million in 2020, $101 million in 2021 and $101 million in 2022. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2017.
(c)
Unconditional purchase obligations include the energy and capacity costs associated with our PPAs, capacity and certain transmission, gas transportation and storage agreements The energy charges under the PPAs are variable costs, which for purposes of estimating our future obligations, were based on costs incurred during 2017 and price assumptions using existing prices at December 31, 2017. Our transmission obligations are based on filed tariffs as of December 31, 2017.
(d)Includes operating leases associated with several office buildings, warehouses and call centers, equipment and vehicles.
(e)
Includes estimated asset retirement obligations associated with our Electric Utilities, Gas Utilities and Mining segments as discussed in Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
(f)Represents both estimated employer contributions to Defined Benefit Pension Plans and payments to employees for the Non-Pension Defined Benefit Postretirement Healthcare Plans and the Supplemental Non-Qualified Defined Benefit Plans through the year 2027.
(g)
Amounts in the table exclude: (1) any obligation that may arise from our derivatives, including commodity related contracts that have a negative fair value at December 31, 2017. These amounts have been excluded as it is impractical to reasonably estimate the final amount and/or timing of any associated payments; and (2) a portion of our gas purchases are hedged. These hedges are in place to reduce our customers' underlying exposure to commodity price fluctuations. The impact of these hedges is not included in the above table.

Our Gas Utility segment has commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. In addition, a portion of our gas purchases are purchased under evergreen contracts and therefore, for purposes of this disclosure, are carried out for 60 days. As of December 31, 2017, we are committed to purchase 11.2 million MMBtu, 10.6 million MMBtu, 3.9 million MMBtu, 3.7 million MMBtu and 1.8 million MMBtu in each of the years from 2018 to 2022, respectively.



Off-Balance Sheet Commitments

Guarantees

We have entered into various off-balance sheet commitments in the form of guarantees and letters of credit. We provide various guarantees supporting certain of our subsidiaries under specified agreements or transactions. At December 31, 2017, we had outstanding guarantees as indicated in the table below. For more information on these guarantees,additional information. see Note 203 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 plan is $20 million as of December 31, 2021, compared to $40 million as of December 31, 2020. While we do not have required contributions, we expect to make $3.9 million in contributions to our Pension Plan in 2022. See further information in Note 13 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
50

Common Stock Dividends

Future cash dividends, if any, will be dependent on our results of operations, financial position, cash flows, reinvestment opportunities and other factors, and will be evaluated and approved by our Board of Directors.

Additionally, there are certain statutory limitations that could affect future cash dividends paid. Federal law places limits on the ability of public utilities within a holding company structure to declare dividends. Specifically, under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries’ dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants. See additional information in Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

On January 26, 2022, our Board of Directors declared a quarterly dividend of $0.595 per share, equivalent to an annual dividend rate of $2.38 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:
202120202019
Common Stock Dividends Paid$145,023 $135,439 $124,647 
Dividend Payout Ratio61 %60 %63 %
Dividends Per Share$2.29 $2.17 $2.05 

Our three-year compound annualized dividend growth rate was 5.9%.

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, 2021, 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, 2021 was not material.

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.


Critical Accounting Estimates

We hadprepare 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 impacts of COVID-19 and Winter Storm Uri on our critical accounting estimates including, but not limited to, collectibility of customer receivables, recoverability of regulatory assets, impairment risk of goodwill and long-lived assets, valuation of pension assets and liabilities 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 guaranteesaccounting estimates are the most critical in place (in thousands):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.

51
 Outstanding atYear
Nature of GuaranteeDecember 31, 2017Expiring
Indemnification for subsidiary reclamation/surety bonds (a)
$58,221
Ongoing
 $58,221
 
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, 2021 and 2020, we had total regulatory assets of $797 million and $278 million, respectively, and total regulatory liabilities of $503 million and $533 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.

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 Chief Operating Decision Maker (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 4.9% to 5.1% and long-term growth rate projections of 1.75% were utilized in the goodwill impairment test performed as of October 1, 2021. Although 1.75% was used for a long-term growth rate projection, the short-term projected growth rate is higher with planned recovery of capital investments through rider mechanisms and rate reviews. Under the market approach, we estimate fair value using multiples derived from comparable sales transactions and enterprise value to EBITDA for comparative peer companies for each respective reporting unit. These multiples are applied to operating data for each reporting unit to arrive at an indication of fair value. In addition, we add a reasonable control premium when calculating fair value utilizing the peer multiples, which is estimated as the premium that would be received in a sale in an orderly transaction between market participants.

The estimates and assumptions used in the 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, 2021, 2020, and 2019, there were no impairment losses recorded. At December 31, 2021, the fair value substantially exceeded the carrying value at all reporting units.

52
Pension and Other Postretirement Benefits

As described in Note 13 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K, we have one defined benefit pension plan, one defined post-retirement healthcare plan and several non-qualified retirement plans. A Master Trust holds the assets for the pension plan. A VEBA trust for the funded portion of the post-retirement healthcare plan has also been established.

Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rates, healthcare cost trend rates, expected return on plan assets, compensation increases, retirement rates and mortality rates. The determination of our obligation and expenses for pension and other postretirement benefits is dependent on the assumptions determined by management and used by actuaries in calculating the amounts. Although we believe our assumptions are appropriate, significant differences in our actual experience or significant changes in our assumptions may materially affect our pension and other postretirement obligations and our future expense.

The 2022 pension benefit cost for our non-contributory funded pension plan is expected to be $2.2 million compared to $0.8 million in 2021. The increase in the expected 2022 pension benefit cost is driven primarily by lower expected asset returns and a higher discount rate.

The effect of hypothetical changes to selected assumptions on the pension and other postretirement benefit plans would be as follows in thousands of dollars:
(a)We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets.December 31,
AssumptionsPercentage Change
2021
Increase/(Decrease)
PBO/APBO (a)
2022
 Increase/(Decrease) Expense - Pretax
Pension
Discount rate (b)
 +/- 0.5(27,101)/29,688(1,883)/2,389
Expected return on assets +/- 0.5N/A(2,180)/2,180
OPEB
Discount rate (b)
 +/- 0.5(2,839)/3,09747/107
Expected return on assets +/- 0.5N/A(37)/37

Letters____________________
(a)    Projected benefit obligation (PBO) for the pension plan and accumulated postretirement benefit obligation (APBO) for OPEB plans.
(b)    Impact on service cost, interest cost and amortization of Creditgains or losses.


LettersIncome 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 reducecarryforwards. Such temporary differences are the borrowing capacity availableresult 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 corporate Revolving Credit Facility. We had $27 milliondeferred tax assets in lettersthe 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 credit issued undertax laws and the resolution of current and any future tax audits could significantly impact the amounts provided for income taxes in our Revolving Credit Facility at December 31, 2017.consolidated financial statements.


See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
Market Risk Disclosures


53
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.To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures.


Market risk is the potential loss that may occur as a result of an adverse change in market price, rate or rate. supply. We are exposed, but not limited to, the following market risks, including, but not limited to:risks:


•Commodity price risk associated with our retail natural gas services, wholesale electric power marketing activities and our fuel procurement for certainseveral of our gas-fired generation assets;assets. Market fluctuations may occur due to unpredictable factors such as weather (Winter Storm Uri), market speculation, inflation, pipeline constraints, and other factors that may impact natural gas and electric energy supply and demand; and


•Interest rate risk associated with our variable ratefuture debt, including reduced access to liquidity during periods of extreme capital markets volatility, such as described in Notes 6the 2008 financial crisis and 7the COVID-19 pandemic.

Credit risk is associated with financial loss resulting from non-performance of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Our exposure to these market risks is affectedcontractual obligations by a number of factors includingcounterparty.

To manage and mitigate these identified risks, we have adopted the size, durationBlack Hills Corporation Risk Policies and composition of our energy portfolio, the absolute and relative levels of interest rates and commodity prices, the volatility of these prices and rates and the liquidity of the related interest rate and commodity markets.

Procedures. The Black Hills Corporation Risk Policies and Procedures have been approved by our Executive Risk Committee and reviewed by the Audit Committee of our Board of Directors.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 on a regular basisat 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


We produce, purchase and distribute power in four states, and purchase and distribute natural gas in six states. All of ourOur utilities have GCAvarious provisions that allow them to pass the prudently-incurred cost of gasenergy through to the customer. To the extent that gasenergy prices are higher or lower than amounts in our current billing rates, adjustments are made on a periodic basis to “true-up”reflect billed amounts to match the actual natural gasenergy cost we incurred. In Colorado, South Dakota Colorado,and Wyoming, and Montana, we have a mechanism forECA or PCA provisions that adjust electric rates when energy costs are higher or lower than the costs included in our regulated electric utilitiestariffs. In Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming, we have GCA provisions that serves a purpose similar to the GCAs foradjust natural gas rates when our regulatednatural gas utilities. To the extent that our fuel and purchased power costs are higher or lower than the energy cost built intoincluded in our tariffs, the difference (or a portion thereof) is passed through to the customer.tariffs. These adjustments are subject to periodic prudence reviews by the state utilityregulatory commissions.


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 volatility in natural gas prices.price volatility. Therefore, as allowed or required by state utilityregulatory 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’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 (Loss).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.

54
Black Hills Energy Services

We buy sell and deliversell 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/or sales during time frames ranging from January 2018 through May 2020.

The fair valueand sales. A portion of our Electricover-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 Gas Utilities derivative contracts atreclassified into earnings in the same period that the underlying hedged item is recognized in earnings.

At December 31, is summarized below (in thousands):2021 and 2020, 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.

 2017 2016
Net derivative liabilities$(6,644) $(4,733)
Cash collateral8,256
 12,722
 $1,612
 $7,989
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.


Wholesale PowerInterest Rate Risk


A potential risk related to power sales is the price risk arising from the sale of wholesale 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.

Financing Activities

Historically,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, 2017,2021, we had no interest rate swaps in place. At December 31, 2016, we had a $50 million notional, 4.94% pay-fixed interest rate swap designated to borrowings on our Revolving Credit Facility; this swap expired in January 2017.

Further details of past swap agreements are set forth in Note 9 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.



At December 31, 2021, 91% 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 $2.7 million and $2.1 million for the years ended December 31, 2021 and 2020, respectively. See Note 8 for further information on cash amounts outstanding under short- and long-term variable rate borrowings.




The table below presents principal amountsWe are subject to interest rate risk associated with our pension and related weighted averagepost-retirement benefit obligations. Changes in interest rates by yearimpact the liabilities associated with these benefit plans as well as the amount of maturityincome or expense recognized for our long-term debt obligations, including current maturities (dollarsthese plans. Declines in thousands):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.
 20182019202020212022ThereafterTotal
Long-term debt       
Fixed rate(a)
$5,743
$255,742
$205,743
$1,436
$—
$2,349,000
$2,817,664
Average interest rate (b)
2.32%2.5%5.78%2.32%—%4.29%4.23%
        
Variable rate$—
$300,000
$—
$7,000
$—
$12,855
$319,855
Average interest rate (b)
—%2.55%—%1.78%—%1.79%2.5%
        
Total long-term debt$5,743
$555,742
$205,743
$8,436
$—
$2,361,855
$3,137,519
Average interest rate (b)
2.32%2.53%5.78%1.87%—%4.28%4.05%
_________________________
(a)Excludes unamortized premium or discount.
(b)The average interest rates do not include the effect of interest rate swaps.


Credit Risk


Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty. 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. In addition, our Executive Risk Committee, which includes senior executives, meets on a regular basis to review our credit activities and to monitor compliance with the adopted policies.

We seekattempt to mitigate our credit riskexposure by conducting a majority of our business primarily with investment grade companies,high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements and securing ourmitigating credit exposure with less creditworthy counterparties through parental guarantees, prepayments,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 our review of their current credit information. We maintain a provision for estimated credit losses based upon our historical experience, changes in current market conditions, expected losses and any specific customer collection issue that we haveis identified. While most credit losses have historically been within our expectations and provisions established, we cannot provide assurance that we will continue to experience the same credit loss rates that we have in the past, or that an investment grade counterparty will not default sometime in the future.

Our credit exposure at December 31, 20172021 was concentrated primarily among retail utility customers, investment grade companies, municipal cooperativescooperative utilities and federal agencies.


New Accounting Pronouncements

See Note more information in Notes 1 and 9 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for information on new accounting standards adopted in 2017 or pending adoption.10-K.




ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


55
INDEX TO CONSOLIDATED
ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA



Management’s Report on Internal Controls Over Financial Reporting
88
Reports of Independent Registered Public Accounting Firm
89
Consolidated Statements of Income (Loss) for the three years ended December 31, 2017
91
Consolidated Statements of Comprehensive Income (Loss) for the three years ended December 31, 2017
92
Consolidated Balance Sheets as of December 31, 2017 and 2016
93
Consolidated Statements of Cash Flows for the three years ended December 31, 2017
95
Consolidated Statements of Equity for the three years ended December 31, 2017
96
Notes to Consolidated Financial Statements
97






Management’s Report on Internal Control overOver 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, 2017,2021, 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, 2017.2021.


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, 2017.2021. Deloitte & Touche LLP's report on Black Hills Corporation's internal control over financial reporting is included herein.


Black Hills Corporation

56










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, 20172021 and 2016,2020, the related consolidated statements of income, (loss), comprehensive income, (loss),shareholders' equity, and cash flows, for each of the three years in the period ended December 31, 2017,2021, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the “financial statements”"financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172021 and 2016,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2021, 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, 2017,2021, 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 23, 2018,15, 2022, 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’sCompany'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).

57


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 the return on invested capital.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, and (2) a refund or future rate reduction to be provided to customers. Given the uncertainty of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:

•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) refunds or future reductions in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We read relevant regulatory orders issued by the Commissions, 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 15, 2022
February 23, 2018    


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



58


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"“Company”) as of December 31, 2017,2021, 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, 2017,2021, 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 statementsand financial statement schedule as of and for the year ended December 31, 2017,2021, of the Company and our report dated February 23, 201815, 2022, expressed an unqualified opinion on those consolidated financial statements and financial statement schedule.statements.

Basis for Opinion

The Company'sCompany’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’sManagement's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company'sCompany’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 15, 2022
February 23, 2018
59







BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
Year endedDecember 31, 2021December 31, 2020December 31, 2019
(in thousands, except per share amounts)
Revenue$1,949,102 $1,696,941 $1,734,900 
Operating expenses:
Fuel, purchased power and cost of natural gas sold741,934 492,404 570,829 
Operations and maintenance501,690 495,404 495,994 
Depreciation, depletion and amortization235,953 224,457 209,120 
Taxes - property and production60,096 56,373 52,915 
Total operating expenses1,539,673 1,268,638 1,328,858 
Operating income409,429 428,303 406,042 
Other income (expense):
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)(154,112)(144,931)(139,291)
Interest income1,708 1,461 1,632 
Impairment of investment— (6,859)(19,741)
Other income (expense), net1,404 (2,293)(5,740)
Total other income (expense)(151,000)(152,622)(163,140)
Income before income taxes258,429 275,681 242,902 
Income tax (expense)(7,169)(32,918)(29,580)
Net income251,260 242,763 213,322 
Net income attributable to non-controlling interest(14,516)(15,155)(14,012)
Net income available for common stock$236,744 $227,608 $199,310 
Earnings per share of common stock:
Earnings per share, Basic$3.74 $3.65 $3.29 
Earnings per share, Diluted$3.74 $3.65 $3.28 
Weighted average common shares outstanding:
Basic63,219 62,378 60,662 
Diluted63,325 62,439 60,798 
Year endedDecember 31, 2017December 31, 2016December 31, 2015
 (in thousands, except per share amounts)
    
Revenue$1,680,266
$1,538,916
$1,261,322
    
Operating expenses:   
Fuel, purchased power and cost of natural gas sold563,288
499,132
456,887
Operations and maintenance454,605
426,603
323,809
Depreciation, depletion and amortization188,246
175,533
126,533
Taxes - property and production51,578
46,160
40,060
Other operating expenses5,813
55,307
13,613
Total operating expenses1,263,530
1,202,735
960,902
    
Operating income416,736
336,181
300,420
    
Other income (expense):   
Interest charges -   
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts)(140,756)(139,447)(86,226)
Allowance for funds used during construction - borrowed2,415
2,981
1,250
Capitalized interest223
356
326
Interest income1,016
1,429
1,621
Allowance for funds used during construction - equity2,321
3,270
897
Other expense(1,559)(626)(158)
Other income1,346
1,750
2,075
Total other income (expense)(134,994)(130,287)(80,215)
Income before income taxes281,742
205,894
220,205
Income tax benefit (expense)(73,367)(59,101)(78,657)
Income from continuing operations208,375
146,793
141,548
Net (loss) from discontinued operations(17,099)(64,162)(173,659)
Net income (loss)191,276
82,631
(32,111)
Net income attributable to noncontrolling interest(14,242)(9,661)—
Net income (loss) available for common stock$177,034
$72,970
$(32,111)
    
Amounts attributable to common shareholders:   
Net income from continuing operations$194,133
$137,132
$141,548
Net (loss) from discontinued operations(17,099)(64,162)(173,659)
Net income (loss) available for common stock$177,034
$72,970
$(32,111)
    
Earnings (loss) per share of common stock, Basic -   
Earnings from continuing operations$3.65
$2.64
$3.12
(Loss) from discontinued operations$(0.32)$(1.23)$(3.83)
Total earnings (loss) per share of common stock, Basic$3.33
$1.41
$(0.71)
    
Earnings (loss) per share of common stock, Diluted -   
Earnings from continuing operations$3.52
$2.57
$3.12
(Loss) from discontinued operations$(0.31)$(1.20)$(3.83)
Total earnings (loss) per share of common stock, Diluted$3.21
$1.37
$(0.71)
    
Weighted average common shares outstanding:   
Basic53,221
51,922
45,288
Diluted55,120
53,271
45,288


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


60


BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

Year endedDecember 31, 2021December 31, 2020December 31, 2019
(in thousands)
Net income$251,260 $242,763 $213,322 
Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (loss) (net of tax of $(664), $191 and $1,886, respectively)1,959 (1,062)(6,253)
Benefit plan liability adjustments - prior service costs (net of tax of $0, $0 and $2 respectively)— — (8)
Reclassification adjustment of benefit plan liability - net loss (net of tax of $(665), $(958) and $434, respectively)1,726 1,429 1,179 
Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $27, $23 and $19, respectively)(71)(80)(58)
Derivative instruments designated as cash flow hedges:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(677), $(287) and $(666), respectively)2,174 2,564 2,185 
Net unrealized gains (losses) on commodity derivatives (net of tax of $(980), $14 and $126, respectively)3,023 (47)(422)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $502, $(96) and $55, respectively)(1,549)505 (362)
Other comprehensive income (loss), net of tax7,262 3,309 (3,739)
Comprehensive income258,522 246,072 209,583 
Less: comprehensive income attributable to non-controlling interest(14,516)(15,155)(14,012)
Comprehensive income available for common stock$244,006 $230,917 $195,571 


Year endedDecember 31, 2017December 31, 2016December 31, 2015
 (in thousands)
Net income (loss)$191,276
$82,631
$(32,111)
    
Other comprehensive income (loss), net of tax:   
Benefit plan liability adjustments - net gain (loss) (net of tax of $1,030, $757 and $(1,375), respectively)(1,890)(1,738)2,657
Benefit plan liability adjustments - prior service (costs) (net of tax of $0, $107 and $0, respectively)—
(247)—
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(585), $(600) and $(972), respectively)1,072
1,378
1,850
Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $69, $67 and $88, respectively)(128)(154)(150)
Derivative instruments designated as cash flow hedges:   
Net unrealized gains (losses) on interest rate swaps (net of tax of $0, $10,920 and $(598), respectively)—
(20,302)2,290
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(1,029), $(1,365) and $(1,348), respectively)1,912
2,534
2,299
Net unrealized gains (losses) on commodity derivatives (net of tax of $(135), $212 and $(3,898), respectively)231
(361)5,884
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $154, $4,067 and $5,619, respectively)(516)(6,938)(8,841)
Other comprehensive income (loss), net of tax681
(25,828)5,989
    
Comprehensive income (loss)191,957
56,803
(26,122)
Less: comprehensive income attributable to non-controlling interest(14,242)(9,661)—
Comprehensive income (loss) available for common stock$177,715
$47,142
$(26,122)

See Note 1611 for additional disclosures related to Comprehensive Income.


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

61




BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS

As of
December 31, 2021December 31, 2020
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents$8,921 $6,356 
Restricted cash and equivalents4,889 4,383 
Accounts receivable, net321,652 265,961 
Materials, supplies and fuel150,979 117,400 
Derivative assets, current4,373 1,848 
Income tax receivable, net18,017 19,446 
Regulatory assets, current270,290 51,676 
Other current assets29,012 26,221 
Total current assets808,133 493,291 
Property, plant and equipment7,856,573 7,305,530 
Less accumulated depreciation and depletion(1,407,397)(1,285,816)
Total property, plant and equipment, net6,449,176 6,019,714 
Other assets:
Goodwill1,299,454 1,299,454 
Intangible assets, net10,770 11,944 
Regulatory assets, non-current526,309 226,582 
Other assets, non-current38,054 37,801 
Total other assets, non-current1,874,587 1,575,781 
TOTAL ASSETS$9,131,896 $8,088,786 

 As of
 December 31, 2017December 31, 2016
 (in thousands)
ASSETS  
Current assets:  
Cash and cash equivalents$15,420
$13,518
Restricted cash and equivalents2,820
2,274
Accounts receivable, net248,330
259,311
Materials, supplies and fuel113,283
103,606
Derivative assets, current304
3,985
Regulatory assets, current81,016
49,260
Other current assets25,367
23,928
Current assets held for sale84,242
10,932
Total current assets570,782
466,814
   
Investments13,090
12,561
   
Property, plant and equipment5,567,518
5,315,296
Less accumulated depreciation and depletion(1,026,088)(929,119)
Total property, plant and equipment, net4,541,430
4,386,177
   
Other assets:  
Goodwill1,299,454
1,299,454
Intangible assets, net7,559
8,392
Derivative assets, non-current—
222
Regulatory assets, non-current216,438
246,882
Other assets, non-current10,149
11,508
Noncurrent assets held for sale—
109,763
Total other assets, non-current1,533,600
1,676,221
TOTAL ASSETS$6,658,902
$6,541,773

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



62




BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
(Continued)

As of
December 31, 2021December 31, 2020
(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable$217,761 $183,340 
Accrued liabilities244,759 243,612 
Derivative liabilities, current1,439 2,044 
Regulatory liabilities, current17,574 25,061 
Notes payable420,180 234,040 
Current maturities of long-term debt— 8,436 
Total current liabilities901,713 696,533 
Long-term debt, net of current maturities4,126,923 3,528,100 
Deferred credits and other liabilities:
Deferred income tax liabilities, net465,388 408,624 
Regulatory liabilities, non-current485,377 507,659 
Benefit plan liabilities123,925 150,556 
Other deferred credits and other liabilities141,447 134,667 
Total deferred credits and other liabilities1,216,137 1,201,506 
Commitments, contingencies and guarantees (Note 3)
00
Equity:
Stockholders’ equity -
Common stock $1.00 par value; 100,000,000 shares authorized; issued: 64,793,095 and 62,827,179, respectively64,793 62,827 
Additional paid-in capital1,783,436 1,657,285 
Retained earnings962,458 870,738 
Treasury stock at cost - 54,078 and 32,492, respectively(3,509)(2,119)
Accumulated other comprehensive income (loss)(20,084)(27,346)
Total stockholders’ equity2,787,094 2,561,385 
Non-controlling interest100,029 101,262 
Total equity2,887,123 2,662,647 
TOTAL LIABILITIES AND TOTAL EQUITY$9,131,896 $8,088,786 

 As of
 December 31, 2017December 31, 2016
 (in thousands, except share amounts)
   
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND EQUITY  
Current liabilities:  
Accounts payable$160,887
$152,129
Accrued liabilities219,462
235,548
Derivative liabilities, current2,081
1,104
Accrued income tax, net1,022
12,552
Regulatory liabilities, current6,832
13,067
Notes payable211,300
96,600
Current maturities of long-term debt5,743
5,743
Current liabilities held for sale41,774
11,189
Total current liabilities649,101
527,932
   
Long-term debt, net of current maturities3,109,400
3,211,189
   
Deferred credits and other liabilities:  
Deferred income tax liabilities, net336,520
561,935
Regulatory liabilities, non-current478,294
193,689
Benefit plan liabilities159,646
173,682
Other deferred credits and other liabilities105,735
115,883
Noncurrent liabilities held for sale—
23,034
Total deferred credits and other liabilities1,080,195
1,068,223
   
Commitments and contingencies (See Notes 6, 7, 8, 9, 14, 18, 19, and 20)

   
Redeemable noncontrolling interest—
4,295
   
Equity:  
Stockholders’ equity -  
Common stock $1 par value; 100,000,000 shares authorized; issued: 53,579,986 and 53,397,467, respectively53,580
53,397
Additional paid-in capital1,150,285
1,138,982
Retained earnings548,617
457,934
Treasury stock at cost - 39,064 and 15,258, respectively(2,306)(791)
Accumulated other comprehensive income (loss)(41,202)(34,883)
Total stockholders’ equity1,708,974
1,614,639
Noncontrolling interest111,232
115,495
Total equity1,820,206
1,730,134
   
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND TOTAL EQUITY$6,658,902
$6,541,773

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

63




BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year endedDecember 31, 2021December 31, 2020December 31, 2019
(in thousands)
Operating activities:
Net income$251,260 $242,763 $213,322 
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization235,953 224,457 209,120 
Deferred financing cost amortization6,968 7,883 7,838 
Impairment of investment— 6,859 19,741 
Stock compensation9,655 5,373 12,095 
Deferred income taxes7,261 38,091 38,020 
Employee benefit plans9,590 11,997 12,406 
Other adjustments, net7,018 11,669 16,485 
Change in certain operating assets and liabilities:
Materials, supplies and fuel(35,707)2,755 2,052 
Accounts receivable and other current assets(43,170)(10,843)7,578 
Accounts payable and other current liabilities10,660 24,659 (34,906)
Regulatory assets(514,687)(5,047)23,619 
Regulatory liabilities(9,533)(10,706)(15,158)
Contributions to defined benefit pension plans— (12,700)(12,700)
Other operating activities, net167 4,653 6,001 
Net cash provided by (used in) operating activities(64,565)541,863 505,513 
Investing activities:
Property, plant and equipment additions(677,492)(767,404)(818,376)
Other investing activities13,262 5,740 2,166 
Net cash (used in) investing activities(664,230)(761,664)(816,210)
Financing activities:
Dividends paid on common stock(145,023)(135,439)(124,647)
Common stock issued118,979 99,278 101,358 
Term Loan - borrowings800,000 — — 
Term Loan - repayments(800,000)— — 
Net borrowings (payments) of Revolving Credit Facility and CP Program186,140 (115,460)163,880 
Long-term debt - issuance600,000 400,000 1,100,000 
Long-term debt - repayments(8,436)(8,597)(905,743)
Distributions to non-controlling interests(15,749)(15,839)(17,901)
Other financing activities(4,045)(7,061)(16,737)
Net cash provided by financing activities731,866 216,882 300,210 
Net change in cash, restricted cash and cash equivalents3,071 (2,919)(10,487)
Cash, restricted cash and cash equivalents beginning of year10,739 13,658 24,145 
Cash, restricted cash and cash equivalents end of year$13,810 $10,739 $13,658 
Supplemental cash flow information:
Cash (paid) refunded during the period:
Interest (net of amounts capitalized)$(142,685)$(136,549)$(131,774)
Income taxes$1,521 $2,172 $4,682 
Non-cash investing and financing activities:
Accrued property, plant and equipment purchases at December 31$68,758 $72,215 $91,491 
Increase in capitalized assets associated with asset retirement obligations$2,109 $4,774 $5,044 
Year endedDecember 31, 2017December 31, 2016December 31, 2015
 (in thousands)
Operating activities:   
Net income (loss)$191,276
$82,631
$(32,111)
(Income) loss from discontinued operations, net of tax17,099
64,162
173,659
Income (loss) from continuing operations208,375
146,793
141,548
Adjustments to reconcile net income (loss) to net cash provided by operating activities:   
Depreciation, depletion and amortization188,246
175,533
126,533
Deferred financing cost amortization8,261
6,180
6,364
Stock compensation7,626
10,885
4,076
Deferred income taxes80,992
82,704
74,704
Employee benefit plans10,141
14,291
20,616
Other adjustments, net(4,773)(5,519)(4,872)
Change in certain operating assets and liabilities:   
Materials, supplies and fuel(10,089)1,211
7,216
Accounts receivable, unbilled revenues and other current assets4,534
(27,172)33,255
Accounts payable and other current liabilities(28,222)(33,023)(74,748)
Regulatory assets(15,407)3,614
21,883
Regulatory liabilities(4,536)(14,082)1,675
Contributions to defined benefit pension plans(27,700)(14,200)(10,200)
Interest rate swap settlement—
(28,820)—
Other operating activities, net(8,418)(660)(9,033)
Net cash provided by operating activities of continuing operations409,030
317,735
339,017
Net cash provided by (used in) operating activities of discontinued operations19,231
2,744
85,366
Net cash provided by operating activities428,261
320,479
424,383
    
Investing activities:   
Property, plant and equipment additions(326,010)(454,952)(266,375)
Acquisition of net assets, net of long-term debt assumed—
(1,124,238)(21,970)
Other investing activities465
(1,139)(444)
Net cash (used in) investing activities of continuing operations(325,545)(1,580,329)(288,789)
Net cash provided by (used in) investing activities of discontinued operations7,881
(8,413)(187,600)
Net cash provided by (used in) investing activities(317,664)(1,588,742)(476,389)
    
Financing activities:   
Dividends paid on common stock(96,744)(87,570)(72,604)
Common stock issued4,408
121,619
248,759
Net increase (decrease) in commercial paper and short-term borrowings114,700
19,800
1,800
Long-term debt - issuance—
1,767,608
300,000
Long-term debt - repayments(105,743)(1,164,308)(275,000)
Sale of noncontrolling interest—
216,370
—
Distributions to noncontrolling interests(18,397)(9,561)—
Equity units - issuance—
—
290,030
Other financing activities(6,919)(22,960)(9,283)
Net cash provided by (used in) financing activities(108,695)840,998
483,702
    
Net change in cash and cash equivalents1,902
(427,265)431,696
    
Cash and cash equivalents beginning of year13,518
440,783
9,087
Cash and cash equivalents end of year$15,420
$13,518
$440,783



See Note 17 for supplemental disclosure of cash flow information.

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


64


BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY


Common StockTreasury Stock
(in thousands except share amounts)SharesValueSharesValueAdditional Paid in CapitalRetained EarningsAOCINon controlling InterestTotal
Balance at December 31, 201860,048,567 $60,049 44,253 $(2,510)$1,450,569 $700,396 $(26,916)$105,835 $2,287,423 
Net income— — — — — 199,310 — 14,012 213,322 
Other comprehensive (loss), net of tax— — — — — — (3,739)— (3,739)
Dividends on common stock ($2.05 per share)— — — — — (124,647)— — (124,647)
Share-based compensation103,759 104 (40,297)2,243 4,729 — — — 7,076 
Issuance of common stock1,328,332 1,328 — — 98,672 — — — 100,000 
Issuance costs— — — — (1,182)— — — (1,182)
Other— — — — — 327 — — 327 
Implementation of ASU 2016-02 Leases— — — — — 3,390 — — 3,390 
Distributions to non-controlling interest— — — — — — — (17,901)(17,901)
Balance at December 31, 201961,480,658 $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 compensation123,578 123 28,536 (1,852)6,923 — — — 5,194 
Issuance of common stock1,222,943 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, 202062,827,179 $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 compensation153,719 154 21,586 (1,390)9,256 — — — 8,020 
Issuance of common stock1,812,197 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, 202164,793,095 $64,793 54,078 $(3,509)$1,783,436 $962,458 $(20,084)$100,029 $2,887,123 
 Common StockTreasury Stock     
(in thousands except share amounts)SharesValueSharesValueAdditional Paid in CapitalRetained EarningsAOCINon controlling InterestTotal
Balance at December 31, 201444,714,072
$44,714
42,226
$(1,875)$748,840
$577,249
$(15,044)$—
$1,353,884
Net income (loss) available for common stock—
—
—
—
—
(32,111)—
—
(32,111)
Other comprehensive income (loss), net of tax—
—
—
—
—
—
5,989
—
5,989
Dividends on common stock—
—
—
—
—
(72,604)—
—
(72,604)
Share-based compensation126,765
127
(2,506)(13)4,126
—
—
—
4,240
Issuance of common stock6,325,000
6,325
—
—
248,256
—
—
—
254,581
Issuance costs—
—
—
—
(17,926)—
—
—
(17,926)
Premium on Equity Units—
—
—
—
(33,118)—
—
—
(33,118)
Dividend reinvestment and stock purchase plan66,024
66
—
—
2,891
—
—
—
2,957
Other stock transactions—
—
—
—
(25)—
—
—
(25)
Balance at December 31, 201551,231,861
$51,232
39,720
$(1,888)$953,044
$472,534
$(9,055)$—
$1,465,867
Net income (loss) available for common stock—
—
—
—
—
72,970
—
9,661
82,631
Other comprehensive income (loss), net of tax—
—
—
—
—
—
(25,828)—
(25,828)
Dividends on common stock—
—
—
—
—
(87,570)—
—
(87,570)
Share-based compensation145,634
146
(16,165)668
4,665
—
—
—
5,479
Issuance of common stock1,968,738
1,969
—
—
118,021
—
—
—
119,990
Issuance costs—
—
—
—
(1,566)—
—
—
(1,566)
Dividend reinvestment and stock purchase plan51,234
50
—
—
2,933
—
—
—
2,983
Other stock transactions—
—
(8,297)429
47
—
—
—
476
Sale of noncontrolling interest—
—
—
—
61,838
—
—
115,395
177,233
Distributions to noncontrolling interest—
—
—
—
—
—
—
(9,561)(9,561)
Balance at December 31, 201653,397,467
$53,397
15,258
$(791)$1,138,982
$457,934
$(34,883)$115,495
$1,730,134
Net income (loss) available for common stock—
—
—
—
—
177,034
—
14,242
191,276
Other comprehensive income (loss), net of tax—
—
—
—
—

681
—
681
Reclassification of certain tax effects from AOCI—
—
—
—
—
7,000
(7,000)—
—
Dividends on common stock—
—
—
—
—
(96,744)—
—
(96,744)
Share-based compensation134,266
134
23,806
(1,515)8,948
—
—
—
7,567
Tax effect of share-based compensation—
—
—
—
533
3,184
—
—
3,717
Issuance costs—
—
—
—
(189)—
—
—
(189)
Dividend reinvestment and stock purchase plan48,253
49
—
—
3,107
—
—
—
3,156
Redemption of and distributions to noncontrolling interest—
—
—
—
(1,096)209
—
(18,505)(19,392)
Balance at December 31, 201753,579,986
$53,580
39,064
$(2,306)$1,150,285
$548,617
$(41,202)$111,232
$1,820,206

Dividends per share paid were $1.81, $1.68 and $1.62 for the years ended December 31, 2017, 2016 and 2015, respectively.

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

65






BLACK HILLS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSNotes to Consolidated Financial Statements
December 31, 2017, 20162021, 2020 and 20152019


(1)
BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES

(1)    BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES

Business Description


Black Hills Corporation is a customer-focused, growth-oriented vertically-integrated 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, Power Generation and Mining.Utilities. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other.


Segment Reporting


Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products services and regulation.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, Wyoming Electric and ColoradoWyoming Electric, which supply regulated electric utility services to areas in Colorado, Montana, South Dakota Wyoming, Colorado and Montana. Wyoming. We also own and operate non-regulated power generation and mining businesses that are vertically integrated with our Electric Utilities.

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.

Our Gas Utilities Segmentsegment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, WyomingNebraska and Nebraska.Wyoming.


All of our non-utility business segments support our electric utilities. Our Power Generation segment, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Wyoming and Colorado. Our Mining segment, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyoming. For further descriptions ofinformation regarding our reportable business segments,segment reporting, see Note 516.

On November 1, 2017, our Board of Directors approved a complete divestiture of our Oil and Gas segment. As of February 23, 2018, we have either closed transactions or signed contracts to sell more than 90% of our oil and gas properties. We have executed agreements to sell all our operated properties and have only non-operated assets left to divest. We plan to conclude the sale of all of our remaining assets by mid-year 2018.

The Oil and Gas segment assets and liabilities have been classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. The consolidated financial statements and accompanying notes for current and prior periods have been restated. At the time the assets were classified as held for sale, depreciation, depletion and amortization expenses were no longer recorded. Unless otherwise noted, the amounts presented in the accompanying notes to the consolidated financial statements relate to the Company’s continuing operations. For more information on discontinued operations, see Note 21.


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, 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. Investment in non-controlled entities over which we have the ability to exercise significant influence over operating and financial policies are accounted for using the equity method of accounting. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for our proportionate share of earnings and losses and distributions. Under this method, a proportionate share of pretax income is recorded as Equity earnings (loss) of unconsolidated subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. For additional information on intercompany revenues, see Note 516.




Our Consolidated Statements of Income (Loss) include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our working interests in oil and gas properties and for our ownership interest in any jointly-owned electric utility generatinggeneration facility, wind projectfarm or transmission tie. See Note 46 for additional information.


66


Variable Interest Entities


We evaluate arrangements and contracts with other entities to determine if they are VIEs and if so, if we are the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrollingnon-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 noncontrollingnon-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 12.12.


Cash, and Cash Equivalents and Restricted Cash


We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Restricted Cash and Equivalents

cash equivalents. We maintain cash accounts for various specified purposes. Therefore, we classify these amountspurposes, 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.

•Coal supply agreements - Our WRDC mine sells coal primarily under long-term contracts to affiliates for use at their generation facilities. The contracts include a single promise to supply coal necessary to fuel the customers’ facilities during the contract term. The transaction price is established in the supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons delivered.

•Other non-regulated services - Our Utilities segments also provide non-regulated services primarily comprised of appliance repair service and protection plans, electric and natural gas technical infrastructure construction and maintenance services, and in Nebraska and Wyoming, an unbundled natural gas commodity offering under the regulatory-approved Choice Gas Program. Revenue contracts for these services generally represent a single performance obligation with the price reflecting the standalone selling price stated in the agreement and a variable revenue based on the units delivered or services provided.

67


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.

Accounts Receivable and Allowance for Doubtful AccountsCredit Losses


Accounts receivable for our Electric and Gas Utilities business segments primarily consists of sales to residential, commercial, industrial, municipaltransportation and other customers, all of which do not bear interest. These accounts receivable are stated at billed and estimated unbilled amounts, net of write-offs and allowance for doubtful accounts.credit losses. Accounts receivable for our Miningpower generation and Power Generation business segmentsmining businesses consists of amounts due from sales of coal, natural gas, electric energy and capacity.capacity and coal primarily to affiliates or regional utilities.
We maintain an allowance for doubtful accountscredit 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 collectibility.collectability.


In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accountscredit 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):

20212020
Billed Accounts Receivable$181,027 $146,899 
Unbilled Revenue$142,738 $126,065 
Less Allowance for Credit Losses$(2,113)$(7,003)
Accounts Receivable, net$321,652 $265,961 
68


2017Accounts Receivable, TradeUnbilled RevenueLess Allowance for Doubtful AccountsAccounts Receivable, net
Electric Utilities$39,347
$36,384
$(586)$75,145
Gas Utilities81,256
88,967
(2,495)167,728
Power Generation1,196
—
—
1,196
Mining2,804
—
—
2,804
Corporate1,457
—
—
1,457
Total$126,060
$125,351
$(3,081)$248,330



Changes to allowance for credit losses for the years ended December 31, were as follows (in thousands):
2016Accounts Receivable, TradeUnbilled RevenueLess Allowance for Doubtful AccountsAccounts Receivable, net
Electric Utilities$41,730
$36,463
$(353)$77,840
Gas Utilities88,168
88,329
(2,026)174,471
Power Generation1,420
—
—
1,420
Mining3,352
—
—
3,352
Corporate2,228
—
—
2,228
Total$136,898
$124,792
$(2,379)$259,311
Balance at Beginning of YearAdditions Charged to Costs and ExpensesRecoveries and Other AdditionsWrite-offs and Other DeductionsBalance at End of Year
2021$7,003 $2,444 (a)$3,560 $(10,894)$2,113 
2020$2,444 $8,927 (a)$4,728 $(9,096)$7,003 
2019$3,209 $5,795 $3,942 $(10,502)$2,444 

_________________
Revenue Recognition

Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price and delivery has occurred or services have been rendered. Sales and franchise taxes collected from our customers are recorded on a net basis (excluded from Revenue).

Utility revenues are based on authorized rates approved by the state regulatory agencies and the FERC. Revenues related(a)    Due to the sale, transmissionCOVID-19 pandemic, all of our jurisdictions temporarily suspended disconnections due to non-payment for a period of time, which increased our accounts receivable arrears balances. As a result, we increased our allowance for credit losses and distribution of energy, and delivery of service are generally recorded when service is renderedbad debt expense for the year ended December 31, 2020 by an incremental $3.3 million. All jurisdiction disconnect moratoriums ended on or energy is delivered to customers. 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.before May 3, 2021.


For long-term non-regulated power sales agreements, revenue is recognized either in accordance with accounting standards for revenue recognition, or in accordance with accounting standards for leases, as appropriate. Under accounting standards for revenue recognition, revenue is generally recognized as the lesser of the amount billed or the average rate expected over the life of the agreement.

Natural gas and crude oil sales included in discontinued operations are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectibility of the revenue is reasonably assured. BHEP records its share of revenues based on production volumes and contracted sales prices. The sales price for natural gas, crude oil, condensate and NGLs is adjusted for transportation costs and other related deductions when applicable. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment.



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):

20212020
Materials and supplies$86,400 $85,250 
Fuel1,267 1,531 
Natural gas in storage63,312 30,619 
Total materials, supplies and fuel$150,979 $117,400 
 20172016
Materials and supplies$69,732
$64,852
Fuel - Electric Utilities2,962
3,667
Natural gas in storage40,589
35,087
Total materials, supplies and fuel$113,283
$103,606


Materials and supplies represent parts and supplies for all of our business segments. Fuel -represents diesel oil and gas used by our Electric Utilities represents oil, gas and coal on hand used 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.


Investments

In February 2018, we made a contribution of $28 million of assets in exchange for equity securities in a privately held oil and gas company as we divested of our Oil and Gas segment. The carrying value of our investment in the equity securities was recorded at cost. We review this investment on a periodic basis to determine whether a significant event or change in circumstances has occurred that may have an adverse effect on the value of the investment.

During the third quarter of 2019, we assessed our investment for impairment as a result of a deterioration in earnings performance of the privately held oil and gas company and an adverse change in future natural gas prices. Based on the estimated fair value of our investment, we concluded that the carrying value of the investment exceeded fair value. As a result, we recorded a pre-tax impairment loss of $20 million for the three months ended September 30, 2019, which was the difference between the carrying amount and the fair value of the investment at that time.

During the first quarter of 2020, we assessed our investment for impairment as a result of continued adverse changes in future natural gas prices and liquidity concerns at the privately held oil and gas company. Based on the estimated fair value of our investment, we concluded that the carrying value of the investment exceeded fair value. As a result, we recorded a pre-tax impairment loss of $6.9 million for the three months ended March 31, 2020, which was the difference between the carrying value and the fair value of the investment at that time.

The following table presents the carrying value of our investments (in thousands), which are included in Other assets, non-current on the Consolidated Balance Sheets, as of December 31:
20212020
Investment in privately held oil and gas company$1,500 $1,500 
Cash surrender value of life insurance contracts12,365 13,628 
Other investments1,616 682 
Total investments$15,481 $15,810 
69



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 Location202120202019
AFUDC BorrowedInterest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)$4,068 $5,617 $6,556 
AFUDC EquityOther income (expense), net593 318 472 

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 is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income. The accounting for the obligation for regulated operations 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.

We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Our annual goodwill impairment testing date is as of October 1, which aligns our testing date with our financial planning process.

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

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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, 2021 and 2020, Goodwill balances were as follows (in thousands):
Electric UtilitiesGas UtilitiesTotal
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 2 years to 40 years. Changes to intangible assets for the years ended December 31, were as follows (in thousands):
202120202019
Intangible assets, net, beginning balance$11,944 $13,266 $14,337 
Amortization expense (a)
(1,174)(1,322)(1,071)
Intangible assets, net, ending balance$10,770 $11,944 $13,266 
____________________
(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):

20212020
Accrued employee compensation, benefits and withholdings$74,387 $77,806 
Accrued property taxes50,874 47,105 
Customer deposits and prepayments48,814 52,185 
Accrued interest33,680 31,520 
Other (none of which is individually significant)37,004 34,996 
Total accrued liabilities$244,759 $243,612 
 20172016
Accrued employee compensation, benefits and withholdings$52,467
$54,553
Accrued property taxes42,029
37,379
Customer deposits and prepayments44,420
55,191
Accrued interest33,822
33,982
CIAC current portion1,552
1,575
Other (none of which is individually significant)45,172
52,868
Total accrued liabilities$219,462
$235,548

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. 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 base or “cushion gas” as property, plant and equipment. Cushion gas is 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.

The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs associated with non-legal retirement obligations related to our regulated properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other assets, except for crude oil and natural gas properties as described below, 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. Capitalized coal mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-utility power plant components, depreciation is computed on a unit-of-production methodology based on plant hours run.




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 continue to be amortized over their estimated useful lives.

We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired.  Beginning in 2016, we changed our annual goodwill impairment testing date from November 30 to October 1 to better align the testing date with our financial planning process.   We believe that the change in the date of the annual goodwill impairment test from November 30 to October 1 is not a material change in the application of an accounting principle.  The new and old testing dates are close in proximity and both are in the fourth quarter of the year. We would not expect a materially different outcome as a result of testing on October 1 as compared to November 30. The change in assessment date does not have a material effect on the financial statements.

We estimated the fair value of the goodwill using discounted cash flow methodology, EBITDA multiple method and an analysis of comparable transactions. This analysis required 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 and long-term earnings and merger multiples for comparable companies.

The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results. See Note 5 for additional business segment information.

Goodwill at our Electric Utilities primarily arose from Colorado Electric, acquired in the Aquila acquisition, which allocated approximately $246 million, or 72% of the transaction to Colorado Electric. Goodwill at our Gas Utilities is primarily from the SourceGas Acquisition, which was allocated entirely to the Gas Utilities adding $940 million in goodwill and the Aquila Transaction, which allocated approximately $94 million, or 28% of the transaction, to the Gas Utilities.

We believe that the goodwill reflects the inherent value of the relatively stable, long-lived cash flows of the regulated electric and gas utility businesses, considering the regulatory environment, and the long-lived cash flow and rate base growth opportunities at our utilities. Goodwill balances were as follows (in thousands):
 Electric UtilitiesGas UtilitiesPower GenerationTotal
Ending balance at December 31, 2015$248,479
$102,515
$8,765
$359,759
Additions (a)
—
939,695
—
939,695
Ending balance at December 31, 2016$248,479
$1,042,210
$8,765
$1,299,454
Additions—
—
—
—
Ending balance at December 31, 2017$248,479
$1,042,210
$8,765
$1,299,454
_________________
(a)Represents goodwill recorded with the acquisition of SourceGas. See Note 2 for more information.

Our intangible assets represent easements, rights-of-way, customer listings and trademarks. The finite-lived intangible assets are amortized using a straight-line method based on estimated useful lives; these assets are currently being amortized from 2 years to 40 years. Changes to intangible assets for the years ended December 31, were as follows (in thousands):
 201720162015
Intangible assets, net, beginning balance$8,392
$3,380
$3,176
Additions—
5,522
434
Amortization expense (a)
(833)(510)(230)
Intangible assets, net, ending balance$7,559
$8,392
$3,380
_________________
(a)Amortization expense for existing intangible assets is expected to be $0.8 million for each year of the next five years.



Asset Retirement Obligations

Accounting standards for asset retirement obligations 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 is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income (Loss). The accounting for the obligation for regulated operations 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. For oil and gas liabilities classified as held for sale, differences in the settlement of the liability and the recorded amount are generally reflected as adjustments to the capitalized cost of oil and gas properties and prior to held-for-sale classification were depleted pursuant to the use of the full cost method of accounting. Additional information is included in Note 8 and 21.


Fair Value Measurements


Derivative Financial Instruments


AssetsWe 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. This levelLevel 1 instruments primarily consistsconsist of highly liquid and actively traded financial instruments such as exchange-traded securities or listed derivatives.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 include significant inputs that 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

Electric Utilities and Gas Utilities Segments:


The wholesale electric energy and natural gas commodity contracts for the Electric and Gasour 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 natural gas contracts.. For exchanged-tradedexchange-traded futures, options and basis swap Level 2 assets and liabilities, fair value was derived using broker quotes validated by the Chicago Mercantile Exchangeexchange settlement pricing for similar instruments.the applicable contract. For over-the-counter swaps and option Level 2 assets and liabilities, fair value was derived from, or corroborated by, observable market pricing data. In addition,instruments, the fair value for the over-the-counter swaps and option derivatives include a CVA component. The CVA considers the fair value of the derivative and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings.

Corporate Segment:

Interest rate swaps are valued using the market valuation approach. We establish fair value by obtaining price quotes directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. The fair valueis obtained from the counterparty is then validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value, forwhich we validate by comparing our valuation with the interest rate swap derivativescounterparty. The fair value of these swaps includes a CVA component. The CVA considers the fair value of the interest rate swap and the probability of default based on the lifecredit spreads of the contract. For the probability of a default component,counterparties when we utilize observable inputs supporting Level 2 disclosure by usingare in an unrealized gain position or on our own credit default spread if available, or a generic credit default spread curve that takes into account our credit ratings. We have no interest rate swaps as of December 31, 2017.when we are in an unrealized loss position.


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


Derivatives and Hedging Activities


The accounting standards forAll our derivatives and hedging require that derivative instruments be recorded on the balance sheet as either an asset or liabilityare measured at its fair value and changes inrecognized as either assets or liabilities on the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met and designated accordingly, if they qualify for certain exemptions, including the normal purchases and normal sales exemption, or if regulatory rulings require a different accounting treatment. Changes in the fair value for derivative instruments that do not meet any of these criteria are recognized in the income statement as they occur. Each Consolidated Balance Sheet reflects the offsetting of netSheets, except for derivative positions with fair value amounts for cash collateral with the same counterparty when a legal right of offset exists.

Revenues and expenses on contracts that qualify as derivatives may befor and are elected under the normal purchasespurchase and normal sales exception and are recognized when the underlying physical transaction is completed under the accrual basis of accounting.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 pricepricing is not tiedclearly and closely related to an unrelated underlying derivative. As part of our electric and gas utility operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments toasset being purchased or sold. Normal purchase and sell energysales 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 retail and wholesale markets with the intent and ability to deliver or take delivery. If it was determined that a transaction designated as a normal purchase or normal sale no longer met the exceptions, the fair value of the related contract would be reflectedthese approved derivative contracts are deferred as either ana regulatory asset or regulatory liability underpursuant 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 accounting standards for derivatives and hedging.corresponding hedged transaction is recognized in earnings. Changes in the fair value of all other derivative contracts are recognized in earnings.


We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. We reflect the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when a legal right of offset exists. Therefore, the gross amounts are not indicative of either our actual credit or net economic exposures.


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. Deferred financingThese 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 followare 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 and reflect the effects of the numerous rate-making principles followed by the various state and federal agencies regulating the utilities. The accounting policies followed are generally subject to the Uniform System of Accounts of the FERC.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 rate recovery becomes unlikely or uncertain due to competition orchanges in the regulatory action, these accounting standardsenvironment occur, we may no longer be eligible to apply which could require these net regulatory assetsthis accounting treatment, and may be required to be charged to current income or OCI. Our regulatory assets represent amounts for which we will recover the cost, but generally are not allowed a return, except as described below. In the event we determine that our regulated net assets no longer meet the criteria for accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations, which could be material.

We had the followingeliminate regulatory assets and liabilities asfrom our balance sheet. Such changes could adversely affect our results of operations, financial position or cash flows.

As of December 31, (in thousands):
 Maximum  
 Amortization  
  (in years)20172016
Regulatory assets   
Deferred energy and fuel cost adjustments - current (a)
1$20,187
$17,491
Deferred gas cost adjustments (a)
131,844
15,329
Gas price derivatives (a)
311,935
8,843
Deferred taxes on AFUDC (b)
457,847
15,227
Employee benefit plans (c)
12109,235
108,556
Environmental (a)
subject to approval1,031
1,108
Asset retirement obligations (a)
44517
505
Loss on reacquired debt (a)
3020,667
22,266
Renewable energy standard adjustment (a)
51,088
1,605
Deferred taxes on flow through accounting (c)
5426,978
37,498
Decommissioning costs1013,287
16,859
Gas supply contract termination (a)
420,001
26,666
Other regulatory assets (a)
3032,837
24,189
  $297,454
$296,142
    
Regulatory liabilities   
Deferred energy and gas costs (a)
1$3,427
$10,368
Employee benefit plan costs and related deferred taxes (c)
1240,629
68,654
Cost of removal (a)
44130,932
118,410
Excess deferred income taxes (c) (d)
40301,553
62
Revenue subject to refund11,488
2,485
Other regulatory liabilities (c)
257,097
6,777
  $485,126
$206,756
__________
(a)Recovery of costs, but we are not allowed a rate of return.
(b)In addition to recovery of costs, we are 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.
(d)The increase in the regulatory tax liability is primarily related to the revaluation of deferred income tax balances at the lower income tax rate. As of December 31, 2017, all of the liability has been classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions or other revenue offsets in 2018.


Regulatory assets represent items2021 and 2020, we expect to recover from customers through probable future rates.

Deferred Energy and Fuel Cost Adjustments - Current - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our electric utility 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 commission. Our electric and gas 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 utility commissions.

Deferred Gas Cost Adjustment - 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 estimates of future gas costs based on market forecasts with state utility commissions.

Gas Price Derivatives - Our regulated utilities, as allowed or required by state utility 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. The 3-year term represents the maximum forward term hedged.

Deferred Taxes on AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a regulator’s action, it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment.

Employee Benefit Plans - 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 inhad total regulatory assets rather than in AOCI, including costs being amortized from the Aquilaof $797 million and SourceGas Transactions.$278 million respectively, and total regulatory liabilities of $503 million and $533 million respectively. See Note 2 for further information.

Environmental - Environmental expenditures are costs associated with manufactured gas plant sites. The amortization of this asset is first offset by recognition of insurance proceeds and settlements with other third parties. Any remaining recovery will be requested in future rate filings. Recovery has not yet been approved by the applicable commission or board and therefore, the recovery period is unknown.

Asset Retirement Obligations - Asset retirement obligations represent the estimated recoverable costs for legal obligations associated with the retirement of a tangible long-lived asset. See Note 8 for additional details.

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.

Renewable Energy Standard Adjustment - The renewable energy standard adjustment is associated with incentives for our Colorado Electric customers to install renewable energy equipment at their location. These incentives are recovered over time with an additional rider charged on customers’ bills.

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 in the year in which the tax benefits are realized and result in lower utility rates. 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.

Gas Supply Contract Termination - Black Hills Gas Holdings had agreements under the previous ownership that required the Company to purchase all of the natural gas produced over the productive life of specific leaseholds in


the Bowdoin Field in Montana. The majority of these purchases were committed to distribution customers in Nebraska, Colorado, and Wyoming, which are subject to cost recovery mechanisms. The prices to be paid under these agreements varied, ranging from $6 to $8 per MMBtu at the time of acquisition, and exceeded market prices. We recorded a liability for this contract in our purchase price allocation. We were granted approval to terminate these agreements from the NPSC, CPUC and WPSC, on the basis that these agreements are not beneficial to customers over the long term. We received written orders allowing us to create a regulatory asset for the net buyout costs associated with the contract termination, and recover the majority of costs from customers over a period of five years. We terminated the contract and settled the liability on April 29, 2016.

Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates.

Deferred Energy and Gas Costs - Deferred energy costs and gas costs related to over-recovery of purchased power, transmission and natural gas costs.

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 accounting standards for compensation - retirement benefits. In addition, this regulatory liability 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.

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 is recorded as an excess deferred income tax to be refunded to customers primarily using the normalization principles as prescribed in the TCJA.


Income Taxes


The Company and its subsidiaries file consolidated federal income tax returns. As a result of the SourceGas transaction, certain subsidiaries acquired file as a separate consolidated group. Where applicable, each tax-payingEach 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.

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA makes broad and complex changes to the U.S. tax code, including, but not limited to reducing the U.S. federal corporate tax rate from 35% to 21%. 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. As such, the Company has remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017.


It is our policy to apply the flow-through method of accounting for investment tax credits as allowed by our rate-regulated jurisdictions.ITCs. Under the flow-through method, investment tax creditsITCs 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 investment tax creditITC 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 benefit (expense) benefit on the Consolidated Statements of Income (Loss).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 from continuing and discontinued operations is computed by dividing Net income (loss) from continuing and discontinued operationsavailable 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, and outstanding stock options, restricted stock and performance shares under our equity compensation plans.


A reconciliation of share amounts used to compute earnings (loss) per share is as follows for the years ended December 31 (in thousands):
202120202019
Net income available for common stock$236,744 $227,608 $199,310 
Weighted average shares - basic63,219 62,378 60,662 
Dilutive effect of:
Equity compensation106 61 136 
Weighted average shares - diluted63,325 62,439 60,798 
Net income available for common stock, per share - Diluted$3.74 $3.65 $3.28 

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 201720162015
    
Net income (loss) available for common stock$177,034
$72,970
$(32,111)
    
Weighted average shares - basic53,221
51,922
45,288
Dilutive effect of:   
Equity Units1,783
1,222
—
Equity compensation116
127
—
Weighted average shares - diluted55,120
53,271
45,288
    
Net income (loss) available for common stock, per share - Diluted$3.21
$1.37
$(0.71)

Due to our Net loss available for common stock for the year ended December 31, 2015, potentially dilutedThe following securities were excluded from the diluted loss per share calculation due to their anti-dilutive effect. In computing diluted net loss per share, 83,000 equity compensation shares were excluded from the computation for the year ended December 31, 2015.

The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutivecomputation for the years ended December 31 because of their anti-dilutive nature (in thousands):
202120202019
Equity compensation13 60 1 
Anti-dilutive shares excluded from computation of earnings per share13 60 1 
 201720162015
    
Equity compensation11
3
112
Equity units—
—
6,440
Anti-dilutive shares excluded from computation of earnings (loss) per share11
3
6,552


Non-controlling Interests
Business Combinations

We record acquisitions in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. The excess of the purchase price over the estimated fair values of the net tangible and net intangible assets acquired is recorded as goodwill. The application of ASC 805, Business Combinations requires management to make significant estimates and assumptions in the determination of the fair value of assets acquired and liabilities assumed in order to properly allocate purchase price consideration between goodwill and assets that are depreciated and amortized. Our estimates are based on historical experience, information obtained from the management of the acquired companies and, when appropriate, include assistance from independent third-party appraisal firms. These estimates are inherently uncertain and unpredictable. In addition, unanticipated events or circumstances may occur which may affect the accuracy or validity of such estimates. See Note 2 for additional detail on the accounting for the SourceGas Acquisition.



Noncontrolling Interest

We account for changes in our controlling interests of subsidiaries according to ASC 810, Consolidations. 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 noncontrollingnon-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 noncontrollingnon-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 Noncontrolling Interests.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


Revenue from Contracts with Customers,Facilitation of the Effects of Reference Rate Reform on Financial Reporting, ASU 2014-092020-04


In May 2014,March 2020, the FASB issued ASU 2014-09, Revenue from Contracts with Customers.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. The standard provides relief for companies with a single modelpreparing for use in accountingdiscontinuation of interest rates, such as LIBOR, and allows optional expedients and exceptions for revenue arising fromapplying GAAP to contracts, with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017. Entities have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption.

We have implemented this standard effective January 1, 2018 on a modified retrospective basis. We have completed our assessment of all revenue from existing contracts with customers and there is no significant impact to our revenue recognition practices, financial position, results of operations or cash flows. A majority of our revenues are from regulated tariff offerings that provide natural gas or electricity with a defined contractual term, generally limited to the services requested and received to date for such arrangements. For such arrangements, the performance obligation transfer of control and revenue recognition occurs when the electricity or natural gas is delivered, consistent with the previous revenue recognition guidance. The same transfer of control and revenue recognition based on delivery principles also apply to our revenue contracts for wholesale and off-system power sales arrangements, coal supply agreements,hedging relationships and other non-regulated services. Therefore, we did not have a cumulative adjustment to Retained earnings or an impact on our revenue recognition policies as a result oftransactions affected by reference rate reform if certain criteria are met. The amendments in this update are elective and are effective upon the adoption of the new standard. The new standard will require us to provide more robust disclosures than required by previous guidance, including disclosures related to disaggregation of revenue into appropriate categories, performance obligations, and the judgments made in revenue recognition determinations.

Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07

In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The changes to the standard require employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. This ASU will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and post-retirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets will be applied on a prospective basis. This new guidance is effective for annual periods beginning afterissuance through December 15, 2017, including interim periods within those annual periods.31, 2022. We have implemented this standard effective January 1, 2018. For our rate-regulated entities,are currently evaluating if we will capitalizeapply the other components of net periodic benefit costs into


regulatory assets or regulatory liabilities and maintain a FERC to GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs will result in offsetting changes to Operating income and Other income, which are not expected to be material.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. The ASU will be effective for fiscal years beginning after December 15, 2017.We have implemented this standard effective January 1, 2018 using the retrospective transition method. This standard will not have a material impact on our financial position, results of operations or cash flows.

Leases, ASU 2016-02

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangementoptional guidance as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Under the current guidance, lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not towe assess whether certain land easements are, or contain, leases when transitioning to the new lease standard.

We currently expect to adopt this standard on January 1, 2019 and anticipate electing the transition approach to not assess existing or expired land easements that were not previously accounted for as a lease. We continue to evaluate the impact of this new standardthe discontinuance of LIBOR on our financial position, results of operationscurrent arrangements and cash flows as well as monitor emerging guidance on such topics as easements and rights of way, pipeline laterals, purchase power agreements, secondary use assets, and other industry-related areas. We continue the process of identifying and categorizing our lease contracts and evaluating our current business processes and systems.

Derivatives and Hedging: Targeted Improvement to Accounting for Hedging Activities, 2017-12

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvement to Accounting for Hedging Activities. This standard better aligns risk management activities and financial reporting for hedging relationships, simplifies hedge accounting requirements and improves disclosures of hedging arrangements. This ASU is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We are currently reviewing this standard to assess thepotential impact on our financial position, results of operations and cash flows.


Simplifying the Test for Goodwill Impairment, 2017-04

In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit. The new standard is effective for interim and annual reporting periods beginning after December 15, 2019, applied on a prospective basis with early adoption permitted. We do not anticipate the adoption of this guidance to have any impact on our financial position, results of operations or cash flows.



Recently Adopted Accounting Standards


Reclassification of Certain Tax Effects from Accumulated Other ComprehensiveSimplifying the Accounting for Income Taxes, ASU 2018-022019-12


In February 2018,December 2019, the FASB issued ASU 2018-02, Reclassification2019-12, Simplifying the Accounting for Income Taxes as part of Certain Tax Effects from Accumulated Other Comprehensive Income. This ASU was issuedits overall simplification initiative to address industry concerns regardingreduce costs and complexity in applying accounting standards while maintaining or improving the application of current accounting guidance to certain provisionsusefulness of the new tax reform legislation. This ASU permits entitiesinformation provided to make a one-time reclassification from AOCI to retained earnings for stranded tax effects resulting from the newly enacted corporate tax rate. The amountusers of the reclassificationfinancial statements. Amendments include removal of certain exceptions to the general principles of ASC 740, Income Taxes, and simplification in several other areas such as accounting for a franchise tax (or similar tax) that is calculatedpartially based on the basis of the difference between the historical and newly enacted tax rates for deferred tax liabilities and assets related to items within AOCI. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods therein, and early adoption is permitted.income. We have implementedadopted this ASU effective December 22, 2017, the enactment date of the TCJA, which resulted in a reclassification of $7.0 million of stranded tax effects from AOCI to retained earnings.standard prospectively on January 1, 2021. Adoption of this ASUstandard did not have a materialan impact on our consolidated financial position, results of operations or cash flows.


Improvements
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(2)    REGULATORY MATTERS

We had the following regulatory assets and liabilities as of December 31 (in thousands):
20212020
Regulatory assets
Winter Storm Uri (a)
$509,025 $— 
Deferred energy and fuel cost adjustments (b)
59,973 39,035 
Deferred gas cost adjustments (b)
9,488 3,200 
Gas price derivatives (b)
2,584 2,226 
Deferred taxes on AFUDC (b)
7,457 7,491 
Employee benefit plans and related deferred taxes (c)
88,923 116,598 
Environmental (b)
1,385 1,413 
Loss on reacquired debt (b)
21,011 22,864 
Deferred taxes on flow-through accounting (b)
63,243 47,515 
Decommissioning costs (b)
5,961 8,988 
Gas supply contract termination (b)
— 2,524 
Other regulatory assets (b)
27,549 26,404 
Total regulatory assets796,599 278,258 
Less current regulatory assets(270,290)(51,676)
Regulatory assets, non-current$526,309 $226,582 
Regulatory liabilities
Deferred energy and gas costs (b)
$6,113 $13,253 
Employee benefit plan costs and related deferred taxes (c)
32,241 40,256 
Cost of removal (b)
179,976 172,902 
Excess deferred income taxes (c)
264,042 285,259 
Other regulatory liabilities (c)
20,579 21,050 
Total regulatory liabilities502,951 532,720 
Less current regulatory liabilities(17,574)(25,061)
Regulatory liabilities, non-current$485,377 $507,659 
_____________________
(a)    Timing of Winter Storm Uri incremental cost recovery and associated carrying costs vary by jurisdiction and some jurisdictions are still subject to Employee Share-Based Payment Accounting, ASU 2016-09pending applications with the respective utility commission. See further information below.

(b)    Recovery of costs, but we are not allowed a rate of return.
(c)    In March 2016,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 FASB issued ASU 2016-09, Improvementscost of electricity delivered to Employee Share-Based Payment Accounting. This ASU simplifies several aspectsour 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. The recovery period for these costs is less than a year.

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 accounting for employee share-based payment transactions, includingupcoming gas costs and recovery or refund of prior under-recovered or over-recovered costs. To the accounting for forfeitures, income taxes, and statutory tax withholding requirements. The ASU was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. Certain amendments of this guidance are to be applied retrospectively and others prospectively. We implemented this ASU effective January 1, 2017, recording a cumulative-effect adjustment of $3.2 million to Retained earnings in the Consolidated Balance Sheets as of the date of adoption, representing previously recorded forfeitures and excess tax benefits generated in years prior to 2017extent that were previously not recognized in stockholders’ equity due to NOLs in those years. Adoption of this ASU did not have a material impact on our consolidated financial position, results of operations or cash flows.



(2)    ACQUISITION

Acquisition of SourceGas

On February 12, 2016, Black Hills Corporation acquired SourceGas, pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, including the assumption of $760 million in debt at closing. The purchase price was subject to post-closing adjustments for capital expenditures, indebtedness and working capital. Post-closing adjustments of approximately $11 million were agreed to and received from the sellers in June 2016.  SourceGas is a 100% owned subsidiary of Black Hills Utility Holdings, Inc., a wholly-owned subsidiary of Black Hills Corporation and has been renamed Black Hills Gas Holdings, LLC. Black Hills Gas Holdings primarily operates four regulated natural gas utilities serving approximately 429,000 customers in Arkansas, Colorado, Nebraska and Wyoming, and a 512-mile regulated intrastate natural gas transmission pipeline in Colorado.

Cash consideration of $1.135 billion paid on February 12, 2016 to close the SourceGas Acquisition included net proceeds of approximately $536 million from the November 23, 2015 issuance of 6.325 million shares of our common stock, 5.98 million equity units, and $546 million in net proceeds from our debt offerings on January 13, 2016. We funded the cash consideration and out-of-pocket expenses payable with the SourceGas Acquisition using the proceeds listed above, cash on hand, and draws under our revolving credit facility.

In connection with the acquisition, the Company recorded pre-tax, incremental acquisition costs of approximately $45 million and $10 million for the years ending December 31, 2016 and 2015, respectively. These costs consisted of transaction costs, professional fees, employee-related expenses and other miscellaneous costs. The costs are under-recovered or over-recovered, they are recorded primarily in Other operating expenses and Interest expense on the Consolidated Statements of Income (Loss).

as a regulatory asset or liability, respectively. Our consolidated operating results for the year ended December 31, 2016 include revenues of $348 million and net income (loss) of $15 million, attributable to SourceGas for the period from February 12 through December 31, 2016. The SourceGas operating results are reported in our Gas Utilities segment. We believe the SourceGas Acquisition enhances Black Hills Corporation’s utility growth strategy, providing greater operating scale, driving more efficient deliveryfile periodic estimates of services and benefiting customers.future gas costs based on market forecasts with state regulatory commissions. The recovery period for these costs is less than a year.


We accounted for the SourceGas Acquisition in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. Substantially all
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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, 2021 are accounted for in accordance with GAAP for regulated operations. SourceGas’ assets and liabilities subject to rate setting provisions provide revenues derived from costs, includinghedged over a returnmaximum forward term of two years.

Deferred Taxes on investmentAFUDC - The equity component of assets and liabilities included in rate base. As such, the fair value of these assets and liabilities equal their historical net book values.

The final purchase price allocation of the fair value of the assets acquired and liabilities assumedAFUDC is included in the table below. The cash consideration paid of $1.124 billion, net of long-term debt assumed of $760 million andconsidered a working capital adjustment received of approximately $11 million, resulted in goodwill of $940 million. We had up to one year from the acquisition date to finalize the purchase price allocation. The working capital adjustment received in 2016 of $11 million reflected changes in valuation estimates for intangible assets, accrued liabilities and deferred taxes. Approximately $252 million of the goodwill balance is amortizablepermanent difference for tax purposes relatingwith 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 partnership interests that were directly acquiredutility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment.

Employee Benefit Plans and Related Deferred Taxes - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plan and post-retirement benefit plans in regulatory assets rather than in AOCI. In addition, this regulatory asset includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate regulated environment.

Environmental - Environmental costs associated with certain former manufactured gas plant sites. These costs are first offset by recognition of insurance proceeds and settlements with other third parties. Any remaining cost will be requested for recovery in future rate filings. Recovery for these specific environmental costs has not yet been approved by the applicable state regulatory commission and therefore, the recovery period is unknown at this time.

Loss on Reacquired Debt - Loss on reacquired debt is recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue.

Deferred Taxes on Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer and result in lower utility rates in the transaction. The remainderyear 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 goodwill balance is not amortizable for tax purposes. Goodwill generated from the acquisition reflects the benefitsremaining net book values and decommissioning costs of increased operating scaletheir decommissioned coal plants. In 2018, Arkansas Gas received approval to record Liquefied Natural Gas Plant decommissioning costs as a regulatory asset and organic growth opportunities.received approval in 2020 to begin recovering those costs over three years.



 (in thousands)
Purchase Price  $1,894,882
Less: Long-term debt assumed  (760,000)
Less: Working capital adjustment received  (10,644)
 Consideration paid, net of working capital adjustment received  $1,124,238
    
Allocation of Purchase Price:   
Current Assets  $112,983
Property, plant & equipment, net  1,058,093
Goodwill  939,695
Deferred charges and other assets, excluding goodwill  133,299
Current liabilities  (172,454)
Long-term debt  (758,874)
Deferred credits and other liabilities  (188,504)
Total consideration paid, net of working-capital adjustment received  $1,124,238

Conditions of SourceGas Acquisition Regulatory Approval

The acquisition was subject to regulatory approvals from the public utility commissions in Arkansas (APSC), Colorado (CPUC), Nebraska (NPSC), and Wyoming (WPSC). Approvals were obtained from all commissions, subject to various conditions as set forth below:

The APSC order includes a twelve-month base rate moratorium, an annual $0.25 million customer credit for a term of up to five years or until we file the next rate review, whichever comes first, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate review, as well as various other terms and reporting requirements.

The CPUC order includes a two-year base rate moratorium for our regulated transmission and wholesale natural gas provider, a three-year base rate moratorium for our regulated gas distribution utility, an annual $0.2 million customer credit for a term of up to five-years or until we file the next rate review, whichever comes first, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements.

The NPSC order includes a three-year base rate moratorium, a three-year continuation of the Choice Gas Program, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate review, as well as various other terms and reporting requirements.

The WPSC order includes a three-year continuation of the Choice Gas Program, as well as various other terms and reporting requirements.

All four orders also disallowed recovery of goodwill and transaction costs. Recovery of transition costs is disallowed in Arkansas, Colorado and Nebraska. However, Wyoming allows for request of recovery of transition costs. Transition costs are those non-recurring costs related to the transition and integration of SourceGas. In the conditions mentioned above, the orders that include base rate moratoriums over a specified period of time do not impact our ability to adjust rates through riders or gas supply cost recovery mechanisms as allowed under the current enacted state tariffs. In certain cases, we may file for leave to increase general base rates and/or cost of sales recovery limited to material adverse changes, but only if there are changes in law or regulations or the occurrence of other extraordinary events outside of our control which result in a material adverse change in revenues, revenue requirement and/or increase in operating costs.

Settlement of Gas Supply Contract

On April 29, Termination - With the 2016 SourceGas acquisition, we settled for $40 million, a former SourceGas contract that requiredassumed agreements requiring the Company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. This contract’s intangible negative fair value is included with Current liabilities in the purchase price allocation. Approximately 75% of these purchases were committed to distribution customers in Nebraska, Colorado and Wyoming, which are subject to cost recovery mechanisms, while the remaining 25% was not subject to regulatory recovery. The prices to be paid under this contract varied,


ranging from $6 to $8 per MMBtuthese agreements exceeded market prices at the time of acquisition and exceeded market prices.acquisition. We applied for and were granted approvalreceived state utility commission approvals to terminate this agreement fromthese agreements and Orders allowing us to create a regulatory asset for the NPSC, CPUCnet contract buyout costs with recovery over five years. We terminated the contract and WPSC,settled the liability on the basisApril 29, 2016.

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 the agreement was not beneficialhave 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 long term.cumulative excess of pension and retiree healthcare costs recovered in rates over pension expense recorded in accordance with accounting standards for compensation - retirement benefits. In addition, this regulatory liability 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.

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.

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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, a prolonged period of historic cold temperatures across the central United States covered all of our Utilities’ service territories, 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 of Winter Storm Uri, 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. These incremental cost estimates are subject to adjustments as final decisions are issued by the respective utility commissions. In these applications, we sought approval to recover carrying costs. For the year ended December 31, 2021, $4.1 million of carrying costs were accrued and recorded to a regulatory asset. We received written orders allowingare also seeking recovery of $13 million of previously disclosed Winter Storm Uri incremental costs through our existing regulatory mechanisms.

To date, Iowa Gas, Kansas Gas, Nebraska Gas and South Dakota Electric received commission approval for Winter Storm Uri cost recovery. Additionally, Arkansas Gas and Wyoming Gas received approval for interim cost recovery subject to a final decision on carrying costs and recovery periods at a later date. Colorado Gas and Colorado Electric filed settlement agreements for their applications with final rates to be implemented in 2022. These settlements are subject to final approval by the net buyoutCPUC. For the year ended December 31, 2021, our Utilities collected $40 million of Winter Storm Uri incremental costs associated withand carrying costs from customers.

TCJA

On December 22, 2017, the contract termination that were allocatedU.S. government enacted comprehensive tax legislation commonly referred to regulated subsidiaries. These costs were recorded as athe TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. As such, the Company remeasured our deferred income taxes at the 21% federal tax rate as of December 31, 2017. In 2018 and 2019, the Company successfully delivered several of these tax benefits from the TCJA to its utility customers.

In 2020, regulatory asset of approximately $30 million that is being recovered over a five-year period beginning April 29, 2016.

Pro Forma Results (unaudited)

We calculatedproceedings resolved the pro forma impactlast of the SourceGas Acquisition andCompany’s open dockets seeking approval of its TCJA plans. As a result, the associated debt and equity financings on our operating resultsCompany relieved certain TCJA-related liabilities, which resulted in an increase to net income for the year ended December 31, 2016 and 2015.2020 of $4.0 million.

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 following pro forma results give effect to the acquisition, assuming the transaction closed on January 1, 2015:
  Pro Forma Results
  December 31,
  20162015
  (in thousands, except per share amounts)
Revenue $1,617,878
$1,720,618
Income from continuing operations $177,040
$160,290
Net income (loss) $112,878
$(13,369)
Earnings from continuing operations per share, Basic $3.41
$3.15
Earnings from continuing operations per share, Diluted $3.32
$3.15

We derived the pro forma results for the SourceGas Acquisition based on historical financial information obtainedbill credits, which represent a disposition of excess deferred income tax benefits resulting from the sellers and certain management assumptions. Our pro forma adjustments relateTCJA, were delivered to incremental interest expensecustomers in February 2021. The settlement agreement further provided for Colorado Electric to deliver annual bill credits to customers, starting in April 2021, until remaining excess deferred income tax regulatory liabilities associated with the financingsTCJA are fully amortized. In April 2021, Colorado Electric delivered $0.9 million of TCJA-related bill credits to effectcustomers.

On January 26, 2021, the transaction,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.

These Colorado Electric and Nebraska Gas 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, 2015, also include adjustments to shares outstanding to reflect the equity issuances as if they had occurred on January 1, 2015, and to reflect pro forma dilutive effects of the equity units issued. The pro forma results do not reflect any cost savings, (or associated costs to achieve such savings) from operating efficiencies or restructuring that could result from the acquisition, and exclude any unique one-time items resulting from the acquisition that are not expected to have a continuing impact on the combined consolidated results. Pro forma results for the year ended December 31, 2016 reflect unfavorable weather impacts resulting in lower gas usage by our customers than in the same periods of the prior year. In addition, we calculated the tax impact of these adjustments at an estimated combined federal and state income tax rate of 37%.2021.

These pro forma results are for illustrative purposes only and do not purport to be indicative of the results that would have been obtained had the SourceGas Acquisition been completed on January 1, 2015, or that may be obtained in the future.

Seller’s noncontrolling interest


As part of the SourceGas Transaction,2021 rate review settlement agreement discussed further below, Kansas Gas will deliver $3.0 million of TCJA and state tax reform benefits to customers, annually, for each of the next three years starting in 2022 (approximately $9.1 million of total benefits expected to be delivered).
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Arkansas Gas

On December 10, 2021, Arkansas Gas filed a seller retainedrate review with the APSC seeking recovery of significant infrastructure investments in its 7,200-mile natural gas pipeline system. The rate review requests $22 million in new annual revenue with a 0.5% noncontrolling interestcapital structure of 50.9% equity and we entered into an associated option49.1% debt and a return on equity of 10.2%. The request seeks to finalize rates in the fourth quarter of 2022.

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 holderCPUC 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 will shift $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.

Nebraska Gas

Jurisdictional Consolidation and Rate Review

On January 26, 2021, Nebraska Gas received approval from the NPSC to consolidate rate schedules into a new, single statewide structure and recover significant infrastructure investments in its 13,000-mile natural gas pipeline system. Final rates were enacted on March 1, 2021, which replaced interim rates effective September 1, 2020. The approval shifted $4.6 million of SSIR revenue to base rates and is expected to generate $6.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 9.5%. The approval also included an extension of the SSIR for five years and an expansion of this mechanism across the consolidated jurisdictions.

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, 2021, the annual revenue requirement for the 0.5% retained interest.FERC Transmission Formula Rate was $26 million and included estimated weighted average capital additions of $5.0 million for 2020 and 2021 combined.
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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 continue for 11 years.


(3)    COMMITMENTS, CONTINGENCIES AND GUARANTEES

Power Purchase and Transmission Services Agreements

Through our subsidiaries, we have the following significant long-term power purchase contracts and transmission services agreement with non-affiliated third-parties:

SubsidiaryContract TypeCounterpartyFuel TypeQuantity (MW)Expiration Date
Colorado Electric (a)
PPAPRPAWind60May 31, 2030
Colorado ElectricPPAPRPACoal25June 30, 2024
Colorado ElectricPPATC Colorado Solar, LLCSolar200
Pending Completion (b)
South Dakota ElectricPPAPacifiCorpCoal50December 31, 2023
South Dakota Electric (c)
Transmission Services AgreementPacifiCorpN/A50December 31, 2023
South Dakota ElectricPPAPRPAWind12September 30, 2029
South Dakota ElectricPPAFall River Solar, LLCSolar80
Pending Completion (d)
Wyoming Electric (e)
PPAHappy JackWind30September 3, 2028
Wyoming Electric (f)
PPASilver SageWind30September 30, 2029
____________________
(a)    Colorado Electric sells the wind energy purchased under this PPA to City of Colorado Springs as discussed below.
(b)    On January 31, 2022, TC Colorado Solar, LLC (TC Solar) provided termination notice of the PPA to Colorado Electric. Colorado Electric has disputed TC Solar’s right to termination and pursuant to the agreement, has initiated discussions with TC Solar. This agreement relates to a new solar facility to be constructed and would expire 15 years after construction completion.
(c)    This is a firm point-to-point transmission service agreement providing the ability to deliver a maximum of 50 MW of capacity and associated energy.
(d)    This agreement relates to a new solar facility currently being constructed and will expire 20 years after construction completion, which is expected by the end of 2022.
(e)    Under a separate intercompany PSA, Wyoming Electric sells 50% of the facility output to South Dakota Electric.
(f)    Under a separate intercompany PSA, Wyoming Electric sells 67% of the facility output to South Dakota Electric.

Costs under these agreements for the years ended December 31 were as follows (in thousands):
SubsidiaryContract TypeCounterpartyFuel Type202120202019
Colorado ElectricPPAPRPAWind$4,246 $2,791 $— 
Colorado ElectricPPAPRPACoal$4,447 $4,524 $1,802 
South Dakota ElectricPPAPacifiCorpCoal$8,923 $5,897 $7,477 
South Dakota ElectricTransmission Services AgreementPacifiCorpN/A$1,783 $1,776 $1,741 
South Dakota ElectricPPAPRPAWind$596 $715 $688 
Wyoming ElectricPPAHappy JackWind$3,544 $4,531 $3,936 
Wyoming ElectricPPASilver SageWind$4,717 $6,203 $5,366 
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Power Purchase Agreements - Related Parties

Wyoming Electric had a PPA with Black Hills Wyoming scheduled to expire on December 31, 2022, which provided 60 MW of unit-contingent capacity and energy from Black Hills Wyoming’s Wygen I facility. On October 15, 2020, the FERC approved a settlement agreement 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 facility. The new agreement commenced on January 1, 2022, replaced the existing PPA and will continue for 11 years.

Black Hills Electric Generation provides the wind energy generated from Busch Ranch II to Colorado Electric through a PPA, which expires in November 2044.

Black Hills Electric Generation provides its 14.5 MW share of energy generated from Busch Ranch I to Colorado Electric through a PPA, which expires in October 2037.

Colorado Electric’s PPA with Black Hills Colorado IPP, expiring on December 31, 2031, provides 200 MW of power to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines.

Purchase Commitments

We maintain natural gas supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated baseload gas volumes are established prior to the beginning of the month under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month based on requirements in accordance with the terms of the individual contract.

Our Gas Utilities segment has 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. At December 31, 2021, the long-term commitments to purchase quantities of natural gas under contracts indexed to the following forward indices were as follows (in MMBtus):

20222023202420252026Thereafter
El Paso - Bondad Station31,000—————
Kern River - Opal9,300—————
El Paso - San Juan Basin182,550—————
Enable East Pipeline1,825,000450,000————
Northern Natural Gas - Demarc1,614—————
Northern Natural Gas - Ventura1,810,0001,840,0001,820,000———
Northwest Pipeline - Wyoming1,531,7001,510,000910,000———
ONEOK - Oklahoma5,475,0005,475,0005,490,0004,560,000——
Southern Star Central Gas Pipeline113,130—————
Panhandle Eastern Pipe Line1,609,6802,737,500————
12,588,97412,012,5008,220,0004,560,000——

Purchases under these contracts totaled $61 million, $25 million and $7 million for 2021, 2020 and 2019, respectively.

Other Gas Supply Agreements

Our Utilities also 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.
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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):
Power purchase and transmission services agreements (a)
Natural gas transportation and storage agreements
2022$23,985 $143,750 
2023$11,678 $119,923 
2024$2,738 $82,428 
2025$— $58,669 
2026$— $36,503 
Thereafter$— $60,429 
____________________
(a)    This schedule does not reflect renewable energy PPA obligations since these agreements vary based on weather conditions.

Power Sales Agreements

Through our subsidiaries, we have the following significant long-term power sales contracts with non-affiliated third-parties:

•On July 1, 2020, Colorado Electric entered into a PSA with the City of Colorado Springs to sell up to 60 MW of wind energy purchased from PRPA under a separate 60 MW PPA discussed above. This PSA with the City of Colorado Springs expires June 30, 2025.

•During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, South Dakota Electric will provide MDU with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU. This agreement expires January 31, 2023.

•South Dakota Electric has an agreement to provide MDU capacity and energy up to a maximum of 50 MW in excess of Wygen III ownership. This agreement expires December 31, 2023.

•During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, South Dakota Electric will provide the City of Gillette with its first 23 MW from its other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, which has an initial term through September 3, 2034 and would be renewed annually on September 3 thereafter, South Dakota Electric will also provide the City of Gillette their operating component of spinning reserves.

•South Dakota Electric has an amended agreement, effective January 1, 2019, to supply up to 20 MW of energy and capacity to MEAN under a contract that expires May 31, 2028. The contract terms are from June 1 through May 31 for each interval listed below. This contract is unit-contingent based on the availability of our Neil Simpson II and Wygen III plants, with decreasing capacity purchased over the term of the agreement. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows:
Contract YearsTotal Contract CapacityContingent Capacity Amounts on Wygen IIIContingent Capacity Amounts on Neil Simpson II
2020-202215 MW7 MW8 MW
2022-202315 MW8 MW7 MW
2023-202810 MW5 MW5 MW

•South Dakota Electric had an agreement that expired December 31, 2021 to provide 50 MW of energy to Macquarie Energy, LLC during heavy and light load timing intervals.

•Black Hills Wyoming sold its CTII 40 MW natural gas-fired generating unit to the City of Gillette, Wyoming on September 3, 2014. Under the terms of the sale, Black Hills Wyoming entered into ancillary agreements to operate CTII, provide use of shared facilities including a ground lease and dispatch generation services. In March 2017,addition, the agreement includes a 20-year Economy Energy PSA that contains a sharing arrangement in which the parties share the savings of wholesale power purchases made when market power prices are less than the cost of operating the generating unit.

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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 34 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, 2021, 2020 and 2019.

As of December 31, 2021, scheduled maturities of operating lease payments to be received in future years were as follows (in thousands):
Operating Leases
2022$2,173 
20232,204 
20242,125 
20252,070 
20261,881 
Thereafter51,233 
Total lease receivables$61,686 

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 exercisedmay 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 call optionPueblo 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 purchasedprocessing for this zero discharge facility. The reclamation liability is recorded at the remaining 0.5% equity interestpresent 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 SourceGasNebraska and Iowa, which were previously used to convert coal to natural gas. The acquisition provided for $5.6 million.an insurance recovery, now valued at $1.2 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 $1.4 million regulatory asset for manufactured gas processing sites; see Note 2 for additional information.



As of December 31, 2021, we had $2.6 million accrued for remediation of Iowa’s manufactured gas processing site as the landowner. As of December 31, 2021, 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.




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(3)    

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.

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 GuaranteeDecember 31, 2021
Indemnification for reclamation/surety bonds$55,867 
Guarantees supporting business transactions$370,558 
$426,425 


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(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, 2021, 2020 and 2019. Sales tax and other similar taxes are excluded from revenues.
Year ended December 31, 2021 Electric Utilities Gas UtilitiesInter-company RevenuesTotal
Customer types:(in thousands)
Retail$711,448 $913,725 $— $1,625,173 
Transportation— 158,053 (428)157,625 
Wholesale30,848 — — 30,848 
Market - off-system sales41,682 396 — 42,078 
Transmission/Other52,945 39,365 (17,200)75,110 
Revenue from contracts with customers836,923 1,111,539 (17,628)1,930,834 
Other revenues5,335 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 time809,782 1,111,539 (17,628)1,903,693 
Revenue from contracts with customers$836,923 $1,111,539 $(17,628)$1,930,834 
Year ended December 31, 2020 Electric Utilities Gas UtilitiesInter-company RevenuesTotal
Customer types:(in thousands)
Retail$636,902 $765,922 $— $1,402,824 
Transportation— 154,581 (526)154,055 
Wholesale24,845 — — 24,845 
Market - off-system sales15,512 260 — 15,772 
Transmission/Other55,422 43,658 (15,772)83,308 
Revenue from contracts with customers732,681 964,421 (16,298)1,680,804 
Other revenues6,176 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 time705,592 964,421 (16,298)1,653,715 
Revenue from contracts with customers$732,681 $964,421 $(16,298)$1,680,804 
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Year ended December 31, 2019 Electric Utilities Gas UtilitiesInter-company RevenuesTotal
Customer types:(in thousands)
Retail$632,936 $817,840 $— $1,450,776 
Transportation— 143,390 (1,042)142,348 
Wholesale28,464 — — 28,464 
Market - off-system sales16,081 691 — 16,772 
Transmission/Other53,750 47,725 (13,443)88,032 
Revenue from contracts with customers731,231 1,009,646 (14,485)1,726,392 
Other revenues8,124 384 — 8,508 
Total revenues$739,355 $1,010,030 $(14,485)$1,734,900 
Timing of revenue recognition:
Services transferred at a point in time$27,180 $— $— $27,180 
Services transferred over time704,051 1,009,646 (14,485)1,699,212 
Revenue from contracts with customers$731,231 $1,009,646 $(14,485)$1,726,392 


(5)    PROPERTY, PLANT AND EQUIPMENT


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

20212020Lives (in years)
Electric UtilitiesProperty, Plant and EquipmentWeighted Average Useful Life (in years)Property, Plant and EquipmentWeighted Average Useful Life (in years)MinimumMaximum
Electric plant:
Production$1,452,055 41$1,417,951 403245
Electric transmission546,126 49517,794 494350
Electric distribution1,000,619 47959,453 464549
Integrated Generation720,490 30716,479 31259
Plant acquisition adjustment (a)
4,870 324,870 323232
General266,935 28259,010 282531
Total electric plant in service3,991,095 3,875,557 
Construction work in progress181,451 95,266 
Total electric plant4,172,546 3,970,823 
Less accumulated depreciation and depletion(1,016,738)(960,993)
Electric plant net of accumulated depreciation and depletion$3,155,808 $3,009,830 
____________________
(a)    The plant acquisition adjustment is included in rate base and is being recovered with 9 years remaining.
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 20172016Lives (in years)
Electric UtilitiesProperty, Plant and EquipmentWeighted Average Useful Life (in years)Property, Plant and EquipmentWeighted Average Useful Life (in years)MinimumMaximum
       
Electric plant:      
Production$1,315,044
39$1,303,101
413055
Electric transmission407,203
51354,801
524070
Electric distribution755,213
48712,575
481575
Plant acquisition adjustment (a)
4,870
324,870
323232
General232,842
31164,761
25365
Capital lease - plant in service (b)
261,441
20261,441
202020
Total electric plant in service2,976,613
 2,801,549
   
Construction work in progress13,595
 74,045
   
Total electric plant2,990,208
 2,875,594
   
Less accumulated depreciation and amortization644,022
 578,162
   
Electric plant net of accumulated depreciation and amortization$2,346,186
 $2,297,432
   

_____________
(a)The plant acquisition adjustment is included in rate base and is being recovered with 13 years remaining.
(b)Capital lease - plant in service represents the assets accounted for as a capital lease under the PPA between Colorado Electric and Black Hills Colorado IPP. The capital lease ends in conjunction with the expiration of the PPA on December 31, 2031.

20212020Lives (in years)
Gas UtilitiesProperty, Plant and EquipmentWeighted Average Useful Life (in years)Property, Plant and EquipmentWeighted Average Useful Life (in years)MinimumMaximum
Gas plant:
Production$14,841 40$15,603 402446
Gas transmission645,550 58578,278 542271
Gas distribution2,394,352 532,115,082 534559
Cushion gas - depreciable (a)
3,539 283,539 282828
Cushion gas - not depreciable (a)
42,478 N/A39,184 N/AN/AN/A
Storage56,289 3855,481 382752
General474,964 21438,217 19323
Total gas plant in service3,632,013 3,245,384 
Construction work in progress37,860 67,229 
Total gas plant3,669,873 3,312,613 
Less accumulated depreciation(389,115)(323,679)
Gas plant net of accumulated depreciation$3,280,758 $2,988,934 
____________________

(a)    Depreciation of Cushion Gas is determined by the respective regulatory jurisdiction in which the Cushion Gas resides.



2021Lives (in years)
Property, Plant and EquipmentConstruction Work in ProgressTotal Property Plant and EquipmentLess Accumulated DepreciationNet Property, Plant and EquipmentWeighted Average Useful LifeMinimumMaximum
Corporate$5,694 $8,460 $14,154 $(1,544)$12,610 101022


2020Lives (in years)
Property, Plant and EquipmentConstruction Work in ProgressTotal Property Plant and EquipmentLess Accumulated DepreciationNet Property, Plant and EquipmentWeighted Average Useful LifeMinimumMaximum
Corporate$5,692 $16,402 $22,094 $(1,144)$20,950 101022


 20172016Lives (in years)
Gas UtilitiesProperty, Plant and EquipmentWeighted Average Useful Life (in years)Property, Plant and EquipmentWeighted Average Useful Life (in years)MinimumMaximum
       
Gas plant:      
Production$10,495
35$10,821
351771
Gas transmission366,433
48338,729
482270
Gas distribution1,413,431
421,303,366
423347
Cushion gas - depreciable (a)
3,539
283,539
282828
Cushion gas - not depreciated (a)
47,466
047,055
000
Storage28,520
3127,686
311548
General336,869
19339,382
19344
Total gas plant in service2,206,753
 2,070,578
   
Construction work in progress44,440
 28,446
   
Total gas plant2,251,193
 2,099,024
   
Less accumulated depreciation and amortization229,170
 194,585
   
Gas plant net of accumulated depreciation and amortization$2,022,023
 $1,904,439
   
_____________
(a)Cushion gas is 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. Depreciation of cushion gas is determined by the respective regulatory jurisdiction in which the cushion gas resides.

2017Lives (in years)
 Property, Plant and EquipmentConstruction Work in ProgressTotal Property Plant and EquipmentLess Accumulated Depreciation, Depletion and AmortizationNet Property, Plant and EquipmentWeighted Average Useful LifeMinimumMaximum
         
Power Generation$155,569
$224
$155,793
$57,813
$97,980
33240
Mining158,370
—
158,370
108,844
49,526
14259

2016Lives (in years)
 Property, Plant and EquipmentConstruction Work in ProgressTotal Property Plant and EquipmentLess Accumulated Depreciation, Depletion and AmortizationNet Property, Plant and EquipmentWeighted Average Useful LifeMinimumMaximum
         
Power Generation$161,430
$1,298
$162,728
$55,157
$107,571
33240
Mining151,709
4,642
156,351
105,219
51,132
13259




2017Lives (in years)
 Property, Plant and EquipmentConstruction Work in ProgressTotal Property Plant and EquipmentLess Accumulated Depreciation, Depletion and Amortization
Add Accumulated Depreciation - Capital Lease Elimination (a)
Net Property, Plant and EquipmentWeighted Average Useful LifeMinimumMaximum
Corporate$5,580
$6,374
$11,954
$309
$14,070
$25,715
8330
___________
(a)Reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP of $14 million.

2016Lives (in years)
 Property, Plant and EquipmentConstruction Work in ProgressTotal Property Plant and EquipmentLess Accumulated Depreciation, Depletion and Amortization
Add Accumulated Depreciation - Capital Lease Elimination (a)
Net Property, Plant and EquipmentWeighted Average Useful LifeMinimumMaximum
Corporate$9,625
$11,974
$21,599
$2,106
$6,110
$25,603
8330
___________
(a)Reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP of $6.1 million.

(4)    (6)    JOINTLY OWNED FACILITIES

Utility Plant


Our consolidated financial statements include our share of several jointly-owned utility facilities as described below. Our share of the facilities’ expenses are reflected in the appropriate categories of operating expenses in the Consolidated Statements of Income (Loss).Income. Each owner of the facility is responsible for financing its investment in the jointly-owned facilities.


Wyodak Plant

South Dakota Electric owns a 20% interest in the Wyodak Plant a coal-fired electric generating station located in Campbell County, Wyoming.while PacifiCorp owns the remaining ownership percentageinterest and operates the Wyodak Plant. South Dakota Electric receives its proportionate share of the Wyodak Plant’s capacity and is committed to pay its proportionate share of its additions, replacements and operating and maintenance expenses. In addition to supplying South Dakota Electric with coal for its share of the Wyodak Plant, our Mining subsidiary, WRDC,mine supplies PacifiCorp’s share of the coal to the Wyodak Plant 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.


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Transmission Tie

South Dakota Electric also owns a 35% interest in, and is the operator of, the Converter Station Site and South Rapid City Interconnection (the transmission tie)Transmission Tie), an AC-DC-AC transmission tie. Basin Electric Power Cooperative owns the remaining ownership percentage. The transmission tie provides an interconnection between65% interest in the Western and Eastern transmission grids, which provides us with access to both the WECC region and the MAPP region. The total transfer capacity of the tie is 400 MW, including 200 MW from West to East and 200 MW from East to West.Transmission Tie. South Dakota Electric is committed to pay its proportionate share of the additions and replacements and operating and maintenance expenses of the transmission tie.Transmission Tie.


Wygen III

South Dakota Electric owns 52% of the Wygen III coal-fired generation facility. MDU and the City of Gillette each ownsown an undivided ownership interest in Wygen III and are obligated to make payments for costs associated with administrative services and their proportionate share of the costs of operating the plant for the life of the facility. We retainSouth Dakota Electric retains responsibility for plant operations. Our Mining subsidiarymine supplies coalfuel to Wygen III for the life of the plant.


Colorado Electric owns 50% of the Busch Ranch Wind Farm while AltaGas owns the remaining undivided ownership interest and is obligated to make payments for costs associated with their proportionate share of the costs of operating the wind farm for the life of the facility. We retain responsibility for operations of the wind farm.
Wygen I






Non-Regulated Plants

Our consolidated financial statements include our share of a jointly-owned non-regulated power generation facility as described below. Our share of direct expenses for the jointly-owned facility is included in the corresponding categories of operating expenses in the accompanying Consolidated Statements of Income (Loss). Each of the respective owners is responsible for providing its own financing.

Black Hills Wyoming owns 76.5% of the Wygen I plant while MEAN owns the remaining ownership percentage.interest. MEAN is obligated to make payments for its share of the costs associated with administrative services, plant operations and coal supply provided by our Mining subsidiarymine during the life of the facility. We retainBlack Hills Wyoming retains responsibility for plant operations.


At December 31, 2017,2021, our interests in jointly-owned generating facilities and transmission systems were (in thousands):
Plant in ServiceConstruction Work in ProgressLess Accumulated DepreciationPlant Net of Accumulated Depreciation
Wyodak Plant$118,637 $882 $(70,468)$49,051 
Transmission Tie$24,544 $287 $(6,922)$17,909 
Wygen III$142,199 $635 $(26,598)$116,236 
Wygen I$120,565 $399 $(53,784)$67,180 

Jointly Owned Facilities - Related Party

Busch Ranch I

Colorado Electric owns 50% of Busch Ranch I while Black Hills Electric Generation owns the remaining 50% ownership interest. Each company is obligated to make payments for costs associated with their proportionate share of the costs of operating the wind farm over the life of the facility. Colorado Electric retains responsibility for operations of 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.

Cheyenne Prairie

Cheyenne Prairie 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 South Dakota Electric (58 MW) and Wyoming Electric (42 MW). BHSC is responsible for plant operations.

Corriedale

Corriedale serves as the dedicated wind energy supply for Renewable Ready customers in South Dakota and Wyoming. The 52.5 MW wind farm is jointly-owned by South Dakota Electric (32.5 MW) and Wyoming Electric (20 MW). BHSC is responsible for operations of the wind farm.

87
 Plant in ServiceConstruction Work in ProgressAccumulated Depreciation
Wyodak Plant$114,405
$727
$58,955
Transmission Tie$20,037
$242
$6,215
Wygen I$109,552
$209
$40,465
Wygen III$138,688
$406
$19,239
Busch Ranch Wind Farm$18,899
$—
$3,858

(7)    ASSET RETIREMENT OBLIGATIONS

(5)    BUSINESS SEGMENT INFORMATIONWe have identified legal obligations related to reclamation of mining sites; removal of fuel tanks, transformers containing polychlorinated biphenyls, and 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 and wells 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.


Our reportable segmentsThe following tables present the details of AROs which are basedincluded on our method of internal reporting, which is generally segregated by differencesthe accompanying Consolidated Balance Sheets in products, servicesOther deferred credits and regulation. All of our operations and assets are located within the United States.

Segment information was as followsother liabilities (in thousands):
December 31, 2020Liabilities IncurredLiabilities SettledAccretionRevisions to Prior EstimatesDecember 31, 2021
Electric Utilities$29,157 $— $(978)$1,315 $595 $30,089 
Gas Utilities (a)
42,274 — (66)1,733 1,514 45,455 
Total71,431 $— $(1,044)$3,048 $2,109 $75,544 
Total Assets (net of intercompany eliminations) as of December 31,20172016
Electric (a)
$2,906,275
$2,859,559
Gas3,426,466
3,307,967
Power Generation (a)
60,852
73,445
Mining65,455
67,347
Corporate and Other115,612
112,760
Discontinued operations (b)
84,242
120,695
Total assets$6,658,902
$6,541,773

__________________
(a)The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.
(b)On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. See Note 21 for additional information.

December 31, 2019Liabilities IncurredLiabilities SettledAccretionRevisions to Prior EstimatesDecember 31, 2020
Electric Utilities (b) (c)
$28,120 $1,217 $(185)$1,230 $(1,225)$29,157 
Gas Utilities (d)
36,085 4,782 (132)1,539 — 42,274 
Total$64,205 $5,999 $(317)$2,769 $(1,225)$71,431 

____________________

(a)    The Revisions to Prior Estimates were primarily driven by changes in estimates associated with natural gas wells.
(b)    Liabilities incurred were related to new wind assets.
Capital Expenditures and Asset Acquisitions (a) for the years ended December 31,
20172016
Capital expenditures  
Electric Utilities$138,060
$258,739
Gas Utilities184,389
173,930
Power Generation1,864
4,719
Mining6,708
5,709
Corporate and Other6,668
17,353
Total capital expenditures337,689
460,450
Asset acquisitions  
Gas Utilities (b)
—
1,124,238
Total capital expenditures and asset acquisitions of continuing operations337,689
1,584,688
Total capital expenditures of discontinued operations23,222
6,669
Total capital expenditures and asset acquisitions$360,911
$1,591,357
(c)    The Revisions to Prior Estimates were primarily driven by changes in estimated costs associated with back-filling the pit with overburden removed during the mining process.
_________________
(a)Includes accruals for property, plant and equipment.
(b)SourceGas was acquired on February 12, 2016. Net cash paid of $1.124 billion was net of long-term debt assumed and working capital adjustments received. See Note 2.
Property, Plant and Equipment as of December 31,20172016
Electric Utilities (a)
$2,990,208
$2,875,594
Gas Utilities2,251,193
2,099,024
Power Generation (a)
155,793
162,728
Mining158,370
156,351
Corporate and Other11,954
21,599
Total property, plant and equipment$5,567,518
$5,315,296
_______________
(a)The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.



 Consolidating Income Statement
Year ended December 31, 2017Electric UtilitiesGas UtilitiesPower GenerationMiningCorporateIntercompany EliminationsDiscontinued OperationsTotal
  
Revenue$689,945
$947,595
$7,263
$35,463
$—
$—
$—
$1,680,266
Intercompany revenue14,705
35
84,283
31,158
344,685
(474,866)—
—
Total revenue704,650
947,630
91,546
66,621
344,685
(474,866)—
1,680,266
         
Fuel, purchased power and cost of natural gas sold268,405
409,603
—
—
151
(114,871)—
563,288
Operations and maintenance172,307
269,190
32,382
44,882
296,067
(302,832)—
511,996
Depreciation, depletion and amortization93,315
83,732
5,993
8,239
21,031
(24,064)—
188,246
Operating income (loss)170,623
185,105
53,171
13,500
27,436
(33,099)—
416,736
         
Interest expense(55,229)(80,829)(3,959)(228)(152,416)154,543
—
(138,118)
Interest income2,955
2,254
1,123
23
115,382
(120,721)—
1,016
Other income (expense), net1,730
(829)(54)2,191
330,373
(331,303)—
2,108
Income tax benefit (expense) (a)
(9,997)(39,799)10,333
(1,100)(32,433)(371)—
(73,367)
Income (loss) from continuing operations110,082
65,902
60,614
14,386
288,342
(330,951)—
208,375
Income (loss) from discontinued operations, net of tax (b)
—
—
—
—
—
—
(17,099)(17,099)
Net income (loss)110,082
65,902
60,614
14,386
288,342
(330,951)(17,099)191,276
Net income attributable to noncontrolling interest—
(107)(14,135)—
—
—
—
(14,242)
Net income (loss) available for common stock$110,082
$65,795
$46,479
$14,386
$288,342
$(330,951)$(17,099)$177,034
________________
(a)The effective tax rate is lower(d)    Liabilities incurred were driven by an increase in gas pipeline miles; which increases our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in 2017 resulting from revaluation of net deferred tax liabilities in accordance with ASC 740 and the enactment of the TCJA on December 22, 2017.
(b)Discontinued operations includes oil and gas property impairments (see Note 21).


 Consolidating Income Statement
Year ended December 31, 2016Electric UtilitiesGas UtilitiesPower GenerationMiningCorporateIntercompany EliminationsDiscontinued OperationsTotal
  
Revenue$664,330
$838,343
$7,176
$29,067
$—
$—
$—
$1,538,916
Intercompany revenue12,951
—
83,955
31,213
347,500
(475,619)—
—
Total revenue677,281
838,343
91,131
60,280
347,500
(475,619)—
1,538,916
         
Fuel, purchased power and cost of natural gas sold261,349
352,165
—
—
456
(114,838)—
499,132
Operations and maintenance158,134
245,826
32,636
39,576
378,744
(326,846)—
528,070
Depreciation, depletion and amortization84,645
78,335
4,104
9,346
22,930
(23,827)—
175,533
Operating income (loss)173,153
162,017
54,391
11,358
(54,630)(10,108)—
336,181
         
Interest expense(56,237)(76,586)(3,758)(401)(114,597)115,469
—
(136,110)
Interest income5,946
1,573
1,983
24
97,147
(105,244)—
1,429
Other income (expense), net3,193
184
2
2,209
179,838
(181,032)—
4,394
Income tax benefit (expense)(40,228)(27,462)(17,129)(3,137)28,398
457
—
(59,101)
Income (loss) from continuing operations85,827
59,726
35,489
10,053
136,156
(180,458)—
146,793
(Loss) from discontinued operations, net of tax (a)
—
—
—
—
—
—
(64,162)(64,162)
Net income (loss)85,827
59,726
35,489
10,053
136,156
(180,458)(64,162)82,631
Net income attributable to noncontrolling interest—
(102)(9,559)—
—
—
—
(9,661)
Net income (loss) available for common stock$85,827
$59,624
$25,930
$10,053
$136,156
$(180,458)$(64,162)$72,970
________________
(a)Discontinued operations includes oil and gas property impairments (see Note 21).



 Consolidating Income Statement
Year ended December 31, 2015Electric UtilitiesGas UtilitiesPower GenerationMiningCorporateIntercompany EliminationsDiscontinued OperationsTotal
  
Revenue$668,226
$551,300
$7,483
$34,313
$—
$—
$—
$1,261,322
Intercompany revenue11,617
—
83,307
30,753
227,708
(353,385)—
—
Total revenue679,843
551,300
90,790
65,066
227,708
(353,385)—
1,261,322
         
Fuel, purchased power and cost of natural gas sold269,409
299,645
—
—
122
(112,289)—
456,887
Operations and maintenance160,924
140,723
32,140
41,630
231,855
(229,790)—
377,482
Depreciation, depletion and amortization80,929
32,326
4,329
9,806
9,723
(10,580)—
126,533
Operating income (loss)168,581
78,606
54,321
13,630
(13,992)(726)—
300,420
         
Interest expense(55,159)(17,912)(4,218)(433)(61,496)54,568
—
(84,650)
Interest income4,114
601
1,015
34
48,799
(52,942)—
1,621
Other income (expense), net1,216
315
71
2,247
70,929
(71,964)—
2,814
Income tax benefit (expense)(41,173)(22,304)(18,539)(3,608)6,606
361
—
(78,657)
Income (loss) from continuing operations77,579
39,306
32,650
11,870
50,846
(70,703)—
141,548
Income (loss) from discontinued operations, net of tax (a)
—
—
—
—
—
—
(173,659)(173,659)
Net income (loss)77,579
39,306
32,650
11,870
50,846
(70,703)(173,659)(32,111)
Net income attributable to noncontrolling interest—
—
—
—
—
—
—
—
Net income (loss) available for common stock$77,579
$39,306
$32,650
$11,870
$50,846
$(70,703)$(173,659)$(32,111)
________________
(a)Discontinued operations includes oil and gas property impairments (see Note 21).

Corporate expense reallocation

In accordance with GAAP, indirect corporate operating costs previously allocatedfederal regulations.

We also have legally required AROs related to BHEP werecertain 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 reclassifiedpossible to discontinued operations. These corporate operating costsestimate a time period when these obligations could be settled, and therefore, a liability for 2017 were reallocated to our operating segments; allocated interest was reclassified to Corporate and Other. Indirect corporate operating costs for 2016 and 2015 were reclassified to Corporate and Other. The reallocationthe cost of these costs to our operating segments in 2017 and an estimate of how these costs could have been allocated to segments other than Corporate and Other in 2016 and 2015 is as followsobligations cannot be measured at this time.


(8)    FINANCING

Short-term debt

We had the following Notes payable outstanding at the Consolidated Balance Sheets date (in thousands):
December 31, 2021December 31, 2020
Balance Outstanding
Letters of Credit (a)
Balance Outstanding
Letters of Credit (a)
Revolving Credit Facility$— $27,209 $— $24,730 
CP Program420,180 — 234,040 — 
Total$420,180 $27,209 $234,040 $24,730 
____________________
(a)    Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility.

88
 Year Ended
Business SegmentDecember 31, 2017December 31, 2016December 31, 2015
Electric Utilities$1,323
$2,079
$3,344
Gas Utilities1,571
2,292
1,815
Power Generation177
320
543
Mining101
196
321
Total reportable segments3,172
4,887
6,023
Corporate and Other (a)
6,405
6,037
3,957
Total$9,577
$10,924
$9,980
Revolving Credit Facility and CP Program
________________________
(a)Includes interest allocations in 2017, 2016 and 2015 of approximately $4.9 million, $5.6 million and $3.4 million, respectively.




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 2 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, 2021. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at December 31, 2021.


(6)    LONG-TERM DEBTWe 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 net short-term borrowings (payments) during 2021 were $186 million. As of December 31, 2021, the weighted average interest rate on short-term borrowings was 0.30%.

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.

89
Long-term debt

Long-term debt outstanding was as follows (dollars in thousands):
Interest Rate atBalance Outstanding
Due DateDecember 31, 2021December 31, 2021December 31, 2020
Corporate
Senior unsecured notes due 2023November 30, 20234.25%$525,000 $525,000 
Senior unsecured notes due 2024August 23, 20241.04%600,000 — 
Senior unsecured notes due 2026January 15, 20263.95%300,000 300,000 
Senior unsecured notes due 2027January 15, 20273.15%400,000 400,000 
Senior unsecured notes, due 2029October 15, 20293.05%400,000 400,000 
Senior unsecured notes, due 2030June 15, 20302.50%400,000 400,000 
Senior unsecured notes due 2033May 1, 20334.35%400,000 400,000 
Senior unsecured notes, due 2046September 15, 20464.20%300,000 300,000 
Senior unsecured notes, due 2049October 15, 20493.88%300,000 300,000 
Corporate term loan due 2021June 7, 2021N/A— 1,436 
Total Corporate debt3,625,000 3,026,436 
Less unamortized debt discount(6,125)(7,013)
Total Corporate debt, net3,618,875 3,019,423 
South Dakota Electric
First Mortgage Bonds due 2032August 15, 20327.23%75,000 75,000 
First Mortgage Bonds due 2039November 1, 20396.13%180,000 180,000 
First Mortgage Bonds due 2044October 20, 20444.43%85,000 85,000 
Total South Dakota Electric debt340,000 340,000 
Less unamortized debt discount(74)(78)
Total South Dakota Electric debt, net339,926 339,922 
Wyoming Electric
Industrial development revenue bonds due 2021(a)
September 1, 2021N/A— 7,000 
Industrial development revenue bonds due 2027(a) (b)
March 1, 20270.15%10,000 10,000 
First Mortgage Bonds due 2037November 20, 20376.67%110,000 110,000 
First Mortgage Bonds due 2044October 20, 20444.53%75,000 75,000 
Total Wyoming Electric debt195,000 202,000 
Less unamortized debt discount— — 
Total Wyoming Electric debt, net195,000 202,000 
Total long-term debt4,153,801 3,561,345 
Less current maturities— 8,436 
Less unamortized deferred financing costs (c)
26,878 24,809 
Long-term debt, net of current maturities and deferred financing costs$4,126,923 $3,528,100 


Interest Rate atBalance Outstanding
 Due DateDecember 31, 2017December 31, 2017December 31, 2016
Corporate    
Senior unsecured notes due 2023November 30, 20234.25%$525,000
$525,000
Senior unsecured notes due 2020July 15, 20205.88%200,000
200,000
Remarketable junior subordinated notes (b)
November 1, 20283.50%299,000
299,000
Senior unsecured notes due 2019January 11, 20192.50%250,000
250,000
Senior unsecured notes due 2026January 15, 20263.95%300,000
300,000
Senior unsecured notes due 2027January 15, 20273.15%400,000
400,000
Senior unsecured notes, due 2046September 15, 20464.20%300,000
300,000
Corporate term loan due 2019 (a)
August 9, 20192.55%300,000
400,000
Corporate term loan due 2021June 7, 20212.32%18,664
24,406
Total Corporate debt  2,592,664
2,698,406
Less unamortized debt discount  (3,808)(4,413)
Total Corporate debt, net  2,588,856
2,693,993
     
Electric Utilities    
First Mortgage Bonds due 2044October 20, 20444.43%85,000
85,000
First Mortgage Bonds due 2044October 20, 20444.53%75,000
75,000
First Mortgage Bonds due 2032August 15, 20327.23%75,000
75,000
First Mortgage Bonds due 2039November 1, 20396.13%180,000
180,000
First Mortgage Bonds due 2037November 20, 20376.67%110,000
110,000
Industrial development revenue bonds due 2021 (c)
September 1, 20211.78%7,000
7,000
Industrial development revenue bonds due 2027 (c)
March 1, 20271.78%10,000
10,000
Series 94A Debt, variable rate (c)
June 1, 20241.83%2,855
2,855
Total Electric Utilities debt  544,855
544,855
Less unamortized debt discount  (90)(94)
Total Electric Utilities debt, net  544,765
544,761
     
Total long-term debt  3,133,621
3,238,754
Less current maturities  5,743
5,743
Less deferred financing costs (d)
  18,478
21,822
Long-term debt, net of current maturities and deferred financing costs  $3,109,400
$3,211,189
____________________
_______________
(a)Variable interest rate, based on LIBOR plus a spread.
(b)
See Note 12 for RSN details.
(c)(a)    Variable interest rate.
(d)Includes deferred financing costs associated with our Revolving Credit Facility of $1.7 million and $2.3 million as of December 31, 2017 and December 31, 2016, respectively.


(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 $2.5 million and $1.0 million as of December 31, 2021 and December 31, 2020, respectively.

Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands):
2022$— 
2023$525,000 
2024$600,000 
2025$— 
2026$300,000 
Thereafter$2,735,000 
90
2018$5,743
2019$555,742
2020$205,743
2021$8,436
2022$—
Thereafter$2,361,855


Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2017.2021. 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. The first mortgage bonds issued by South Dakota Electric

Amortization of Deferred Financing Costs

Our deferred financing costs and Wyoming Electric are callable, but are subject to make-whole provisions which would eliminate any economic benefit for us to callassociated amortization expense included in Interest expense on the bonds.accompanying Consolidated Statements of Income were as follows (in thousands):

Deferred Financing Costs Remaining atAmortization Expense for the years ended December 31,
December 31, 2021202120202019
$26,878 $3,769 $3,272 $3,242 
Assumption of Long-Term Debt

At the closing of the SourceGas Acquisition on February 12, 2016, we assumed $760 million in long-term debt, consisting of the following:

$325 million, 5.9% senior unsecured notes with an original issue date of April 16, 2007, due April 1, 2017.

$95 million, 3.98% senior secured notes with an original issue date of September 29, 2014, due September 29, 2019.

$340 million unsecured corporate term loan due June 30, 2017. Interest under this term loan was LIBOR plus a margin of 0.875%.

The $760 million in long-term debt assumed in the SourceGas Acquisition was repaid in August 2016.

Debt Transactions

On May 16, 2017, we paid down $50 million on our Corporate term loan due August 9, 2019. On July 17, 2017, we paid down an additional $50 million on the same term loan. Short-term borrowings from our CP program were used to fund the payments on the Corporate term loan.


On August 19, 2016,26, 2021, we completed a public debt offering of $700 million principal amount of senior unsecured notes. The debt offeringwhich consisted of $400$600 million, of 3.15% 10-year senior notes due January 15, 2027 and $300 million of 4.20% 30-year senior notes due September 15, 2046 (together the “Notes”). The proceeds of the Notes were used for the following:

Repay the $325 million 5.9%1.037% three-year senior unsecured notes assumeddue 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 SourceGas Acquisition;

Repay the $95 million, 3.98% senior secured notes assumed in the SourceGas Acquisition;

Repay $100 million on the $340 million unsecured term loan assumed in the SourceGas Acquisition;

Pay down $100offering, which were net of $3.7 million of the $500 million three-year unsecured term loan discussed below;

Payment of $29 million for the settlement of $400 million notional interest rate swap; and

Remainder was used for general corporate purposes.

On August 9, 2016, we entered into a $500 million, three-year, unsecured term loan expiring on August 9, 2019. The proceeds of this term loandeferred financing costs, were used to pay down $240 million of the $340 million unsecuredrepay amounts outstanding under our term loan assumed in the SourceGas


Acquisition and the $260 million term loan expiring on April 12, 2017. This new term loan has substantially similar terms and covenants as the amended and restated Revolving Credit Facility.

In accordance with regulatory orders related to the early termination and settlement of the gas supply contract described in Note 1, on June 7, 2016, we entered into a 2.32%, $29 million term loan, due June 7,on February 24, 2021. Proceeds from this term loan were used to finance the early termination of the gas supply contract, resulting in a regulatory asset. Principal and interest are payable quarterly at approximately $1.6 million.


On January 13, 2016,June 17, 2020, we completed a public debt offering which consisted of $550$400 million principal amount of 2.50% 10-year senior unsecured notes. The debt offering consisted of $300 million of 3.95%, ten-year senior notes due 2026, and $250 million of 2.50%, three-year senior notes due 2019. After discounts and underwriter fees, netJune 15, 2030. The proceeds from the offering totaled $546 million and were used as funding for the SourceGas Acquisition. The discounts are amortized over the life of each respective note.

Amortization Expense

Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income (Loss) were as follows (in thousands):
 Deferred Financing Costs Remaining atAmortization Expense for the years ended December 31,
 December 31, 2017201720162015
Revolving Credit Facility$1,703
 $638
$537
$504
Senior unsecured notes due 20232,427
 494
494
494
Senior unsecured notes due 201959
 704
643
—
Senior unsecured notes due 2020425
 167
167
167
Senior unsecured notes due 20262,031
 287
262
—
Senior unsecured notes due 20272,918
 363
121
—
Senior unsecured notes due 20463,082
 111
37
—
Corporate term loan due 201986
 201
144
—
Bridge Term Loan—
 —
843
4,213
RSNs due 20281,326
 122
122
10
First mortgage bonds due 2044 (South Dakota Electric)639
 24
24
24
First mortgage bonds due 2044 (Wyoming Electric)591
 22
23
22
First mortgage bonds due 2032485
 33
33
33
First mortgage bonds due 20391,657
 76
76
76
First mortgage bonds due 2037613
 31
31
31
Other436
 76
304
43
Total$18,478
 $3,349
$3,861
$5,617

Dividend Restrictions

Our credit facility and other debt obligations contain restrictions on the payment of cash dividends when a default or event of default occurs. In addition, the agreements governing our equity units contain restrictions on the payment of cash dividends upon any time we have exercised our right to defer payment of contract adjustment payments under the purchase contracts or interest payments under the RSNs included in such equity units. As of December 31, 2017, we were in compliance with these covenants.



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. The following restrictions on distributions from our subsidiaries existed at December 31, 2017:

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, 2017, the restricted net assets at our Electric and Gas Utilities were approximately $257 million.

(7)    NOTES PAYABLE

Our Revolving Credit Facility and debt securities contain certain restrictive financial covenants. As of December 31, 2017, we were in compliance with all of these financial covenants.

We had the followingrepay short-term debt outstanding at the Consolidated Balance Sheets date (in thousands):and for working capital and general corporate purposes.

 Balance Outstanding at
 December 31, 2017December 31, 2016
Revolving Credit Facility$—
$96,600
CP Program211,300
—
Total$211,300
$96,600

Revolving Credit Facility

On August 9, 2016, we amended and restated our corporate Revolving Credit Facility to increase total commitments to $750 million from $500 million and extend the term through August 9, 2021 with two one-year extension options (subject to consent from the lenders). This facility is similar to the former agreement, which includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents and subject to receipt of additional commitments from existing or new lenders, to increase total commitments of the facility up to $1.0 billion. 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 most favorable Corporate credit rating from either S&P or Moody’s for our unsecured debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.250%, 1.250%, and 1.250%, respectively, at December 31, 2017. A 0.200% commitment fee is charged on the unused amount of the Revolving Credit Facility.

On December 22, 2016, we implemented 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 net amount borrowed under the CP Program during 2017 and our notes outstanding as of December 31, 2017 were $211 million. We did not borrow under the CP Program in 2016 and did not have any notes outstanding as of December 31, 2016. As of December 31, 2017, the weighted average interest rate on CP Program borrowings was 1.76%.

As of December 31, 2017 and 2016, we had outstanding letters of credit totaling approximately $27 million and approximately $36 million, respectively.

Deferred financing costs on the Revolving Credit Facility of $5.4 million are being amortized over its estimated useful life and included in Interest expense on the accompanying Consolidated Statements of Income (Loss).

Debt Covenants


On December 7, 2016, we amendedRevolving Credit Facility

Under our Revolving Credit Facility, and term loan agreements, allowing the exclusion of the Remarketable Junior Subordinated Notes (RSNs) from our Consolidated Indebtedness to Capitalization Ratio covenant calculation. Under the amended and restated Revolving Credit Facility and term loan agreements, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Our Consolidated IndebtednessSubject 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, 2021 as shown below:
Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness, which includes letters
As of December 31, 2021Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio62.1%Less than65%

Wyoming Electric

Covenants within Wyoming Electric's financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of credit, certain guarantees issued and excludes RSNs by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interestsno more than 0.60 to 1.00. As of December 31, 2021, we were in subsidiaries and includes the aggregate outstanding amount of the RSNs.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 Term Loans require complianceholding 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, 2021, 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.

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Equity

At-the-Market Equity Offering Program

On August 3, 2020, we filed a shelf registration and DRSPP with the following financial covenantSEC. 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 endcurrent 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 each quarter:common stock are offered pursuant to our shelf registration statement filed with the SEC.

 At December 31, 2017 Covenant Requirement at December 31, 2017
Consolidated Indebtedness to Capitalization Ratio61% Less than65%
During the twelve months ended December 31, 2021, we issued a total of 1,812,197 shares of common stock under the ATM for $119 million, net of $1.1 million in issuance costs. We did not issue any shares of common stock under the ATM during the twelve months ended December 31, 2020. During the twelve months ended December 31, 2019, we issued a total of 1,328,332 shares of common stock under the ATM for $99 million, net of $1.2 million in issuance costs.


February 2020 Equity Issuance
(8)    ASSET RETIREMENT OBLIGATIONS

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 identified legal retirement obligations related to reclamationa DRSPP under which shareholders may purchase additional shares of coal mining sites incommon stock through dividend reinvestment and/or optional cash payments at 100% of the Mining segment and removalrecent average market price. We have the option of fuel tanks, asbestos, transformers containing polychlorinated biphenyls, an evaporation pond and wind turbines atissuing new shares or purchasing the regulated Electric Utilities segment, retirement of gas pipelines at our Gas Utilities and asbestos at our Electric and Gas Utilities. We periodically review and update estimated costs related to these asset retirement obligations. The actual cost may vary from estimates because of regulatory requirements, changes in technology and increased costs of labor, materials and equipment.

The following tables present the details of AROs which are includedshares on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands):
 December 31, 2016Liabilities IncurredLiabilities SettledAccretionLiabilities Acquired
Revisions to Prior Estimates (b)
December 31, 2017
Electric Utilities$4,661
$—
$(4)$268
$—
$1,362
$6,287
Gas Utilities29,775
—
—
1,142
—
2,321
33,238
Mining12,440
—
(107)651
—
(485)12,499
Total$46,876
$—
$(111)$2,061
$—
$3,198
$52,024

 December 31, 2015Liabilities IncurredLiabilities SettledAccretion
Liabilities Acquired (a)
Revisions to Prior Estimates (b)(c)
December 31, 2016
Electric Utilities$4,462
$—
$—
$191
$—
$8
$4,661
Gas Utilities136
—
—
791
22,412
6,436
29,775
Mining18,633
—
(105)822
—
(6,910)12,440
Total$23,231
$—
$(105)$1,804
$22,412
$(466)$46,876
_____________________
(a)Represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. Approximately $22 million was recorded with the purchase price allocation of SourceGas.
(b)The Gas Utilities Revision to Prior Estimates represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations.
(c)The 2016 Mining Revision to Prior Estimates reflects an approximately 33% reduction in equipment costs as promulgated by the State of Wyoming.

open market. 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 ifissued new shares until March 1, 2018, after which 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 forbegan purchasing shares on the cost of these obligations cannot be measured at this time.

We have identified legal retirement obligations related to plugging and abandonment of natural gas and oil wells. These obligations are classified as held for sale atopen market. At December 31, 2017. See Note 21.

2021, there were 116,306 shares of unissued stock available for future offering under the DRSPP.



Preferred Stock
(9)    
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, 2021 and 2020.


(9)    RISK MANAGEMENT ACTIVITIESAND DERIVATIVES


Market and Credit Risk Disclosures

Our activities in the regulated and non-regulated energy sectorsindustry 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 rate. supply. We are exposed, but not limited to, the following market risks, including, but not limited to:risks:


•Commodity price risk associated with our retail natural gas and wholesale electric power marketing activities and our fuel procurement for certainseveral of our gas-fired generation assets;assets, which include market fluctuations due to unpredictable factors such as the COVID-19 pandemic, weather (Winter Storm Uri), market speculation, inflation, pipeline constraints, and other factors that may impact natural gas and electric supply and demand; and


•Interest rate risk associated with our variable rate debt.future debt, including reduced access to liquidity during periods of extreme capital markets volatility, such as the 2008 financial crisis and the COVID-19 pandemic.


Credit Risk


Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.


For production and generation activities, we
92
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, prepayments,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, 20172021 was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies.

Derivatives and Hedging Activity

Our derivative and hedging activities included in the accompanying Consolidated Balance Sheets, Consolidated Statements of Income (Loss) and Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 10.

Utilities


The operations of our utilities,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 volatility in natural gas prices.price volatility. Therefore, as allowed or required by state utility commissions, we have entered into commission-approvedcommission 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’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 utilityregulatory commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Consolidated Statements of Income (Loss).Income.


We periodically have wholesale power purchase and sale contracts used to manage purchased power costs and load requirements associated with serving our electric customers that are considered derivative instruments due to not qualifying for the normal purchase and normal sales exception to derivative accounting. Changes in the fair value of these commodity derivatives are recognized in the Consolidated Statements of Income.

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/orand sales during time frames ranging from January 20182022 through May 2020.October 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 effective portion of the gain or loss on these designated derivatives is reported in AOCI in the accompanying Consolidated Balance Sheets and reclassified into earnings in the ineffective portion,


if anysame period that the underlying hedged item is reportedrecognized in Fuel, purchased power and cost of natural gas sold.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 Utilitiesutilities are comprised of both short and long positions. We had the following net long positions as of:
December 31, 2021December 31, 2020
Notional (MMBtus)
Maximum Term (months) (a)
Notional (MMBtus)
Maximum Term (months) (a)
Natural gas futures purchased590,000 3620,000 3
Natural gas options purchased, net3,100,000 33,160,000 3
Natural gas basis swaps purchased870,000 3900,000 3
Natural gas over-the-counter swaps, net (b)
4,570,000 343,850,000 17
Natural gas physical commitments, net (c)
16,416,677 2417,513,061 22
Electric wholesale contracts (c)
— 0219,000 12
 December 31, 2017December 31, 2016
 Notional (MMBtus)
Maximum Term (months) (a)
Notional (MMBtus)
Maximum Term (months) (a)
Natural gas futures purchased8,330,000
3614,770,000
48
Natural gas options purchased, net (b)
3,540,000
143,020,000
5
Natural gas basis swaps purchased8,060,000
3612,250,000
48
Natural gas over-the-counter swaps, net (c)
3,820,000
294,622,302
28
Natural gas physical commitments, net (d)
12,826,605
3521,504,378
10
____________________
__________(a)    Term reflects the maximum forward period hedged.
(a)Term reflects the maximum forward period hedged.
(b)
Volumes purchased as of December 31, 2016 is net of 2,133,000 MMBtus of collar options (call purchase and put sale) transactions.
(c)
(b)    As of December 31, 2017, 1,650,000 MMBtus of natural gas over-the-counter swaps purchased were designated as cash flow hedges.
(d)Volumes exclude contracts that qualify for normal purchase, normal sales exception.

Based on December 31, 2017 prices,2021, 1,830,000 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.

93
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 $0.7negotiated line of unsecured credit. At December 31, 2021, the Company posted $2.1 million related to such provisions, which is included in Other current assets on the Consolidated Balance Sheets.

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 Location20212020
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivativesDerivative assets - current$2,017 $181 
Noncurrent commodity derivativesOther assets, non-current18 43 
Liability derivative instruments:
Current commodity derivativesDerivative liabilities - current— (108)
Total derivatives designated as hedges$2,035 $116 
Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivativesDerivative assets - current$2,356 $1,667 
Noncurrent commodity derivativesOther assets, non-current804 151 
Liability derivative instruments:
Current commodity derivativesDerivative liabilities - current(1,439)(1,936)
Noncurrent commodity derivativesOther deferred credits and other liabilities(20)— 
Total derivatives not designated as hedges$1,701 $(118)

Derivatives Designated as Hedge Instruments

The impact of cash flow hedges on our Consolidated Statements of Income is presented below for the years ended December 31, 2021, 2020 and 2019. 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 wouldwe realized when the underlying physical and financial transactions were settled.
202120202019202120202019
Derivatives in Cash Flow Hedging RelationshipsAmount of Gain/(Loss) Recognized in OCIIncome Statement LocationAmount of Gain/(Loss) Reclassified from AOCI into Income
(in thousands)(in thousands)
Interest rate swaps$2,851 $2,851 $2,851 Interest expense$(2,851)$(2,851)$(2,851)
Commodity derivatives1,952 540 (965)Fuel, purchased power and cost of natural gas sold2,051 (601)417 
Total$4,803 $3,391 $1,886 $(800)$(3,452)$(2,434)

As of December 31, 2021, $0.9 million of net losses related to our interest rate swaps and commodity derivatives are expected to be realized, reported in pre-tax earnings and reclassified from AOCI duringinto earnings within the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

Financing Activities

At December 31, 2017, we had no outstanding interest rate swap agreements. In October 2015 and January 2016, we entered into forward starting interest rate swaps with a notional value totaling $400 million to fix the Treasury yield component associated with the anticipated issuance of senior notes. These swaps were settled at a loss of $29 million in connection with the issuance of our $400 million of unsecured ten-year senior notes in August 2016. The effective portion of the loss in the amount of $28 million was recognized as a component of AOCI and will be recognized as interest expense over the ten-year life of the $400 million unsecured note issued on August 19, 2016. The ineffective portion of $1.0 million, related to the timing of the debt issuance, was recognized in earnings as a component of interest expense in 2016. The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Consolidated Balance Sheets were as follows (dollars in thousands) as of:
94
 December 31, 2016
 
Interest Rate Swaps (a)
Notional$50,000
Weighted average fixed interest rate4.94%
Maximum terms in months1
Derivative assets, non-current$—
Derivative liabilities, current$90
Derivative liabilities, non-current$—
Derivatives Not Designated as Hedge Instruments
___________________
(a)The $50 million in swaps expired in January 2017. These swaps were designated to borrowings on our Revolving Credit Facility and were priced using three-month LIBOR, matching the floating portion of the related borrowings.

Discontinued Operations

Our Oil and Gas segment was exposed to risks associated with changes in the market prices through the sale and delivery of oil and gas to its customers at competitive prices. Through December 2017, we used exchange traded futures, swaps and options to hedge portions of our crude oil and natural gas production to mitigate commodity price risk and preserve cash flows. Hedge accounting was elected on the swaps and futures contracts. These transactions were designated upon inception as cash flow hedges, documented under accounting standards for derivatives and hedging and initially met prospective effectiveness testing. As a result of divesting our Oil and Gas segment assets, these activities were discontinued and there were no outstanding derivative agreements as of December 31, 2017. Any cash flows associated with our crude oil and natural gas cash flow hedges


were no longer probable of occurring; therefore, we discontinued hedge accounting as of November 1, 2017. As a result, we reclassified the loss in accumulated other comprehensive income associated with the commodity contracts into earnings as a reduction of revenues and recognized a pre-tax loss of $0.3 million, which is included in net loss from discontinued operations on the Consolidated Statements of Income (Loss) for the year ended December 31, 2017.

At December 31, 2016, we had outstanding crude oil futures and swap contracts with notional volumes of 108,000 Bbls, crude oil options contracts with notional volumes of 36,000 Bbls and natural gas futures and swap contracts with notional volumes of 2,700,000 MMBtus.

Cash Flow Hedges


The impactfollowing table summarizes the impacts of cash flow hedgesderivative instruments not designated as hedge instruments on our Consolidated Statements of Income (Loss) is presented below for the years ended December 31, 2017, 20162021, 2020 and 2015 (in thousands).2019. 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.
202120202019
Derivatives Not Designated as Hedging InstrumentsIncome Statement LocationAmount of Gain/(Loss) on Derivatives Recognized in Income
(in thousands)
Commodity derivatives - ElectricFuel, purchased power and cost of natural gas sold$(144)$144 $— 
Commodity derivatives - Natural GasFuel, purchased power and cost of natural gas sold2,599 1,640 (1,100)
$2,455 $1,784 $(1,100)
 December 31, 2017
Derivatives in Cash Flow Hedging RelationshipsLocation of Reclassifications from AOCI into IncomeAmount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)
     
Interest rate swapsInterest expense$(2,941)Interest expense$—
Commodity derivativesNet (loss) from discontinued operations913
Net (loss) from discontinued operations—
Commodity derivativesFuel, purchased power and cost of natural gas sold(243)Fuel, purchased power and cost of natural gas sold(75)
Total impact from cash flow hedges $(2,271) $(75)

 December 31, 2016
Derivatives in Cash Flow Hedging RelationshipsLocation of Reclassifications from AOCI into IncomeAmount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)
     
Interest rate swapsInterest expense$(3,899)Interest expense$(953)
Commodity derivativesNet (loss) from discontinued operations11,019
Net (loss) from discontinued operations—
Commodity derivativesFuel, purchased power and cost of natural gas sold(14)Fuel, purchased power and cost of natural gas sold—
Total $7,106
 $(953)



 December 31, 2015
Derivatives in Cash Flow Hedging RelationshipsLocation of Reclassifications from AOCI into IncomeAmount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)
     
Interest rate swapsInterest expense$(3,647)Interest expense$—
Commodity derivativesNet (loss) from discontinued operations14,460
Net (loss) from discontinued operations—
Total $10,813
 $—

The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the years ended December 31, 2017, 2016 and 2015. The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the Consolidated Statements of Net Income (Loss) as incurred.

 December 31, 2017December 31, 2016December 31, 2015
 (In thousands)
Increase (decrease) in fair value:   
Interest rate swaps$—
$(31,222)$2,888
Forward commodity contracts366
(573)9,782
Recognition of (gains) losses in earnings due to settlements:   
Interest rate swaps2,941
3,899
3,647
Forward commodity contracts(670)(11,005)(14,460)
Total other comprehensive income (loss) from hedging$2,637
$(38,901)$1,857

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 (Loss) for the years ended December 31, 2017, 2016 and 2015 (in thousands). 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.
  201720162015
Derivatives Not Designated as Hedging InstrumentsLocation of Gain/(Loss) on Derivatives Recognized in IncomeAmount of Gain/(Loss) on Derivatives Recognized in IncomeAmount of Gain/(Loss) on Derivatives Recognized in IncomeAmount of Gain/(Loss) on Derivatives Recognized in Income
     
Commodity derivativesNet (loss) from discontinued operations$—
$(50)$—
Commodity derivativesFuel, purchased power and cost of natural gas sold(2,207)940
—
  $(2,207)$890
$—


As discussed above, financial instruments used in our regulated utilitiesGas Utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory assets or Regulatory liability accounts related to the hedgesthese financial instruments in our Gas Utilities were $12$2.6 million and $8.8$2.2 million at December 31, 20172021 and 2016,2020, respectively. For our Electric Utilities, the unrealized gains and losses arising from these derivatives are recognized in the Consolidated Statements of Income.






(10)    (10)    FAIR VALUE MEASUREMENTS


Recurring Fair Value Measurements


There have been no significant transfers between Level 1 and Level 2 derivative balances during 2017 or 2016. Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties.Derivatives


A discussion of fair value of financial instruments is included in Note 11. Oil and gas derivative instruments are included in assets and liabilities held for sale discussed in Note 21. 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 (in thousands):instruments.
As of December 31, 2021
Level 1Level 2Level 3
Cash Collateral and Counterparty Netting (a)
Total
(in thousands)
Assets:
Commodity derivatives - Gas Utilities$— $7,569 $— $(2,374)$5,195 
Commodity derivatives - Electric Utilities— — — — — 
Total$— $7,569 $— $(2,374)$5,195 
Liabilities:
Commodity derivatives - Gas Utilities$— $3,273 $— $(1,814)$1,459 
Commodity derivatives - Electric Utilities0$— 0$— $— 
Total$— $3,273 $— $(1,814)$1,459 
_____________________
(a)    As of December 31, 2021, $2.4 million of our commodity derivative gross assets and $1.8 million of our commodity derivative gross liabilities, as well as related gross collateral amounts, were subject to master netting agreements.

95
As of December 31, 2017As of December 31, 2020
Level 1Level 2Level 3 Cash Collateral and Counterparty NettingTotalLevel 1Level 2Level 3
Cash Collateral and Counterparty Netting (a)
Total
Assets:   Assets:
Commodity derivatives - Utilities$—
$1,586
$—
 $(1,282)$304
Commodity derivatives - Gas UtilitiesCommodity derivatives - Gas Utilities$— 2,504 $— $(1,527)$977 
Commodity derivatives - Electric UtilitiesCommodity derivatives - Electric Utilities— 1,065 — — 1,065 
Total$—
$1,586
$—
 $(1,282)$304
Total$— $3,569 $— $(1,527)$2,042 
   
Liabilities:   Liabilities:
Commodity derivatives - Utilities$—
$13,756
$—
 $(11,497)$2,259
Commodity derivatives - Gas UtilitiesCommodity derivatives - Gas Utilities$— $2,675 $— $(1,552)$1,123 
Commodity derivatives - Electric UtilitiesCommodity derivatives - Electric Utilities— 921 — — 921 
Total$—
$13,756
$—
 $(11,497)$2,259
Total$— $3,596 $— $(1,552)$2,044 

____________________

(a)    As of December 31, 2020, $1.5 million of our commodity derivative assets and $1.6 million of our commodity derivative liabilities, as well as related gross collateral amounts, were subject to master netting agreements.

 As of December 31, 2016
 Level 1Level 2Level 3 Cash Collateral and Counterparty NettingTotal
Assets:      
Commodity derivatives - Utilities$—
$7,469
$—
 $(3,262)$4,207
Total—
7,469
—
 (3,262)4,207
       
Liabilities:      
Commodity derivatives - Utilities$—
$12,201
$—
 $(11,144)$1,057
Interest rate swaps—
90
—
 —
90
Total$—
$12,291
$—
 $(11,144)$1,147
Pension and Postretirement Plan Assets


A discussion of the fair value of our Pension and Postretirement Plan assets is included in Note 13.





Nonrecurring Fair Value Measures by Balance Sheet ClassificationMeasurement


As required by accounting standards for derivatives and hedges,A discussion of the fair values within the following tables are presented on a gross basis, aside from the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under termsvalue of our master netting agreementsinvestment in equity securities of a privately held oil and gas company, a Level 3 asset, is included in Note 1.

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 impactfair value hierarchy. Notes payable consist of legally enforceable master netting agreements that allow us to settle positivecommercial paper borrowings and negative positions.are not traded on an exchange; therefore, they are classified as Level 2 in the fair value hierarchy.


The following tables presenttable presents the carrying amounts and fair values of financial instruments not recorded at fair value and balance sheet classification of our derivative instruments as ofon the Consolidated Balance Sheets at December 31 (in thousands):

20212020
Carrying AmountFair ValueCarrying AmountFair Value
Long-term debt, including current maturities (a)
$4,126,923 $4,570,619 $3,536,536 $4,208,167 
____________________
(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.


96
  20172016
 Balance Sheet LocationFair Value of Asset DerivativesFair Value of Liability DerivativesFair Value of Asset DerivativesFair Value of Liability Derivatives
Derivatives designated as hedges:     
Commodity derivativesDerivative assets - current$—
$—
$1,007
$—
Commodity derivativesDerivative assets - non-current—
—
124
—
Commodity derivativesCurrent assets held for sale—
—
154
—
Commodity derivativesDerivative liabilities - current—
817
—
—
Commodity derivativesOther deferred credits and other liabilities—
67
—
7
Commodity derivativesCurrent liabilities held for sale—
—
—
1,090
Commodity derivativesNoncurrent liabilities held for sale—
—
—
231
Interest rate swapsDerivative liabilities - current—
—
—
90
Total derivatives designated as hedges$—
$884
$1,285
$1,418
      
Derivatives not designated as hedges:    
Commodity derivativesDerivative assets - current$304
$—
$2,977
$—
Commodity derivativesDerivative assets - non-current—
—
98
—
Commodity derivativesDerivative liabilities - current—
1,264
—
1,014
Commodity derivativesOther deferred credits and other liabilities—
111
—
36
Commodity derivativesCurrent liabilities held for sale—
—
—
265
Total derivatives not designated as hedges$304
$1,375
$3,075
$1,315

(11)    OTHER COMPREHENSIVE INCOME



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

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):
It is our policy to offset in our
Location on the Consolidated Statements of IncomeAmount Reclassified from AOCI
December 31, 2021December 31, 2020
Gains and (losses) on cash flow hedges:
Interest rate swapsInterest expense$(2,851)$(2,851)
Commodity contractsFuel, purchased power and cost of natural gas sold2,051 (601)
(800)(3,452)
Income taxIncome tax benefit (expense)175 383 
Total reclassification adjustments related to cash flow hedges, net of tax$(625)$(3,069)
Amortization of components of defined benefit plans:
Prior service costOperations and maintenance$98 $103 
Actuarial gain (loss)Operations and maintenance(2,391)(2,387)
(2,293)(2,284)
Income taxIncome tax benefit (expense)638 935 
Total reclassification adjustments related to defined benefit plans, net of tax$(1,655)$(1,349)
Total reclassifications$(2,280)$(4,418)


Balances by classification included within AOCI, net of tax on the accompanying Consolidated Balance Sheets contracts which provide for legally enforceable netting of our accounts receivable and payable and derivative activities.

As required by accounting standards for derivatives and hedges, fair values within the following tables reconcile the gross amounts to the net amounts. Amounts included in Gross Amounts Offset on Consolidated Balance Sheets in the following tables include the netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions as well as cash collateral posted with the same counterparties. Additionally, the amounts reflect cash collateral on deposit in margin accounts at December 31, 2017 and December 31, 2016, to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the gross amounts are not indicative of either our actual credit exposure or net economic exposure.

Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets at December 31, 2017 was as follows (in thousands):
Derivative AssetsGross Amounts of Derivative AssetsGross Amounts Offset on Consolidated Balance SheetsNet Amount of Total Derivative Assets on Consolidated Balance Sheets
Subject to master netting agreement or similar arrangement:   
Commodity derivative:   
Utilities$1,282
$(1,282)$—
Total derivative assets subject to a master netting agreement or similar arrangement1,282
(1,282)—
    
Not subject to a master netting agreement or similar arrangement:   
Commodity derivative:   
    
Utilities304
—
304
Total derivative assets not subject to a master netting agreement or similar arrangement304
—
304
    
Total derivative assets$1,586
$(1,282)$304

Derivative LiabilitiesGross Amounts of Derivative LiabilitiesGross Amounts Offset on Consolidated Balance SheetsNet Amount of Total Derivative Liabilities on Consolidated Balance Sheets
Subject to a master netting agreement or similar arrangement:   
Commodity derivative:   
Utilities$11,497
$(11,497)$—
Total derivative liabilities subject to a master netting agreement or similar arrangement11,497
(11,497)—
    
Not subject to a master netting agreement or similar arrangement:   
Commodity derivative:   
Utilities2,259
—
2,259
Total derivative liabilities not subject to a master netting agreement or similar arrangement2,259
—
2,259
    
Total derivative liabilities$13,756
$(11,497)$2,259



Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of December 31, 2016 were as follows (in thousands):
Derivatives Designated as Cash Flow Hedges
Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
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 AOCI2,174 (1,549)1,655 2,280 
As of December 31, 2021$(10,384)$1,476 $(11,176)$(20,084)
Derivatives Designated as Cash Flow Hedges
Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
As of December 31, 2019$(15,122)$(456)$(15,077)$(30,655)
Other comprehensive income (loss)
before reclassifications— (47)(1,062)(1,109)
Amounts reclassified from AOCI2,564 505 1,349 4,418 
As of December 31, 2020$(12,558)$2 $(14,790)$(27,346)
97
Derivative AssetsGross Amounts of Derivative AssetsGross Amounts Offset on Consolidated Balance SheetsNet Amount of Total Derivative Assets on Consolidated Balance Sheets
Subject to master netting agreement or similar arrangement:   
Commodity derivative:   
Utilities$4,269
$(3,262)$1,007
Total derivative assets subject to a master netting agreement or similar arrangement4,269
(3,262)1,007
    
Not subject to a master netting agreement or similar arrangement:   
Commodity derivative:   
Utilities3,200
—
3,200
Total derivative assets not subject to a master netting agreement or similar arrangement3,200
—
3,200
    
Total derivative assets$7,469
$(3,262)$4,207

Derivative LiabilitiesGross Amounts of Derivative LiabilitiesGross Amounts Offset on Consolidated Balance SheetsNet Amount of Total Derivative Liabilities on Consolidated Balance Sheets
Subject to a master netting agreement or similar arrangement:   
Commodity derivative:   
Utilities$11,144
$(11,144)$—
Total derivative liabilities subject to a master netting agreement or similar arrangement11,144
(11,144)—
    
Not subject to a master netting agreement or similar arrangement:   
Commodity derivative:   
Utilities1,057
—
1,057
Interest Rate Swaps90
—
90
Total derivative liabilities not subject to a master netting agreement or similar arrangement1,147
—
1,147
    
Total derivative liabilities$12,291
$(11,144)$1,147
(12)    VARIABLE INTEREST ENTITY


(11)    FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 10, were as follows at December 31 (in thousands):
 20172016
 Carrying AmountFair ValueCarrying AmountFair Value
Cash and cash equivalents (a)
$15,420
$15,420
$13,518
$13,518
Restricted cash and equivalents (a)
$2,820
$2,820
$2,274
$2,274
Notes payable (b)
$211,300
$211,300
$96,600
$96,600
Long-term debt, including current maturities (c) (d)
$3,115,143
$3,350,544
$3,216,932
$3,351,305
_______________
(a)
Carrying value approximates fair value. Cash and restricted cash are classified in Level 1 in the fair value hierarchy.
(b)Notes payable consist of commercial paper borrowings in 2017 and borrowings on our Revolving Credit Facility in 2016. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy.
(c)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.
(d)Carrying amount of long-term debt is net of deferred financing costs.

Cash and Cash Equivalents

Included in cash and cash equivalents is cash, money market mutual funds, and term deposits. As part of our cash management process, excess operating cash is invested in money market mutual funds with our bank. Money market mutual funds are not deposits and are not insured by the U.S. Government, the FDIC, or any other government agency and involve investment risk including possible loss of principal. We believe however, that the market risk arising from holding these financial instruments is minimal.

Restricted Cash and Equivalents

Restricted cash and cash equivalents represent restricted cash and uninsured term deposits.

Notes Payable and Long-Term Debt

For additional information on our notes payable and long-term debt, see Note 6 and Note 7.



(12)    EQUITY

Equity Units

On November 23, 2015, we issued 5.98 million equity units for total gross proceeds of $299 million. Each Equity Unit has a stated amount of $50 and consists of (i) a forward purchase contract to purchase the Company’s common stock and (ii) a 1/20, or 5%, undivided beneficial ownership interest in $1,000 principal amount of RSNs due 2028. The RSNs, a debt instrument, and the forward purchase contracts, an equity instrument, are deemed to be separate instruments as the investor may trade the RSNs separately from the forward purchase contract and may also settle the forward purchase contract separately.

The forward purchase contracts obligate the holders to purchase from the Company on the settlement date, which shall be no later than November 1, 2018, for a price of $50 in cash, the following number of shares of our common stock, subject to anti-dilution adjustments:

if the “Applicable Market Value” (AMV) of the Company’s common stock, which is the average volume-weighted average price of the Company’s common stock for the trading days during the 20 consecutive scheduled trading day period ending on the third scheduled trading day immediately preceding the forward purchase contract settlement date, equals or exceeds $47.2938, 1.0572 shares of the Company’s common stock per Equity Unit;

if the AMV is less than $47.2938 but greater than $40.25, a number of shares of the Company’s common stock having a value, based on the AMV, equal to $50; and

if the AMV is less than or equal to $40.25, 1.2422 shares of the Company’s common stock.

The RSNs bear interest at a rate of 3.5% per year, payable quarterly, and mature on November 1, 2028. The RSNs will be remarketed in 2018. If this remarketing is successful, the interest rate on the RSNs will be reset, and thereafter interest will be payable semi-annually at the reset rate. If there is no successful remarketing, the interest rate on the RSNs will not be reset, and the holders of the RSNs will have the right to put the RSNs to the Company at a price equal to 100% of the principal amount, and the proceeds of the put right will be deemed to have been applied against the holders’ obligation under the forward purchase contracts.

The Company also pays the Equity Unit holders quarterly contract adjustment payments at a rate of 4.25% per year of the stated amount of $50 per Equity Unit, or $2.125 per year up to November 1, 2018. The present value of the future contract adjustment payments, $33 million, was recorded as a reduction of shareholders’ equity in the accompanying Consolidated Balance Sheets. Until settlement of the forward purchase contracts, the shares of stock underlying each forward purchase contract are not outstanding. The forward purchase contracts will only be included in the computation of diluted earnings per share to the extent they are dilutive. As of December 31, 2017, the forward purchase contracts were dilutive and therefore included in the computation of diluted earnings per share. Basic earnings per share will not be affected until the forward purchase contracts are settled and the holders thereof become stockholders.

Selected information about our equity units is presented below (in thousands except for percentages):
Issuance DateUnits IssuedTotal Net ProceedsTotal Long-term Debt (RSNs)RSN Interest Rate (annual)Stock Purchase Contract Rate (annual)Stock Purchase Contract Liability as of December 31, 2017
11/23/20155,980
$290,030
$299,000
3.50%4.25%$12,115

At-the-Market Equity Offering Program

On August 4, 2017, we renewed the ATM equity offering program, which reset the size of the program to an aggregate value of up to $300 million. The renewed program, which allows us to sell shares of our common stock, is the same as the prior year program other than the aggregate value increased from $200 million to $300 million. The shares may be offered from time to time pursuant to a sales agreement dated August 4, 2017. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. We did not issue any common shares under the ATM equity offering program during the twelve months ended December 31, 2017. During the three months ended December 31, 2016, we issued 218,647 common shares for $13 million, net of $0.1 million in commissions under the ATM equity offering program. During the twelve months ended December 31, 2016, we issued an aggregate of 1,968,738 shares of common stock under the ATM equity offering program for $119 million, net of $1.2 million in commissions.



Common Stock Offering

On November 23, 2015, we issued 6.325 million shares of common stock pursuant to a public offering at $40.25 per share. Net proceeds were $246 million. The proceeds from the offering were used to partially fund the purchase of SourceGas, which closed on February 12, 2016.

Equity Compensation Plans

Our 2015 Omnibus Incentive Plan allows for the granting of stock, restricted stock, restricted stock units, stock options and performance shares. We had 979,464 shares available to grant at December 31, 2017.

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, 2017, total unrecognized compensation expense related to non-vested stock awards was approximately $12.0 million and is expected to be recognized over a weighted-average period of 1.9 years. Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income (Loss) was as follows for the years ended December 31 (in thousands):
 201720162015
Stock-based compensation expense$7,626
$10,885
$4,076

Stock Options

The Company has not issued any stock options since 2014 and has 96,749 stock options outstanding at December 31, 2017. The amount of stock options granted during the last three years, and related exercise activity are not material to the Company’s consolidated financial statements.

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 3 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, 2017, was as follows:
 Restricted StockWeighted-Average Grant Date Fair Value
 (in thousands) 
Balance at beginning of period295
$52.15
Granted111
60.63
Vested(128)51.44
Forfeited(11)53.80
Balance at end of period267
$55.94

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, was as follows:
 Weighted-Average Grant Date Fair ValueTotal Fair Value of Shares Vested
  (in thousands)
2017$60.63
$7,909
2016$53.55
$4,602
2015$50.01
$6,009



As of December 31, 2017, there was $9.9 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 2.0 years.

Performance Share Plan

Certain officers of the Company and its subsidiaries are participants in a performance share award plan, a market-based 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.

The 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 $2.5 million at December 31, 2017 would be reclassified as a liability.

Outstanding performance periods at December 31 were as follows (shares in thousands):
   Possible Payout Range of Target
Grant DatePerformance PeriodTarget Grant of SharesMinimumMaximum
January 1, 2015January 1, 2015 - December 31, 2017430%200%
January 1, 2016January 1, 2016 - December 31, 2018530%200%
January 1, 2017January 1, 2017 - December 31, 2019510%200%

A summary of the status of the Performance Share Plan at December 31 was as follows:
 Equity PortionLiability Portion
  
Weighted-Average Grant Date Fair Value (a)
 Weighted-Average Fair Value at
 SharesSharesDecember 31, 2017
 (in thousands) (in thousands) 
Performance Shares balance at beginning of period71
$52.29
71
 
Granted26
63.52
26
 
Forfeited(1)55.01
(1) 
Vested(22)55.18
(22) 
Performance Shares balance at end of period74
$55.31
74
$22.31
_____________________
(a)The grant date fair values for the performance shares granted in 2017, 2016 and 2015 were determined by Monte Carlo simulation using a blended volatility of 23%, 24% and 21%, respectively, 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, 2017$63.52
December 31, 2016$47.76
December 31, 2015$54.92



Performance plan payouts have been as follows (dollars and shares in thousands):
Performance PeriodYear of PaymentShares IssuedCash PaidTotal Intrinsic Value
January 1, 2014 to December 31, 20162017—
$—
$—
January 1, 2013 to December 31, 20152016—
$—
$—
January 1, 2012 to December 31, 2014201569
$3,657
$7,314

On January 30, 2018, the Compensation Committee of our Board of Directors determined that the Company’s performance criteria for the January 1, 2015 through December 31, 2017 performance period was not met. As a result, there will be no payout for this period.

As of December 31, 2017, there was $2.1 million of unrecognized compensation expense related to outstanding performance share plans that is expected to be recognized over a weighted-average period of 1.6 years.

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 during 2017 and 2016.

A summary of the DRSPP for the years ended December 31 is as follows (shares in thousands):
 20172016
Shares Issued48
51
   
Weighted Average Price$65.40
$58.24
   
Unissued Shares Available308
356

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.

Sale of Noncontrolling Interest in Subsidiary


Black Hills Colorado IPP owns and operates a 200 MW, combined-cycle natural gas generating facility located in Pueblo, Colorado. On April 14,In 2016, Black Hills Electric Generation sold a 49.9%, noncontrollingnon-controlling interest in Black Hills Colorado IPP for $216 million to a third-party buyer. FERC approval of the sale was received on March 29, 2016. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric. Proceeds from the sale were used to pay down short-term debt and for other general corporate purposes.


ASC 810 requires theThe accounting for a partial sale of a subsidiary in which control is maintained and the subsidiary continues to be consolidated.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 noncontrollingnon-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, 2021, 2020 and 2019 was reduced by $15 million, $15 million, and $14 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 noncontrolling intereststhis 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.

Net income available for common stock for the years ended December 31, 2017 and December 31, 2016 was reduced by $14 million and $9.6 million, respectively, attributable to this noncontrolling interest. The net income allocable to the noncontrolling interest holders is based on ownership interests with the exception of certain agreed upon adjustments.




Black Hills Colorado IPP has been determined to be a variable interest entity (VIE)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:
 2017 2016
 (in thousands)
Assets   
Current assets$14,837
 $12,627
Property, plant and equipment of variable interest entities, net$208,595
 $218,798
    
Liabilities   
Current liabilities$4,565
 $4,342

(13)    REGULATORY MATTERS

Electric Utilities Rate Activity

South Dakota Electric Common Use System (CUS): 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, 2018 the annual revenue requirement increased by $3.3 million and included estimated weighted average capital additions of $45 million for 2017 and 2018. The annual transmission revenue requirement has a true up mechanism that is posted in June of each year.

South Dakota Electric Settlement: On June 16, 2017, South Dakota Electric received approval from the SDPUC on a settlement reached with the SDPUC staff agreeing to a 6-year moratorium period effective July 1, 2017. As part of this agreement, South Dakota Electric will not increase base rates, absent an extraordinary event. The moratorium period also includes suspension of both the Transmission Facility Adjustment and the Environmental Improvement Adjustment, and a $1.0 million increase to the annual power marketing margin guarantee during this period. Additionally, existing regulatory asset balances of approximately $13 million related to decommissioning and Winter Storm Atlas are being amortized over the moratorium period. These balances were previously being amortized over a 10-year period ending September 30, 2024. The vegetation management regulatory asset of $14 million, previously unamortized, is also being amortized over the moratorium period. The change in amortization periods for these costs increased annual amortization expense by approximately $2.7 million. The June 16, 2017 settlement had no impact to base rates.

Colorado Electric Rate Case filing: On December 19, 2016, Colorado Electric received approval from the CPUC to increase its annual revenues by $1.2 million to recover investments in a $63 million, 40 MW natural gas-fired combustion turbine and normal increases in operating expenses. This increase is in addition to approximately $5.9 million in annualized revenue being recovered under the Clean Air Clean Jobs Act construction financing rider. This turbine was completed in the fourth quarter of 2016, achieving commercial operation on December 29, 2016. The approval allowed a return on rate base of 6.02% for this turbine, with a 9.37% return on equity and a capital structure of 67.34% debt and 32.66% equity. Whereas, an authorized return on rate base of 7.4% was received for the remaining system investments, with a return on equity of 9.37% and an approved capital structure of 47.6% debt and 52.4% equity.

On January 9, 2017, we filed an application with the CPUC for rehearing, reargument or reconsideration of the Commission’s December 19, 2016 decision which reduced our proposed $8.9 million annual revenue increase to $1.2 million. Concurrent with this application, we filed a motion for a Commissioner to recuse themselves from continuing to participate in any further proceedings in the rate review. On October 4, 2017, the Company filed an Opening Brief. The Company filed a Reply Brief on November 22, 2017.  The matter is pending.

We believe the CPUC made errors in their December decision by demonstrating bias, making decisions not supported by evidence, making findings inconsistent with cost-recovery provisions of the Colorado Clean Air-Clean Jobs Act and the


Commission’s own prior decisions, and treating Colorado Electric differently than other regulated utilities in Colorado have been treated in similar situations.

Gas Utilities Rate Activity

On December 15, 2017, Arkansas Gas filed a rate review application with the APSC requesting an annual increase in revenue of approximately $30 million. The annual increase is based on a return on equity of 10.2% and a capital structure of 45.3% debt and 54.7% equity. This rate review was driven by approximately $160 million of investments made since 2016 to replace, upgrade and maintain Arkansas Gas’ approximately 5,500 miles of natural gas transmission and distribution pipelines. If approved, new rates would be implemented in the fourth quarter of 2018. We are reviewing the impact of tax reform as it applies to the filing.

On November 17, 2017, Wyoming Gas filed a rate review application with the WPSC requesting an annual increase in revenue of approximately $1.4 million for natural gas system improvements supporting its Northwest Wyoming customers. The annual increase is based on a return on equity of 10.2% and a capital structure of 46.0% debt and 54.0% equity. This rate review was driven by approximately $6 million of investments made since 2015 to replace, upgrade and maintain approximately 620 miles of natural gas transmission and distribution pipelines. If approved, new rates would be implemented in mid-2018. We are reviewing the impact of tax reform as it applies to the filing.

On November 1, 2017, RMNG filed a rate review with the CPUC requesting recovery of $3.1 million, which includes $0.2 million of new revenue related to system safety and integrity expenditures on projects for the period of 2014 through 2018. This SSIR request was approved by the CPUC in December 2017, and is effective January 1, 2018.

On October 3, 2017, RMNG filed a rate review application with the CPUC requesting an annual increase in revenue of $2.2 million and an extension of the SSIR to recover costs from 2018 through 2022. The annual increase is based on a return on equity of 12.25% and a capital structure of 53.37% debt and 46.63% equity. This rate review was driven by the impending expiration of the SSIR on May 31 2018; this application requests a continuation of the SSIR through 2022. We are reviewing the impact of tax reform as it applies to the filing.

Monthly, Arkansas Gas files for recovery of projects related to the replacement of eligible mains (MRP) and projects for the relocation of certain at risk meters (ARMRP). On February 1, 2018, Arkansas Gas requested MRP revenue of $2.8 million and ARMPR revenue of $0.5 million for assets placed in service between April 1, 2016 and December 31, 2017. Pursuant to the Arkansas Gas Tariff, the filed rates are effective the date filed.

Annually, Arkansas Gas files for recovery of Stockton Storage revenue requirement through the Stockton Storage Acquisition Rates regulatory mechanism. On November 16, 2017 Arkansas Gas filed a request for recovery of $3.3 million for the revenue requirement year ended September 30, 2017. Rates were effective January 1, 2017.

On October 2, 2017, Nebraska Gas Distribution filed with the NPSC requesting recovery of $6.8 million, which includes $0.3 million of increased annual revenue related to system safety and integrity expenditures on projects for the period of 2012 through 2017. This SSIR tariff was approved by the NPSC in January 2018, and went into effect on February 1, 2018.

In February 2016, Arkansas Gas implemented new base rates resulting in a revenue increase of $8.0 million. The APSC modified a stipulation reached between the APSC Staff and all intervenors except the Attorney General and Arkansas Gas in its order issued on January 28, 2016. The modified stipulation revised the capital structure to 52% debt and 48% equity and also limited recovery of portions of cost related to incentive compensation.



(14)    OPERATING LEASES

We have entered into lease agreements for vehicles, equipment and office facilities. Rental expense incurred under these operating leases, including month to month leases, for the years ended December 31 was as follows (in thousands):
20212020
Assets:
Current assets$13,220 $13,604 
Property, plant and equipment of variable interest entities, net$189,079 $190,637 
Liabilities:
Current liabilities$5,841 $5,318 


 201720162015
Rent expense$10,325
$9,568
$7,177

The following is a schedule of future minimum payments required under the operating lease agreements (in thousands):
2018$5,030
2019$3,840
2020$1,957
2021$918
2022$808
Thereafter$3,085

(15)    INCOME TAXES

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%. 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 book and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. As such, the Company has 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 rate regulators, which could have a material impact on the Company’s future results of operations, cash flows or financial position. As a result of the revaluation, deferred tax assets and liabilities were reduced by approximately $309 million. Of the $309 million, approximately $301 million is related to our regulated utilities and is reclassified to a regulatory liability. This regulatory liability will generally be amortized over the remaining life of the related assets using the normalization principles as specifically prescribed in the TCJA.

In addition, as allowed under SEC Staff Accounting Bulletin No. 118 (SAB 118), the Company has recorded provisional income tax amounts as of December 31, 2017 for changes pursuant to the TCJA related to depreciation, for which the impacts could not be finalized upon issuance of the Company’s financial statements but reasonable estimates could be determined.  The provisional amounts may change as the Company finalizes the analysis and computations, and such changes could be material to the Company’s future results of operations, cash flows or financial position.

Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands):
 201720162015
Current:   
Federal$(6,193)$(21,806)$2,624
State(1,432)(1,797)1,329
 (7,625)(23,603)3,953
Deferred:   
Federal76,567
78,997
71,332
State4,470
3,759
3,485
Tax credit amortization(45)(52)(113)
 80,992
82,704
74,704
    
 $73,367
$59,101
$78,657



Included in discontinued operations is a tax benefit of $8.4 million, $49 million and $101 million for 2017, 2016 and 2015, respectively.

The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands):
 20172016
Deferred tax assets:  
Regulatory liabilities$90,742
$58,200
Employee benefits18,724
28,873
Federal net operating loss155,276
252,780
Other deferred tax assets(a)
74,561
83,675
Less: Valuation allowance(9,121)(9,263)
Total deferred tax assets330,182
414,265
   
Deferred tax liabilities:  
Accelerated depreciation, amortization and other property-related differences(b)
(510,774)(782,674)
Regulatory assets(26,245)(49,471)
Goodwill(46,392)(60,544)
State deferred tax liability(58,930)(50,258)
Deferred costs(16,063)(18,551)
Other deferred tax liabilities(8,298)(14,702)
Total deferred tax liabilities(666,702)(976,200)
   
Net deferred tax liability$(336,520)$(561,935)
_______________
(a)Other deferred tax assets consist primarily of alternative minimum tax credit and federal research and development credits. No single item exceeds 5% of the total net deferred tax liability.
(b)The net deferred tax liabilities were revalued for the change in federal tax rate to 21% under the TCJA. The revaluation resulted in a reduction to net deferred tax liabilities of approximately $309 million. Due to the regulatory construct, approximately $301 million of the revaluation was reclassified to a regulatory liability.




The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:
 201720162015
Federal statutory rate35.0 %35.0 %35.0 %
State income tax (net of federal tax effect)0.9
1.2
1.5
Percentage depletion(0.6)(0.8)(0.7)
Non-controlling interest (a)
(1.8)(1.6)—
Equity AFUDC(0.2)(0.5)(0.1)
Tax credits(1.7)(0.4)(0.1)
Transaction costs—
0.5
—
Accounting for uncertain tax positions adjustment(0.2)(2.7)0.8
Flow-through adjustments (b)
(1.1)(2.1)(1.0)
Other tax differences(0.9)0.1
0.3
IRC 172(f) carryback claim(0.7)—
—
Tax Cuts & Jobs Act corporate rate reduction (c)
(2.7)—
—
 26.0 %28.7 %35.7 %
_________________________
(a)The effective tax rate reflects the income attributable to the noncontrolling interest in Black Hills Colorado IPP for which a tax provision was not recorded.
(b)Flow-through adjustments related primarily to accounting method changes for tax purposes that allow us to take a current tax deduction for repair costs and certain indirect costs. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and flowed the tax benefit through to tax expense. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record tax benefits consistent with the flow-through method.
(c)On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21% effective January 1, 2018. The 2017 effective tax rate reduction reflects the revaluation of deferred income taxes associated with non-regulated operations required by the change.

At December 31, 2017, we have federal and state NOL carryforwards that will expire at various dates as follows (in thousands):
  Amounts Expiration Dates
Federal Net Operating Loss Carryforward $739,184
 2019to2037
       
State Net Operating Loss Carryforward $688,335
 2017to2038

As of December 31, 2017, we had a $1.3 million valuation allowance against the state NOL carryforwards. Our 2017 analysis of the ability to utilize such NOLs resulted in a slight increase in the valuation allowance of approximately $0.4 million, which resulted in an increase to tax expense. The valuation allowance adjustment was primarily attributable to a projected decrease in state taxable income for years beyond 2017. This projected decrease impacted the utilization of NOL carryforward in those states where the carryforward period is significantly shorter than the federal carryforward period of 20 years. In certain states, the carryforward period is limited to 5 years. Ultimate usage of these NOLs depends upon our future tax filings. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the NOLs, the offsetting amount will affect tax expense.



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
Beginning balance at January 1, 2015$32,192
Additions for prior year tax positions3,285
Reductions for prior year tax positions(3,491)
Additions for current year tax positions—
Settlements—
Ending balance at December 31, 201531,986
Additions for prior year tax positions2,423
Reductions for prior year tax positions(19,174)
Additions for current year tax positions—
Settlements(11,643)
Ending balance at December 31, 20163,592
Additions for prior year tax positions358
Reductions for prior year tax positions(5,713)
Additions for current year tax positions5,026
Settlements—
Ending balance at December 31, 2017$3,263

The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $0.2 million.

We recognized no interest expense for the years ended December 31, 2017 and December 31, 2016, and approximately $1.6 million for the year ended December 31, 2015. We had no accrued interest (before tax effect) associated with income taxes at December 31, 2017 and December 31, 2016.

Black Hills Corporation and its subsidiaries are currently under examination by the IRS for the 2010 to 2012 tax years. A 30-day Letter was received in second quarter 2016 along with a Revenue Agent’s Report from the IRS in regard to the audit of the 2010 to 2012 tax years disallowing certain R&D credits and deductions claimed with respect to certain costs and projects. In response to the 30-day Letter, a protest was timely filed with IRS Appeals in the second quarter of 2016 and a final settlement at IRS Appeals is expected to be reached in 2018. Black Hills Gas, Inc. and subsidiaries, which files a separate consolidated tax return from Black Hills Corporation and subsidiaries, is under examination by the IRS for 2014.

We had deferred a substantial amount of tax payments through various tax planning strategies including the deferral of approximately $125 million in income taxes attributable to the like-kind exchange effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. The IRS had challenged our position with respect to the like-kind exchange. In the first quarter of 2016, we reached a settlement agreement in principle with IRS Appeals related to both the like-kind exchange transaction in addition to the R&D credits and deductions issues. In 2016, the settlement resulted in a reduction to the liability for unrecognized tax benefits of approximately $29 million excluding interest. Approximately $17 million of the reduction was to restore accumulated deferred income taxes and the remaining portion of approximately $12 million was reclassified to current taxes payable.

As of December 31, 2017, 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, 2018.

State tax credits have been generated and are available to offset future state income taxes. At December 31, 2017, we had the following state tax credit carryforwards (in thousands):
State Tax Credit CarryforwardsExpiration Year
Investment tax credit$20,285
2023to2036
Research and development$179
No expiration



As of December 31, 2017, we had a $7.8 million valuation allowance against the state tax credit carryforwards. The re-evaluation of our ability to utilize such credits resulted in an increase of the valuation allowance of approximately $1.2 million of which approximately $0.6 million resulted in an increase to tax expense. The remaining $0.6 million increase is attributable to our regulated business and is being accounted for under the deferral method whereby the credits are amortized to tax expense over the estimated useful life of the underlying asset that generated the credit. The valuation allowance adjustment was primarily attributable to the impact of lower projected apportionment factors resulting in decreased state taxable income in years beyond 2017. Ultimate usage of these credits depends upon our future tax filings. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the state tax credit carryforwards, the offsetting amount will affect tax expense.

(16)    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 (Loss) for the period, net of tax (in thousands):
 Location on the Consolidated Statements of Income (Loss)Amount Reclassified from AOCI
December 31, 2017December 31, 2016
Gains and (losses) on cash flow hedges:   
Interest rate swapsInterest expense$(2,941)$(3,899)
Commodity contracts(Loss) from discontinued operations913
11,019
Commodity contracts
Fuel, purchased power and cost of natural gas sold

(243)(14)
  (2,271)7,106
Income taxIncome tax benefit (expense)875
(2,702)
Total reclassification adjustments related to cash flow hedges, net of tax $(1,396)$4,404
    
Amortization of components of defined benefit plans:   
Prior service costOperations and maintenance$168
$194
Prior service cost(Loss) from discontinued operations29
27
    
Actuarial gain (loss)Operations and maintenance(1,599)(1,881)
Actuarial gain (loss)(Loss) from discontinued operations(58)(97)
  (1,460)(1,757)
Income taxIncome tax benefit (expense)(516)533
Total reclassification adjustments related to defined benefit plans, net of tax $(1,976)$(1,224)
Total reclassifications $(3,372)$3,180




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 SwapsCommodity DerivativesEmployee Benefit PlansTotal
As of December 31, 2016$(18,109)$(233)$(16,541)$(34,883)
Other comprehensive income (loss)    
before reclassifications—
231
(1,890)(1,659)
Amounts reclassified from AOCI1,912
(516)944
2,340
Reclassification of certain tax effects from AOCI(3,384)—
(3,616)(7,000)
As of December 31, 2017$(19,581)$(518)$(21,103)$(41,202)
     
 Derivatives Designated as Cash Flow Hedges  
 Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
As of December 31, 2015$(341)$7,066
$(15,780)$(9,055)
Other comprehensive income (loss)    
before reclassifications(20,302)(361)(1,985)(22,648)
Amounts reclassified from AOCI2,534
(6,938)1,224
(3,180)
As of December 31, 2016$(18,109)$(233)$(16,541)$(34,883)


(17)    SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Years ended December 31,2017 2016 2015
 (in thousands)
Non-cash investing activities and financing from continuing operations -     
Property, plant and equipment acquired with accrued liabilities$28,191
 $27,034
 $25,039
Increase (decrease) in capitalized assets associated with asset retirement obligations$3,198
 $8,577
 $(1,498)
      
Cash (paid) refunded during the period for continuing operations-     
Interest (net of amount capitalized)$(132,428) $(113,627) $(78,744)
Income taxes (paid) refunded$1,775
 $(1,156) $(1,202)



(18)    (13)    EMPLOYEE BENEFIT PLANS


Defined Contribution Plans


We sponsor a 401(k) retirement savings plansplan (the 401(k) Plans)Plan). Participants in the 401(k) PlansPlan may elect to invest a portion of their eligible compensation in the 401(k) PlansPlan up to the maximum amounts established by the IRS. The 401(k) Plans providePlan provides employees the opportunity to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis.


The 401(k) Plans provide eitherPlan provides a Company Matching Contribution or a Non-Elective Safe Harbor Contributionmatching contribution for all eligible participants, depending upon the Plan in which the employee participates.participants. Certain eligible participants who are not currently accruing a benefit in the Pension Plan also receive a Company Retirement Contributionretirement contribution based on the participant’s age and years of service or a Company Discretionary Contribution, depending upon the pension plan in which the employee participates.service. Vesting of all Company and matching contributions ranges from immediate vesting to graduated vestingoccurs at 20% per year with 100% vesting when the participant has 5 years of service with the Company.

The SourceGas Retirement Savings Plan was merged into the Black Hills Corporation Retirement Savings Plan effective December 31, 2017. The plan design of the Black Hills Corporation 401(k) Plan will apply to all employees as of January 1, 2018.


Defined Benefit Pension Plan (Pension Plan)


At December 31, 2016 our three previousWe have 1 defined benefit pension plans consisting of the Black Hills Corporation Pension Plan, the Black Hills Utility Holding, Inc. Pension Plan and the SourceGas Retirement Plan were merged into one single 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.


98
The Pension Plan assets are held in a Master Trust. Due to the plan merger on December 31, 2016, reporting beginning in 2017 no longer represents an undivided interest in the Master Trust. Our Board of Directors has approved the Pension Plan’s investment policy. The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of our obligations to the Pension Plan’s beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a portfolio strategy that will provide liquidity to meet the Pension Plan’s benefit payment obligations. The Pension Plan’s assets consist primarily of equity, fixed income and hedged investments.


The expected rate of return on the Pension Plan assets is determined by reviewing the historical and expected returns of both equity and fixed income markets, taking into account asset allocation, the correlation between asset class returns and the mix of active and passive investments. The Pension Plan utilizes a dynamic asset allocation where the target range to return-seeking and liability-hedging assets is determined based on a targeted asset allocation range determined by the funded ratiostatus of the plan.Plan. As of December 31, 2017,2021, the expected rate of return on pension plan assets was based on the targeted asset allocation range of 37% 22%to 45% equity securities30% return-seeking assets and 55%70% to 63% fixed-income securities and the expected rate of return from these asset categories. The expected rate of return on other postretirement plan assets was based on the targeted asset allocation range of 15% to 25% equity securities and 75% to 85% fixed-income securities and the expected rate of return from these asset categories.78% liability-hedging assets.


The expected long-term rate of return for investments was 6.25% and 6.75% for the Pension Plan 2017 and 2016 plan years, respectively. 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:
20212020
Equity15%21%
Real estate73
Fixed income7469
Cash13
Hedge funds34
Total100%100%
 20172016
Equity26%28%
Real estate45
Fixed income6357
Cash12
Hedge funds68
Total100%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 not funded by the Company.

Plan Assets

We do not fund our Supplemental Plans. We fund on a cash basis as benefits are paid.


Non-pension Defined Benefit Postretirement Healthcare PlansPlan


BHC sponsors a retiree healthcare plansplan (Healthcare Plans)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 PlansPlan for participating business units are pre-funded via VEBAs.VEBA trusts. Pre-65 retirees as well as a grandfathered group of post-65 Cheyenne Light, Fuel and Power (“CLFP”) retirees and a grandfathered group of post-65 former SourceGas employees who retired prior to January 1, 2017 receive their retiree medical benefits through the Black Hills self-insured retiree medical plans.

Healthcare coverage for post-65 Medicare-eligible BHC and Black Hills Utility Holdings retirees is provided through an individual market healthcare exchange. Medicare-eligible SourceGas employees who retired after December 31, 2016 also receive retiree medical coverage through an individual market healthcare exchange.

Plan Assets


We fund the Healthcare PlansPlan on a cash basis as benefits are paid. The Black Hills Utility Holding and SourceGas Postretirement - AWG Plans provideHealthcare Plan provides for partial pre-funding via VEBAs and a Grantor Trust.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, KansasIowa and Iowa.Kansas. We do not pre-fund the Healthcare PlansPlan for those employees outside Arkansas, KansasIowa and Iowa.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):
20212020
Defined Contribution Plan
Company retirement contributions$11,332 $10,455 
Company matching contributions$15,938 $15,240 
99
 20172016
Defined Contribution Plan  
Company retirement contribution$10,223
$9,632
Matching contributions$9,811
$9,645
20212020
Defined Benefit Plans
Defined Benefit Pension Plan$— $12,700 
Non-Pension Defined Benefit Postretirement Healthcare Plan$6,432 $6,058 
Supplemental Non-Qualified Defined Benefit Plans$2,576 $2,674 

 20172016
Defined Benefit Plans  
Defined Benefit Pension Plan$27,700
$14,200
Non-Pension Defined Benefit Postretirement Healthcare Plans$4,332
$4,965
Supplemental Non-Qualified Defined Benefit Plans$3,217
$1,565


While we do not have required contributions, we expect to make approximately $13$3.9 million in contributions to our Pension Plan in 2018.2022.


Fair Value Measurements

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect their placement within the fair value hierarchy levels.




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 PlanDecember 31, 2021
Level 1Level 2Level 3Total 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 

Pension PlanDecember 31, 2020
Level 1Level 2Level 3Total Investments Measured at Fair Value
NAV (a)
Total Investments
Common Collective Trust - Cash and Cash Equivalents— 16,810 — 16,810 — 16,810 
Common Collective Trust - Equity— 100,311 — 100,311 — 100,311 
Common Collective Trust - Fixed Income— 324,845 — 324,845 — 324,845 
Common Collective Trust - Real Estate— — — — 14,301 14,301 
Hedge Funds— — — — 17,454 17,454 
Total investments measured at fair value$— $441,966 $— $441,966 $31,755 $473,721 
____________________
(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 PlanDecember 31, 2021
Level 1Level 2Level 3Total Investments Measured at Fair ValueTotal Investments
Cash and Cash Equivalents$7,972 $— $— $7,972 $7,972 
Total investments measured at fair value$7,972 $— $— $7,972 $7,972 

100
Pension PlanDecember 31, 2017
 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value 
NAV (a)
 Total Investments
AXA Equitable General Fixed Income$—
 $1,280
 $—
 $1,280
 $—
 $1,280
Common Collective Trust - Cash and Cash Equivalents—
 2,184
 —
 2,184
 —
 2,184
Common Collective Trust - Equity—
 109,496
 —
 109,496
 —
 109,496
Common Collective Trust - Fixed Income—
 262,329
 —
 262,329
 —
 262,329
Common Collective Trust - Real Estate—
 1,728
 —
 1,728
 15,701
 17,429
Hedge Funds—
 —
 —
 —
 23,625
 23,625
Total investments measured at fair value$—
 $377,017
 $—
 $377,017
 $39,326
 $416,343
Non-pension Defined Benefit Postretirement Healthcare PlanDecember 31, 2020
Level 1Level 2Level 3Total Investments Measured at Fair ValueTotal Investments
Cash and Cash Equivalents$8,165 $— $— $8,165 $8,165 
Total investments measured at fair value$8,165 $— $— $8,165 $8,165 

Pension PlanDecember 31, 2016
 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value 
NAV (a)
 Total Investments
AXA Equitable General Fixed Income$—
 $1,325
 $—
 $1,325
 $—
 $1,325
Common Collective Trust - Cash and Cash Equivalents—
 5,307
 —
 5,307
 —
 5,307
Common Collective Trust - Equity—
 101,020
 —
 101,020
 —
 101,020
Common Collective Trust - Fixed Income—
 209,815
 —
 209,815
 —
 209,815
Common Collective Trust - Real Estate—
 2,349
 —
 2,349
 15,563
 17,912
Hedge Funds—
 —
 —
 —
 29,316
 29,316
Total investments measured at fair value$—
 $319,816
 $—
 $319,816
 $44,879
 $364,695
_____________
(a)Certain investments that are measured at fair value using Net Asset Value “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 PlansDecember 31, 2017
 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value 
NAV (a)
 Total Investments
Cash and Cash Equivalents$4,671
 $—
 $—
 $4,671
 $—
 $4,671
Equity Securities1,374
 —
 —
 1,374
 —
 1,374
Intermediate-term Bond—
 2,576
 —
 2,576
 —
 2,576
Total investments measured at fair value$6,045
 $2,576
 $—
 $8,621
 $—
 $8,621



Non-pension Defined Benefit Postretirement Healthcare PlansDecember 31, 2016
 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value 
NAV (a)
 Total Investments
Cash and Cash Equivalents$111
 $—
 —
 $111
 —
 $111
Equity Securities1,154
 —
 —
 $1,154
 —
 1,154
Registered Investment Company Trust - Money Market Mutual Fund—
 4,732
 —
 $4,732
 —
 4,732
Intermediate-term Bond—
 2,473
 —
 $2,473
 —
 2,473
Total investments measured at fair value$1,265
 $7,205
 $—
 $8,470
 $—
 $8,470
_____________
(a)Certain investments that are measured at fair value using Net Asset Value “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 plans’ benefit obligations and fair value of plan assets above.


Additional information about assets of the benefit plans, including methods and assumptions used to estimate the fair value of these assets, is as follows:


Cash and Cash Equivalents: This represents an investment in Invesco Treasury Portfolio, which is a short-term investment trust, as well as an investment in Northern Institutional Government Assets Portfolio, which is described as a government money market fund. As shares held reflect quoted prices in an active market, they are categorized as Level 1.Pension Plan


Equity Securities: These represent investments in a combination of equity positions for mainly large cap core allocation and Exchange Trade Funds (ETFs) for diversification into the other sectors of the economy. ETFs are a basket of securities traded like individual stocks on the exchange. Value of equity securities held at year end are based on published market quotations of active markets. The ETF funds can be redeemed on a daily basis at their market price and have no redemption restrictions. As shares held reflect quoted prices in an active market, they are categorized as Level 1.

Intermediate-term bond: This is comprised of a diversified pool of high quality, individual municipal bonds. Pricing is evaluated using multi-dimensional relational models, as well as a series of matrices using Standard Inputs, including Municipal Securities Rule Making Board (MSRB) reported trades and material event notices, plus Municipal Market Data (MMD) benchmark yields and new issue data. As the models use observable inputs and standard data, the investments are categorized as Level 2.

AXA Equitable General Fixed Income Fund: This fund is a diversified portfolio, primarily composed of fixed income instruments. Assets are invested in long-term holdings, such as commercial, agricultural and residential mortgages, publicly traded and privately placed bonds and real estate as well as short-term bonds. Fair values of mortgage loans are measured by discounting future contractual cash flows to be received on the mortgage loans using interest rates of loans with similar characteristics. The discount rate is derived from taking the appropriate U.S. Treasury rate with a like term. The fair value of public fixed maturity securities are generally based on prices obtained from independent valuation service providers with reasonableness prices compared with directly observable market trades. The fair value of privately placed securities are determined using a discounted cash flow model. These models use observable inputs with a discount rate based upon the average of spread surveys collected from private market intermediaries and industry sector of the issuer. The Plan’s investments in the AXA Equitable General Fixed Income Fund are categorized as Level 2.

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.
Common Collective Trust-Real Estate FundFunds: This fund isThese 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. TheSome of the funds without participant withdrawal limitations 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.guidance:
Common Collective Trust-Real Estate Fund: This is the same fund as above except that certain of the funds’ assets contain participant withdrawal policies with restrictions on redemption and are therefore not included in the fair value hierarchy.
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. Generally,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 a 65 day60-day notice and areis limited to a percentage of the total net assetassets 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.

101
Other Plan Information


The following tables provide a reconciliation of the employee benefit plan obligations and fair value of employee benefit plan assets, and 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 PlansDefined Benefit Pension PlanSupplemental Non-qualified Defined
Benefit Plans		Non-pension Defined Benefit Postretirement Healthcare Plan
As of December 31,20172016 20172016 20172016As of December 31,202120202021202020212020
Change in benefit obligation:     Change in benefit obligation:
Projected benefit obligation at beginning of year$440,179
$356,575
 $43,869
$40,219
 $68,023
$48,077
Projected benefit obligation at beginning of year$514,008 $485,376 $55,054 $54,088 $70,238 $65,277 
Transfer from SourceGas Acquisition—
75,254
 —
—
 —
15,091
Service cost7,034
7,619
 2,937
2,099
 2,300
1,757
Service cost (a)
Service cost (a)
5,038 5,411 3,149 1,579 2,237 2,056 
Interest cost15,520
15,743
 1,276
1,257
 2,141
1,942
Interest cost9,313 13,426 706 1,099 1,058 1,649 
Actuarial (gain) loss (a)
36,661
7,001
 247
2,049
 (396)2,808
Actuarial (gain) lossActuarial (gain) loss(14,037)47,064 (1,073)962 (5,165)5,804 
Amendments—
—
 —
—
 265
2,203
Amendments(561)— — — — — 
Benefits paid(24,669)(22,013) (3,217)(1,755) (4,332)(4,965)Benefits paid(35,499)(37,269)(2,576)(2,674)(6,432)(6,058)
Plan participants’ contributions—
—
 —
—
 1,338
1,110
Plan participants’ contributions— — — — 1,548 1,510 
Projected benefit obligation at end of year$474,725
$440,179
 $45,112
$43,869
 $69,339
$68,023
Projected benefit obligation at end of year$478,262 $514,008 $55,260 $55,054 $63,484 $70,238 
____________________
(a)Increase from 2016 is primarily the result of a decrease in the discount rate.

(a)    For the year ended December 31, 2020, Service Cost for the Supplemental Non-qualified Defined Benefit Plans includes a $1.4 million correction of a prior year overstatement of Projected benefit obligation.



Fair Value Employee Benefit Plan Assets
Defined Benefit
Pension Plan
 Supplemental Non-qualified Defined Benefit Plans 
Non-pension Defined Benefit Postretirement Healthcare Plans (a)
Defined Benefit
Pension Plan		Supplemental Non-qualified Defined
Benefit Plans
Non-pension Defined Benefit Postretirement Healthcare Plan (a)
As of December 31,20172016 20172016 20172016As of December 31,202120202021202020212020
Change in fair value of plan assets:     Change in fair value of plan assets:
Beginning fair value of plan assets$364,695
$288,622
 $—
$—
 $8,470
$4,681
Beginning fair value of plan assets$473,721 $434,284 $— $— $8,165 $8,305 
Transfer from SourceGas Acquisition—
53,067
 —
—
 —
3,340
Investment income (loss)48,617
30,819
 —
—
 120
256
Investment income (loss)20,165 64,006 — — (35)33 
Employer contributions27,700
14,200
 3,217
1,755
 3,025
4,048
Employer contributions— 12,700 2,576 2,674 4,726 4,374 
Retiree contributions—
—
 —
—
 1,338
1,110
Retiree contributions— — — — 1,548 1,511 
Benefits paid(24,669)(22,013) (3,217)(1,755) (4,332)(4,965)Benefits paid(35,499)(37,269)(2,576)(2,674)(6,432)(6,058)
Ending fair value of plan assets$416,343
$364,695
 $—
$—
 $8,621
$8,470
Ending fair value of plan assets$458,387 $473,721 $— $— $7,972 $8,165 
____________________
(a)Assets of VEBAs and Grantor Trust.

(a)    Assets of VEBA trusts.
The funded status
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 the plansannuities and the amounts recognizedreduction of return-seeking assets over time to a more liability-hedged portfolio. As a result, capital markets volatility driven by the COVID-19 pandemic did not materially affect our unfunded status.

Amounts Recognized in the Consolidated Balance Sheets at December 31 consist
Defined Benefit
Pension Plan		Supplemental
Non-qualified Defined Benefit Plans		Non-pension Defined Benefit Postretirement Healthcare Plan
As of December 31,202120202021202020212020
Regulatory assets$67,403 $86,677 $— $— $11,660 $16,102 
Current liabilities$— $— $2,156 $1,927 $4,584 $4,931 
Non-current liabilities$19,872 $40,287 $53,104 $53,127 $50,949 $57,142 
Regulatory liabilities$3,830 $3,607 $— $— $2,447 $2,140 

102
 
Defined Benefit
Pension Plan
 
Supplemental
Non-qualified Defined Benefit Plans
Non-pension Defined Benefit Postretirement Healthcare Plans
 20172016 20172016 20172016
Regulatory assets$72,756
$66,640
 $—
$—
 $11,507
$11,401
Current liabilities$—
$—
 $1,372
$1,583
 $4,423
$4,360
Non-current assets$—
$—
 $—
$—
 $69
$21
Non-current liabilities$58,381
$75,484
 $43,739
$42,286
 $56,365
$55,214
Regulatory liabilities$5,232
$5,195
 $—
$—
 $3,334
$3,419



Accumulated Benefit Obligation

Defined Benefit
Pension Plan		Supplemental
Non-qualified Defined Benefit Plans		Non-pension Defined Benefit Postretirement Healthcare Plan
As of December 31,202120202021202020212020
Accumulated Benefit Obligation$466,505 $498,815 $55,260 $54,779 $63,484 $70,238 
As of December 31 (in thousands)
Defined Benefit
Pension Plan
 
Supplemental
Non-qualified Defined Benefit Plans
Non-pension Defined Benefit Postretirement Healthcare Plans
 20172016 20172016 20172016
Accumulated Benefit Obligation (a)
$450,394
$416,786
 $41,243
$32,090
 $69,339
$68,023
____________________
(a)The Defined Benefit Pension Plan Accumulated Benefit Obligation for 2017 and 2016 represents the obligation for the merged Black Hills Retirement Plan. The Non-pension Defined Benefit Retirement Healthcare Plans Accumulated Benefit Obligation for 2017 and 2016 represents that obligation for the five postretirement plans maintained by BHC.


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 31,202120202019202120202019202120202019
Service cost (a)
$5,038 $5,411 $5,383 $3,149 $1,579 $4,995 $2,237 $2,056 $1,815 
Interest cost9,313 13,426 17,374 706 1,099 1,295 1,058 1,649 2,247 
Expected return on assets(20,876)(22,591)(24,401)— — — (136)(182)(230)
Net amortization of prior service cost— — 26 — 2 2 (434)(546)(398)
Recognized net actuarial loss (gain)7,315 8,372 3,763 1,754 1,702 535 466 20 — 
Net periodic expense$790 $4,618 $2,145 $5,609 $4,382 $6,827 $3,191 $2,997 $3,434 
Net periodic expense consisted of the following for____________________
(a)    For the year ended December 31, (in thousands):2020, Service Cost for the Supplemental Non-qualified Defined Benefit Plans includes a $1.4 million correction of a prior year overstatement of Projected benefit obligation.
 
Defined Benefit
Pension Plan
 
Supplemental
Non-qualified Defined Benefit Plans
 Non-pension Defined Benefit Postretirement Healthcare Plans
 201720162015 201720162015 201720162015
Service cost$7,034
$7,619
$6,093
 $1,546
$1,335
$1,380
 $2,300
$1,757
$1,808
Interest cost15,520
15,743
15,522
 1,276
1,257
1,455
 2,141
1,942
1,801
Expected return on assets(24,517)(23,062)(19,470) —
—
—
 (315)(279)(131)
Net amortization of prior service cost58
58
58
 2
2
2
 (411)(428)(428)
Recognized net actuarial loss (gain)4,007
7,173
11,037
 1,001
829
1,081
 499
335
408
Settlement expense(a)
—
10
—
 —
—
—
 —
—
—
Net periodic expense$2,102
$7,541
$13,240
 $3,825
$3,423
$3,918
 $4,214
$3,327
$3,458
____________________
(a)Settlement expense is the result of lump-sum payments on the SourceGas Retirement Plan in excess of interest and service costs for the year.

AOCI


For defined benefit plans, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost atthe years ended December 31, 2021, 2020 and 2019, Service costs were as follows (in thousands):recorded in Operations and maintenance expense while non service costs were recorded in Other expense on the Consolidated Statements of Income.

 
Defined Benefit
Pension Plan
 
Supplemental
Non-qualified Defined Benefit Plans
Non-pension Defined Benefit Postretirement Healthcare Plans
 20172016 20172016 20172016
Net (gain) loss$10,056
$8,472
 $6,639
$7,132
 $1,309
$1,595
Prior service cost (gain)21
31
 4
5
 (542)(694)
Reclassification of certain tax effects from AOCI2,087
—
 1,371
—
 158
—
Total AOCI$12,164
$8,503
 $8,014
$7,137
 $925
$901
AOCI Amounts (After-Tax)

Defined Benefit
Pension Plan		Supplemental
Non-qualified Defined Benefit Plans		Non-pension Defined Benefit Postretirement Healthcare Plan
As of December 31,202120202021202020212020
Net (gain) loss$4,398 $5,511 $7,159 $9,323 $(308)$100 
Prior service cost (gain)(46)— — — (27)(144)
Total amounts included in AOCI, after-tax not yet recognized as components of net periodic expense$4,352 $5,511 $7,159 $9,323 $(335)$(44)


The amounts in AOCI, Regulatory assets or Regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2018 are as follows (in thousands):
 Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans
Net loss$5,610
 $650
 $141
Prior service cost (credit)38
 1
 (258)
Total net periodic benefit cost expected to be recognized during calendar year 2018$5,648
 $651
 $(117)


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:202120202019202120202019202120202019
Discount rate2.88 %2.56 %3.27 %2.77 %2.41 %3.14 %2.79 %2.41 %3.15 %
Rate of increase in compensation levels3.08 %3.34 %3.49 %5.00 %5.00 %5.00 %N/AN/AN/A
103
 
Defined Benefit
Pension Plan
 
Supplemental
Non-qualified Defined Benefit Plans
 Non-pension Defined Benefit Postretirement Healthcare Plans
Weighted-average assumptions used to determine benefit obligations:201720162015 201720162015 201720162015
            
Discount rate3.71%4.27%4.58% 3.56%4.02%4.28% 3.60%3.96%4.17%
Rate of increase in compensation levels3.43%3.47%3.51% 5.00%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:202120202019202120202019202120202019
Discount rate (a)
2.56 %3.27 %4.40 %2.41 %3.14 %4.34 %2.41 %3.15 %4.28 %
Expected long-term rate of return on assets (b)
4.50 %5.25 %6.00 %N/AN/AN/A1.80 %2.35 %3.00 %
Rate of increase in compensation levels3.34 %3.49 %3.52 %5.00 %5.00 %5.00 %N/AN/AN/A

____________________
(a)    The estimated discount rate for the Defined Benefit Pension Plan is 2.88% for the calculation of the 2022 net periodic pension costs.
 
Defined Benefit
Pension Plan
 
Supplemental
Non-qualified Defined Benefit Plans
 Non-pension Defined Benefit Postretirement Healthcare Plans
Weighted-average assumptions used to determine net periodic benefit cost for plan year:201720162015 201720162015 201720162015
            
Discount rate (a)
4.27%4.50%4.19% 4.02%4.28%4.19% 4.05%4.18%3.82%
Expected long-term rate of return on assets (b)
6.75%6.87%6.75% N/A
N/A
N/A
 3.88%3.83%3.00%
Rate of increase in compensation levels3.47%3.42%3.76% 5.00%5.00%5.00% N/A
N/A
N/A
(b)    The expected rate of return on plan assets is 4.25% for the calculation of the 2022 net periodic pension cost.
_____________________________
(a)The estimated discount rate for the merged Black Hills Retirement Plan is 3.71% for the calculation of the 2018 net periodic pension costs.
(b)
The expected rate of return on plan assets is 6.25% for the calculation of the 2018 net periodic pension cost.




The healthcare benefit obligation was determined at December 31 was determined as follows:
20212020
Trend Rate - Medical
Pre-65 for next year - All Plans6.05%6.10%
Pre-65 Ultimate trend rate - Black Hills Corp4.50%4.50%
Trend Year20302027
Post-65 for next year - All Plans5.10%4.92%
Post-65 Ultimate trend rate - Black Hills Corp4.50%4.50%
Trend Year20302029
 2017
2016 (a)
Trend Rate - Medical  
Pre-65 for next year - All Plans7.00%6.10%
Pre-65 Ultimate trend rate - Black Hills Corp4.50%4.50%
Trend Year20272024
   
Post-65 for next year - All Plans5.00%5.10%
Post-65 Ultimate trend rate - Black Hills Corp4.50%4.50%
Trend Year20262023
_____________________________
(a)The 2016 Medical Trend Rates include the two additional non-pension defined benefit postretirement plans from SourceGas.

We do not pre-fund our supplemental plans or three of the five healthcare plans. The table below shows the expected impacts of an increase or decrease to our healthcare trend rate for our Healthcare Plans (in thousands):
Change in Assumed Trend Rate 
Impact on December 31, 2017 Accumulated Postretirement
Benefit Obligation
 
Impact on 2018 Service
and Interest Cost
Increase 1% $2,968
 $148
Decrease 1% $(2,534) $(126)

Beginning in 2016, the Company changed the method used to estimate the service and interest cost components of the net periodic pension, supplemental non-qualified defined benefit and other postretirement benefit costs. See “Pension and Postretirement Benefit Obligations” within our Critical Accounting Policies in Item 7 on Form 10-K for additional details.


The following benefit payments to employees, which reflect future service, are expected to be paid (in thousands):
Defined Benefit Pension PlanSupplemental Non-qualified Defined Benefit PlansNon-pension Defined Benefit Postretirement Healthcare Plan
2022$26,249 $2,156 $5,806 
2023$27,133 $2,224 $5,334 
2024$27,683 $2,410 $5,042 
2025$28,650 $2,757 $4,865 
2026$28,968 $2,782 $4,752 
2027-2031$144,422 $12,553 $21,615 


104
 Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-Pension Defined Benefit Postretirement Healthcare Plans
2018$21,495
 $1,372
 $5,633
2019$23,238
 $1,617
 $6,231
2020$27,203
 $1,558
 $6,328
2021$26,990
 $1,773
 $6,072
2022$27,427
 $1,872
 $5,920
2023-2027$154,771
 $11,304
 $26,365


(14) SHARE-BASED COMPENSATION PLANS


(19)    COMMITMENTS AND CONTINGENCIESOur 2015 Omnibus Incentive Plan allows for the granting of stock, restricted stock, restricted stock units, stock options, performance shares and performance share units. We had 416,325 shares available to grant at December 31, 2021.


Power PurchaseCompensation expense is determined using the grant date fair value estimated in accordance with the provisions of accounting standards for stock compensation and Transmission Services Agreementsis recognized over the vesting periods of the individual awards. As of December 31, 2021, total unrecognized compensation expense related to non-vested stock awards was approximately $14 million and is expected to be recognized over a weighted-average period of two 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):

202120202019
Stock-based compensation expense$9,655 $5,373 $12,095 
Through
Restricted Stock

The fair value of restricted stock and restricted stock unit awards equals the market price of our subsidiaries, we havestock on the following significant long-term power purchase contracts with non-affiliated third-parties:date of grant.


Black Hills Wyoming sold its CTII 40 MW natural gas-fired generating unitThe 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 City of Gillette, Wyoming on September 3, 2014. Underawards is recognized over the termsvesting period.

A summary of the sale, Black Hills Wyoming entered into ancillary agreementsstatus of the restricted stock and restricted stock units at December 31, 2021, was as follows:
Restricted StockWeighted-Average Grant Date Fair Value
(in thousands)
Balance at January 1, 2021196 $69.05 
Granted118 65.64 
Vested(83)67.85 
Forfeited(12)69.59 
Balance at December 31, 2021219 $67.64 

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 ValueTotal Fair Value of Shares Vested
(in thousands)
2021$65.64 $5,400 
2020$69.49 $6,722 
2019$73.66 $8,438 

As of December 31, 2021, there was $11 million of unrecognized compensation expense related to operate CTII, provide usenon-vested restricted stock that is expected to be recognized over a weighted-average period of shared facilities including2.2 years.

Performance Share Plan

Prior to 2021, certain officers of the Company and its subsidiaries became participants in a ground lease and dispatch generation services.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 agreement includesperformance 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 20-year economy energy PPAliability 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 contains a sharing arrangement in whichchange-in-control is probable, the parties share the savingsequity portion of wholesale power purchases made when market power prices are less than the cost of operating the generating unit.

South Dakota Electric’s PPA with PacifiCorp, expiring$2.1 million at December 31, 2023,2021 would be reclassified as a liability.


105
The outstanding performance periods at December 31, 2021 were as follows (shares in thousands):
Possible Payout Range of Target
Grant DatePerformance PeriodTarget Grant of SharesMinimumMaximum
January 1, 2020January 1, 2020 - December 31, 2022360%200%
January 1, 2019January 1, 2019 - December 31, 2021360%200%

A summary of the status of the Performance Share Plan at December 31, 2021 was as follows:
Equity PortionLiability Portion
Weighted-Average Grant Date Fair Value (a)
Weighted-Average Fair Value at
SharesSharesDecember 31, 2021
(in thousands)(in thousands)
Performance Shares balance at beginning of period61 $69.71 61 
Granted— — — 
Forfeited— — — 
Vested(25)61.82 (25)
Performance Shares balance at end of period36 $68.14 36 $31.51 
____________________
(a)    The grant date fair values for the purchaseperformance shares granted in 2020 and 2019 were determined by Monte Carlo simulation using a blended volatility of 50 MW18% and 21%, respectively, comprised of electric capacity50% historical volatility and energy from PacifiCorp’s system. 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 price paidweighted-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 
December 31, 2019$68.72 

Performance plan payouts have been as follows (in thousands):
Performance PeriodYear PaidStock IssuedCash PaidTotal Intrinsic Value
January 1, 2018 to December 31, 2020202128 $1,647 $3,294 
January 1, 2017 to December 31, 2019202014 $1,100 $2,199 
January 1, 2016 to December 31, 2018201944 $2,860 $5,720 

On January 25, 2022, the Compensation Committee of our Board of Directors determined that the Company’s total shareholder return for the capacityJanuary 1, 2018 to December 31, 2020 performance period was at the 30th percentile of its peer group and energyconfirmed a payout equal to 40.17% of target shares, valued at $1.0 million. The payout was fully accrued at December 31, 2021.

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, awarded vest on a pro-rata basis over the three-year period.

106
Performance Share Units - Market Condition

The fair value of each share unit is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants.

South Dakota Electric’s firm point-to-point transmission service agreement with PacifiCorp that expiresCompany’’s closing price at December 31 2023.of the year prior to the award and a Monte Carlo simulation. The agreement provides 50 MWMonte 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 capacitythe award year.

2021
Fair value of share units award$64.97
Three-year risk-free rate0.17%
Black Hills Corporation’s common stock volatility33%
Volatility range for the peer group25 %-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 energythe 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, 2021:

Performance Share Units -
Market Condition		Performance Share Units -
Performance Condition
Share UnitsWeighted-Average Fair Value per Share UnitShare UnitsWeighted-Average Fair Value per Share Unit
Nonvested at January 1, 2021— $— — $— 
Granted32,903 64.97 21,948 61.45 
Nonvested at December 31, 202132,903 $64.97 21,948 $61.45 

As of December 31, 2021, there was $2.9 million of unrecognized compensation expense related to outstanding performance share/unit plans that is expected to be transmitted annually by PacifiCorp.recognized over a weighted-average period of 1.8 years.


Wyoming Electric’s PPA
(15)    INCOME TAXES

Winter Storm Uri

As discussed in Note 2 above, our Utilities submitted cost recovery applications which seek to recover incremental costs from Winter Storm Uri through a regulatory mechanism. We expect to recover these costs from customers over several years. Winter Storm Uri costs, which will be deductible in our 2021 tax return, created a net deferred tax liability which had a balance of $124 million as of December 31, 2021. The deferred tax liability will reverse with Duke Energy’s Happy Jack wind site, expiring September 3, 2028, providesthe same timing as the costs are recovered from our customers.

The income tax deduction recognized from Winter Storm Uri will create 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 2022 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, 2021.
107

CARES Act

On March 27, 2020, President Trump signed the CARES Act, which contained, in part, an allowance for deferral of the employer portion of Social Security employment tax liabilities until 2021 and 2022, as well as a COVID-19 employee retention tax credit of up to 30 MW$5,000 per eligible employee.

During the year ended December 31, 2020, we utilized the payroll tax deferral provision which allowed us to defer payment of wind energy from Happy Jack to Wyoming Electric. Under a separate intercompany agreement, Wyoming Electric sells 50%approximately $10 million of Social Security employment tax liabilities, of which $4.8 million was subsequently paid in 2021 and the remaining portion will be paid in 2022. During the year ended December 31, 2021, we completed our study of the facility outputCARES Act employee retention tax credits and recognized $1.2 million of gross payroll tax credits.

TCJA

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to South Dakota Electric.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. As of December 31, 2021, the Company has amortized, or provided bill credits for, $23 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.


Wyoming Electric’s PPA with Duke Energy’s Silver Sage wind site, expiring September 30, 2029, provides up to 30 MW of wind energy. Under a separate intercompany agreement, Wyoming Electric sells 20 MW of energyIncome Tax Expense (Benefit)

Income tax expense (benefit) from Silver Sage to South Dakota Electric.continuing operations for the years ended December 31 was (in thousands):

202120202019
Current:
Federal$574 $(6,020)$(8,578)
State(666)847 138 
Current income tax (benefit)(92)(5,173)(8,440)
Deferred:
Federal2,170 35,672 34,551 
State5,091 2,419 3,469 
Deferred income tax expense7,261 38,091 38,020 
Income tax expense$7,169 $32,918 $29,580 


Colorado Electric’s REPA with AltaGas expiring October 16, 2037, provides up to 14.5 MW
108
Effective Tax Rates

The effective tax rate differs from the Busch Ranch Wind Farmfederal statutory rate for the years ended December 31, as follows:
202120202019
Federal statutory rate21.0 %21.0 %21.0 %
State income tax (net of federal tax effect)1.2 2.4 1.5 
Non-controlling interest (a)
(1.2)(1.2)(1.2)
Tax credits(b)
(8.4)(9.2)(3.9)
Flow-through adjustments (c)
(3.2)(1.6)(2.4)
Uncertain Tax Benefits0.3 1.5 — 
Valuation Allowance— 0.7 — 
Other tax differences(0.2)0.6 (1.6)
Amortization of excess deferred income tax expense (d)
(3.1)(2.3)(1.2)
TCJA bill credits (e)
(3.6)— — 
Effective Tax Rate2.8 %11.9 %12.2 %
____________________
(a)    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.
(b)    In 2020, the Company completed a research and development study which encompassed tax years from 2013 to 2019.
(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)    As discussed in Note 2 above, Colorado Electric ownsand Nebraska Gas bill credits, which represent a 50% undivided ownership interest.disposition of excess deferred income tax benefits resulting from the TCJA, were delivered to 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.

109

Deferred Tax Assets and Liabilities
Costs under these power purchase contracts
The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands):
20212020
Deferred tax assets:
Regulatory liabilities$77,099 $90,535 
State tax credits23,342 23,339 
Federal NOL (a)
227,535 96,155 
State NOL (a)
33,639 9,914 
Partnership13,395 15,601 
Credit Carryovers68,646 51,445 
Other deferred tax assets31,996 40,143 
Less: Valuation allowance(14,719)(13,943)
Total deferred tax assets460,933 313,189 
Deferred tax liabilities:
Accelerated depreciation, amortization and other property-related differences(597,284)(551,137)
Regulatory assets (a)
(124,582)(28,007)
Goodwill(45,471)(30,590)
State deferred tax liability (a)
(109,136)(73,910)
Other deferred tax liabilities(49,848)(38,169)
Total deferred tax liabilities(926,321)(721,813)
Net deferred tax liability$(465,388)$(408,624)
 201720162015
PPA with PacifiCorp$13,218
$12,221
$13,990
Transmission services agreement with PacifiCorp$1,671
$1,428
$1,213
PPA with Happy Jack$3,846
$3,836
$3,155
PPA with Silver Sage$4,934
$4,949
$4,107
Busch Ranch Wind Farm$1,966
$2,071
$1,734
PPAs with Cargill (a)
$—
$10,995
$16,112
____________________
________________
(a)PPAs with Cargill expired on December 31, 2016.

(a)    Increase primarily driven by Winter Storm Uri — see above.
Other Gas Supply Agreements

Net Operating Loss Carryforwards
Our Utilities also 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.




Purchase Commitments

We maintain natural gas supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated baseload gas volumes are established prior to the beginning of the month under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month based on requirements in accordance with the terms of the individual contract.

Our Gas Utilities segment has 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. At December 31, 2017, the long-term commitments to purchase quantities of natural gas under contracts indexed to the following forward indices were2021, we have federal and state NOL carryforwards that will expire at various dates as follows (in MMBtus):

 CIG RockiesNNG-VenturaNWPL-WyomingEP-San Juan BasinOther
20185,784,827
3,759,500
1,298,970
278,600
30,562
20195,776,125
3,704,300
786,470
287,000
—
202075,075
3,660,000
—
206,600
—
2021—
3,650,000
—
—
—
2022—
1,810,000
—
—
—

Purchases under these contracts totaled $65 million, $31 million and $48 million for 2017, 2016 and 2015, respectively.

The following is a schedule of unconditional purchase obligations required under the power purchase, transmission services, coal and natural gas transportation and storage agreements (in thousands):
AmountsExpiration Dates
Federal NOL Carryforward$476,033 2022to2037
Federal NOL Carryforward$607,465 No expiration
State NOL Carryforward (a)
$572,203 2022to2041
 Power Purchase AgreementsTransportation, storage and coal agreements
2018$28,041
$121,485
2019$6,837
$122,351
2020$6,837
$117,332
2021$6,203
$107,918
2022$6,203
$87,393
Thereafter$6,204
$202,831
____________________

Future Purchase Agreement - Related Party

Wyoming Electric’s PPA for 60 MW of capacity and energy from Black Hills Wyoming’s Wygen I generating facility expiring on December 31, 2022, includes an option for Wyoming Electric to purchase Black Hills Wyoming’s ownership in the Wygen I facility.(a)    The purchase price related to the optioncarryforward balance is $2.6 million per MW which is the equivalent per MW of the pre-construction estimated cost of the Wygen III plant, which was completed in April 2010. This option purchase price is adjusted for capital additions and reduced by an amount equal to annual depreciation based on a 35-year life starting January 1, 2009. The purchase option would be subject to WPSC and FERC approval in order to obtain regulatory treatment.

Power Sales Agreements

Through our subsidiaries, we have the following significant long-term power sales contracts with non-affiliated third-parties:

During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, MDU will be provided with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU. This agreement expires January 31, 2023.

South Dakota Electric has an agreement to serve MDU capacity and energy up to a maximum of 50 MW in excess of Wygen III ownership. This agreement expires December 31, 2023.



During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first 23 MW from our other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, which expires September 3, 2019, South Dakota Electric will also provide the City of Gillette their operating component of spinning reserves.

South Dakota Electric has a PPA with MEAN expiring May 31, 2023. This contract is unit-contingent on up to 10 MW from Neil Simpson II and up to 10 MW from Wygen III basedreflected on the availabilitybasis of these plants. The capacity purchase requirements decrease over the term of the agreement.
apportioned tax losses to jurisdictions imposing state income taxes.

South Dakota Electric has an agreement from January 1, 2017 through December 31, 2021 to provide 50 MW of energy to Cargill (assigned to Macquarie on January 3, 2018) during heavy and light load timing intervals.

Related Party Lease

Colorado Electric’s PPA with Black Hills Colorado IPP expiring on December 31, 2031, provides 200 MW of power to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines. This PPA is accounted for as a capital lease whereby Colorado Electric, as lessee, has included the combined-cycle turbines as property, plant and equipment along with the related lease obligation and Black Hills Colorado IPP, as lessor, has recorded a lease receivable. Segment revenue and expenses associated with the PPA have been impacted by the lease accounting. The effect of the lease accounting is eliminated in corporate consolidations.

Reimbursement Agreement

We have a reimbursement agreement in place with Wells Fargo on behalf of Wyoming Electric for the 2009A bonds of $10 million due in 2027 and the 2009B bonds of $7.0 million due in 2021. In the case of default, we hold the assumption of liability for drawings on Wyoming Electric’s Letter of Credit attached to these bonds.

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.

Solid Waste Disposal

Various materials used at our facilities are subject to disposal regulations. Our Osage plant, permanently retired on March 21, 2014, had an on-site ash impoundment that was near capacity. An application to close the impoundment was approved on April 13, 2012. Site closure work was completed in 2013 with the state providing closure certification in 2014. Post closure monitoring activities will continue for 30 years following the closure certification date.

In September 2013, Osage also received a permit to close the small industrial rubble landfill. Site work was completed with the state providing closure certification in 2014. Post closure monitoring will continue for 30 years following the closure certification date.

Our W.N. Clark plant, which has been retired, previously delivered coal ash to a permitted, privately-owned landfill. While we do not believe that any substances from our solid waste disposal activities will pollute underground water, we can provide no assurance that pollution will not occur over time. In this event, we could incur material costs to mitigate any resulting damages.

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 its land lease for Busch Ranch, Colorado Electric is required to reclaim all land where it has placed wind turbines. The reclamation liability is 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 coal reserves. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.

See Note 8 for additional information.

Manufactured Gas Processing

As a result of the Aquila Transaction, we acquired whole and partial liabilities for several 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 $1.5 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 $1.0 million regulatory asset for manufactured gas processing sites; see Note 1. 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.


As of December 31, 2017, our estimated liabilities for Iowa’s MGP sites currently range from approximately $2.6 million to $6.1 million for which2021, we had $2.6a $1.1 million accrued for remediationvaluation allowance against the state NOL carryforwards. Our 2021 analysis of sites asthe ability to utilize such NOLs resulted in 0 increase in the valuation allowance. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of December 31, 2017the NOLs, the offsetting amount will affect tax expense.

110
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 our Consolidated Balance Sheets.

For additional information on environmental matters, see Item 1 in this Annual Report on Form 10-K.

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.

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.

(20)    GUARANTEES

We have entered into various agreements providing financial or performance assurance to third parties on behalf of certain of our subsidiaries. The agreements include indemnification for reclamation and surety bonds and a contract performance guarantee.

We had the following guarantees in place as of (in thousands):
 Maximum Exposure at 
Nature of GuaranteeDecember 31, 2017Expiration
Indemnification for subsidiary reclamation/surety bonds (a)
$58,221
Ongoing
 $58,221
 
_______________________
(a)We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets.




(21)    DISCONTINUED OPERATIONS

Results of operations for discontinued operations have been classified as Income from discontinued operations, net of income taxes in the accompanying Consolidated Statements of Income. Current assets, noncurrent assets, current liabilities and non-current liabilities of the discontinued operations have been reclassified and reflected on the accompanying Consolidated Balance Sheets as “Current assets held for sale,” “Noncurrent assets held for sale,” “Current liabilities held for sale,” and “Noncurrent liabilities held for sale”, respectively. Prior periods relating to our discontinued operations have also been reclassified to reflect consistency within our consolidated financial statements.

Oil and Gas Segment

On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. As of February 23, 2018, we have either closed transactions or signed contracts to sell more than 90% of our oil and gas properties. We have executed agreements to sell all our operated properties and have only non-operated assets left to divest. We plan to conclude the sale of all of our remaining assets by mid-year 2018.

We are in the process of divesting our Oil and Gas segment; therefore, we performed a fair value assessment of the assets and liabilities classified as held for sale. We evaluated our disposal groups classified as held for sale based on the lower of carrying value or fair value less cost to sell. The market approach was based on our recent fourth quarter 2017 sale of our Powder River Basin assets and pending sale transactions of our other properties.

There is risk involved when determining the fair value of assets, as there may be unforeseen events and changes in circumstances and market conditions that have a material impact on the estimated amount and timing of future cash flows. In addition, the fair value of the assets and liabilities could be different using different estimates and assumptions in the valuation techniques used. We believe that the estimates used in calculating the fair value of our assets and liabilities held for sale are reasonable based on the information that was known when the estimates were made.

At December 31, 2017, the fair value of our held for sale assets was less than our carrying value, which required an after-tax write down of $13 million. There were no adjustments made to the fair value of our held for sale liabilities.

Total assets and liabilities of BHEP at December 31, 2017 have been classified as Current assets held for sale and Current liabilities held for sale on the accompanying Consolidated Balance Sheets due to the expected final disposals occurring by mid-year 2018. Held for sale assets and liabilities at December 31, 2016 are classified as current and non-current.
 As of
(in thousands)December 31, 2017December 31, 2016
Other current assets$10,360
$11,401
Derivative assets, current and noncurrent—
153
Deferred income tax assets, noncurrent, net

16,966
26,329
Property, plant and equipment, net56,916
82,812
Other current liabilities(18,966)(9,834)
Derivative liabilities, current and noncurrent—
(1,586)
Other noncurrent liabilities(22,808)(22,803)
Net assets$42,468
$86,472

At December 31, 2017 and 2016, the Oil and Gas segment’s net deferred tax assets were primarily comprised of basis differences on oil and gas properties.

BHEP’s accrued liabilities at December 31, 2017 and 2016 consisted primarily of accrued royalties, payroll and property taxes. Other liabilities at December 31, 2017 and 2016 consisted primarily of ARO obligations relating to plugging and abandonment of oil and gas wells.

Operating results of the Oil and Gas segment included in Discontinued operations on the accompanying Consolidated Statements of Income were as follows (in thousands):
Changes in Uncertain Tax Positions:202120202019
Beginning balance$8,383 $4,165 $3,583 
Additions for prior year tax positions448 3,788 446 
Reductions for prior year tax positions(732)(1,313)(862)
Additions for current year tax positions2,455 1,743 998 
Ending balance$10,554 $8,383 $4,165 



The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $5.1 million.

 For the Years Ended
 December 31, 2017December 31, 2016December 31, 2015
    
Revenue$25,382
$34,058
$43,283
    
Operations and maintenance22,872
27,187
35,461
Depreciation, depletion and amortization7,521
13,510
28,838
Impairment of long-lived assets20,385
106,957
249,608
Total operating expenses50,778
147,654
313,907
    
Operating (loss)(25,396)(113,596)(270,624)
    
Interest income (expense), net181
698
931
Other income (expense), net(297)110
(378)
Impairment of equity investments—
—
(4,405)
Income tax benefit (expense)8,413
48,626
100,817
    
(Loss) from discontinued operations$(17,099)$(64,162)$(173,659)

Full Cost Accounting

Historically, we used the full cost method of accounting for oil and gas production activities. Under the full cost method, costs related to acquisition, exploration and estimated future expenditures to be incurred in developing proved reserves as well as estimated reclamation and abandonment costs, net of estimated salvage values are capitalized. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonment of properties, are typically treated as adjustments to the cost of the properties withWe recognized no gain or loss recognized.

Costs directlyinterest expense associated with unproved properties and major development projects, if any, are excluded from the costs to be amortized. These excluded costs are subsequently included within the costs to be amortized when it is determined whether or not proved reserves can be assigned to the properties. The properties excluded from the costs to be amortized are assessed for impairment at least annually and any amount of impairment is added to the costs to be amortized.

Under the full cost method, net capitalized costs, less accumulated amortization and related deferred income taxes are subject to a ceiling test which limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC, plus the lower of cost or market value of unevaluated properties. Future net cash flows are estimated based on SEC-defined end-of-period commodity prices adjusted for contracted price changes and held constant for the life of the reserves. An average price is calculated using the price at the first day of each month for each of the preceding 12 months. If the net capitalized costs exceed the full cost “ceiling” at period end, a permanent non-cash write-down would be charged to earnings in that period.

Impairment of long-lived assets

As discussed above, at December 31, 2017, the fair value of our held for sale assets was less than our carrying value, which required a write down of $20 million. There were no adjustments made to the fair value of our held for sale liabilities.

As a result of continued low commodity prices throughout 2016, we recorded non-cash ceiling test impairments of oil and gas assets totaling approximately $92 million for the year ended December 31, 2016. In determining the ceiling value of our assets, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. For natural gas, the average NYMEX price was $2.48 per Mcf, adjusted to $2.25 per Mcf at the wellhead; for crude oil, the average NYMEX price was $42.75 per barrel, adjusted to $37.35 per barrel at the wellhead.

In 2015, we recorded a non-cash ceiling test impairment of oil and gas assets totaling approximately $250 million for the year ended December 31, 2015. In determining the ceiling value of our assets, we utilized the average of the quoted prices from the


first day of each month from the previous 12 months. For natural gas, the average NYMEX price was $2.59 per Mcf, adjusted to $1.27 per Mcf at the wellhead; for crude oil, the average NYMEX price was $50.28 per barrel, adjusted to $44.72 per barrel at the wellhead.

During the second quarter of 2016, certain non-core assets were identified that were not suitable for inclusion in a possible Cost of Service Gas Program. We assessed these assets for impairment in accordance with ASC 360. We valued the assets applying a market method approach utilizing assumptions consistent with similar known and measurable transactions and determined that the carrying amount exceeded the fair value. As a result, we recorded a pre-tax impairment of depreciable properties at June 30, 2016 of $14 million, in addition to the ceiling test impairments noted above.

Equity investments in unconsolidated subsidiaries

BHEP owned a 25% interest in a pipeline and gathering system, accounted for under the equity method of accounting. During the second quarter of 2015, due to sustained low commodity prices, recurring operating losses and future expectations we reviewed this investment interest for impairment utilizing the other-than-temporary impairment model under ASC 820, Fair Value Measurements. We valued the investment applying a market method approach utilizing assumptions consistent with similar known and measurable transactions. The carrying amount of this equity method investment exceeded the fair value, and we concluded the decline was considered to be other than temporary. As a result, we recorded a pre-tax impairment loss in 2015 of $4.4 million, the difference between the carrying amount and the fair value of the investment. In December of 2015, we sold our 25% interest in this pipeline and gathering system.

(22)    OIL AND GAS RESERVES(Unaudited)

On November 1, 2017, we initiated the process of divesting all Oil and Gas segment assets in order to fully exit the oil and gas business. On November 1, 2017, we stopped the use of the full-cost method of accounting for our oil and gas business. The assets and liabilities have been classified as held for sale and the results of operations are included in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. As a result, our oil and gas reserves are no longer considered significant. For more information, see Note 21.

Costs Incurred

Following is a summary of costs incurred in oil and gas property acquisition, exploration and development during the years ended December 31 (in thousands):
 20162015
Acquisition of properties:  
Proved$—
$1,407
Unproved910
669
Exploration costs1,102
35,434
Development costs4,657
128,998
Asset retirement obligations incurred—
566
Total costs incurred$6,669
$167,074

Reserves

The following table summarizes BHEP’s quantities of proved developed and undeveloped oil, natural gas and NGL reserves, estimated using SEC-defined product prices, as of December 31, 2016 and 2015 and a reconciliation of the changes between these dates. The summary information presented for our estimated proved developed and undeveloped crude oil, natural gas, and NGL reserves and the 10% discounted present value of estimated future net revenues is based on reports prepared by Cawley Gillespie & Associates (CG&A), an independent consulting and engineering firm located in Fort Worth, Texas. CG&A is a Texas Registered Engineering Firm. Our primary contact at CG&A is Mr. Zane Meekins. Mr. Meekins has been practicing consulting petroleum engineering since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas, a member of the Society of Petroleum Evaluation Engineers (SPEE), and has over 30 years of practical experience in petroleum engineering and over 28 years of experience in the estimation and evaluation of reserves. Reserves were determined consistent with SEC requirements using a 12-month average product price calculated using the first-day-of-the-month price for each of the 12 months in the reporting period held constant for the life of the properties. Reserves for crude oil, natural gas, and NGLs


are reported separately and then combined for a total MMcfe (where oil and NGLs in Mbbl are converted to an MMcfe basis by multiplying Mbbl by six). Such reserve estimates were inherently imprecise and may be subject to revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.

Minor differences in amounts may result in the following tables relating to oil and gas reserves due to rounding.
 2016 2015 
 OilGasNGL OilGasNGL 
 (in Mbbls of oil and NGL, and MMcf of gas)
Proved developed and undeveloped reserves:        
Balance at beginning of year3,450
73,412
1,752
 4,276
65,440
1,720
 
Production (a)
(319)(9,430)(133) (371)(10,058)(102) 
Sales(570)(1,291)(17) (11)(828)—
 
Additions - extensions and discoveries3
52
—
 199
24,462
232
 
Revisions to previous estimates(322)(8,173)110
 (643)(5,604)(98) 
Balance at end of year2,242
54,570
1,712
 3,450
73,412
1,752
 
         
Proved developed reserves at end of year included above2,242
54,570
1,712
 3,436
73,390
1,752
 
         
Proved undeveloped reserves at the end of year included in above—
—
—
 14
22
—
 
         
NYMEX prices$42.75
$2.48
$—
(b) 
$50.28
$2.59
$—
(b) 
         
Well-head reserve prices(c)
$37.35
$2.25
$11.92
 $44.72
$1.27
$18.96
 
________________________
(a)Production for reserve calculations did not include volumes for natural gas liquids (NGLs) for historical periods.
(b)A specific NYMEX price for NGL was not available. Market prices for NGL are broken down by various liquid components, including ethane, propane, isobutane, normal butane, and natural gasoline. Each of these components is traded as an index. Ethane was not being recovered at any of the facilities that process our natural gas production.
(c)For reserves purposes, costs to gather gas previously netted from the gas price were reclassified into operating expenses in 2016, with approximate rates of $1.54/Mcf for Piceance, $0.92/Mcf for San Juan and $0.53/Mcf for all others. The sales price for natural gas was adjusted for transportation costs and other related deductions when applicable.

Capitalized Costs

Following is information concerning capitalized costs for the years ended December 31, 2021, December 31, 2020 and December 31, 2019. We had no accrued interest (before tax effect) associated with income taxes at December 31, 2021 and December 31, 2020.

The Company is subject to federal income tax as well as income tax in various state and local jurisdictions. Black Hills Gas, Inc. and subsidiaries, which filed a separate consolidated tax return from BHC and subsidiaries through March 31, 2018, is under examination by the IRS for 2014. BHC is no longer subject to examination for tax years prior to 2017.

As of December 31, 2021, 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, 2022.

State tax credits have been generated and are available to offset future state income taxes. At December 31, 2021, we had the following state tax credit carryforwards (in thousands):
State Tax Credit CarryforwardsAmountsExpiration Year
ITC$23,060 2023to2041
Research and development$282 No expiration
 20162015
Unproved oil and gas properties$18,547
$47,254
Proved oil and gas properties1,043,558
1,008,466
Gross capitalized costs1,062,105
1,055,720
   
Accumulated depreciation, depletion and amortization and valuation allowances(1,000,091)(888,775)
Net capitalized costs$62,014
$166,945




Results of Operations

For more on oil and gas producing activities included in discontinued operations, see Note 21. Following is a summary of results of operations for producing activities for the years ended December 31 (in thousands):
 20162015
Revenue$34,058
$43,283
   
Production costs17,231
19,762
Depreciation, depletion and amortization12,574
28,062
Impairment of long-lived assets106,957
249,608
Total costs136,762
297,432
Results of operations from producing activities before tax(102,704)(254,149)
   
Income tax benefit (expense)37,916
93,743
Results of operations from producing activities (excluding general and administrative costs and interest costs)$(64,788)$(160,406)

Unproved Properties

Unproved properties not subject to amortization at December 31, 2016 and 2015 consisted mainly of exploration costs on various existing work-in-progress projects as well as leasehold acquired through significant natural gas and oil property acquisitions and through direct purchases of leasehold. We capitalized approximately $0.9 million and $1.0 million of interest during 2016 and 2015, respectively, on significant investments in unproved properties that were not yet included in the amortization base of the full-cost pool.
The table below sets forth the cost of unproved properties excluded from the amortization base asAs of December 31, 2016 and notes2021, we had a $13.6 million valuation allowance against the year in which the associated costs were incurred (in thousands):

 20162015PriorTotal
Leasehold acquisition cost$963
$—
$—
$963
Exploration cost532
441
—
973
Capitalized interest50
23
—
73
Total$1,545
$464
$—
$2,009

Standardized Measure of Discounted Future Net Cash Flows

Following is a summarystate ITC carryforwards. Our 2021 analysis of the standardized measure of discounted future net cash flows and changes relatingability to proved oil and gas reserves for the years ended December 31 (in thousands):
 20162015
Future cash inflows$246,221
$295,173
Future production costs(166,248)(146,552)
Future development costs, including plugging and abandonment(18,333)(24,833)
Future net cash flows61,640
123,788
10% annual discount for estimated timing of cash flows(26,574)(44,760)
Standardized measure of discounted future net cash flows$35,066
$79,028



The following are the principal sources of changeutilize such ITC resulted in a $0.8 million increase in the standardized measurevaluation allowance, which resulted in an increase to tax expense of discounted$0.8 million. The valuation allowance adjustment was primarily attributable to changes in forecasted future net cash flows duringstate taxable income.


(16)    BUSINESS SEGMENT INFORMATION

Our chief operating decision maker (CODM) reviews financial information presented on an operating segment basis for purposes of making decisions and assessing financial performance. Our CODM assesses the years ended December 31 (in thousands):performance of our operating segments based on operating income.

 20162015
Standardized measure - beginning of year$79,028
$183,022
Sales and transfers of oil and gas produced, net of production costs(4,314)(29,948)
Net changes in prices and production costs(32,698)(127,199)
Extensions, discoveries and improved recovery, less related costs—
15,718
Changes in future development costs1,825
(7,387)
Development costs incurred during the period—
27,211
Revisions of previous quantity estimates(7,477)(6,941)
Accretion of discount7,903
18,870
Net change in income taxes—
5,682
Sales of reserves(9,201)—
Standardized measure - end of year$35,066
$79,028

Changes inIn the standardized measure from “revisions of previous quantity estimates” were driven by reserve revisions, modifications of production profiles and timing of future development. For all years presented,prior year, we had minimal net reserve revisions to prior estimates due to performance. Production forecast modifications were generally made at the well level each year through the reserve review process. These production profile modifications were based on incorporation of the most recent production informationreported four operating segments: Electric Utilities, Gas Utilities, Power Generation and applicable technical studies. Timing of future development investments were reviewed each year and were often modified in response to current market conditions for items such as permitting and service availability.




(23)    QUARTERLY HISTORICAL DATA(Unaudited)

The Company operates on a calendar year basis. The following tables set forth select unaudited historical operating results and market data for each quarter of 2017 and 2016.
 First QuarterSecond Quarter
Third
Quarter
Fourth Quarter
 (in thousands, except per share amounts, dividends and common stock prices)
2017    
Revenue$547,528
$341,829
$335,611
$455,298
Operating income (loss)
$150,186
$69,796
$79,559
$117,195
Income (loss) from continuing operations$81,715
$25,927
$32,898
$67,835
Income (loss) from discontinued operations$(1,569)$(616)$(1,300)$(13,614)
Net income attributable to noncontrolling interest$(3,623)$(3,116)$(3,935)$(3,568)
Net income (loss) available for common stock$76,523
$22,195
$27,663
$50,653
     
Amounts attributable to common shareholders:    
Net income (loss) from continuing operations$78,092
$22,811
$28,963
$64,267
Net income (loss) from discontinued operations$(1,569)$(616)$(1,300)$(13,614)
Net income (loss) available for common stock$76,523
$22,195
$27,663
$50,653
     
Income (loss) per share for continuing operations - Basic$1.47
$0.43
$0.54
$1.21
Income (loss) per share for discontinued operations - Basic$(0.03)$(0.01)$(0.02)$(0.26)
Earnings (loss) per share - Basic$1.44
$0.42
$0.52
$0.95
     
Income (loss) per share for continuing operations - Diluted$1.42
$0.41
$0.52
$1.17
Income (loss) per share for discontinued operations - Diluted$(0.03)$(0.01)$(0.02)$(0.25)
Earnings (loss) per share - Diluted1.39
0.40
0.50
0.92
     
Dividends paid per share$0.445
$0.445
$0.445
$0.475
     
Common stock prices - High$67.02
$72.02
$71.01
$69.79
Common stock prices - Low$60.02
$65.37
$67.08
$57.01

Income from continuing operations for each quarter of 2017 included external incremental acquisition and transaction costs. We incurred after-tax external incremental acquisition and transaction expenses of $0.9 million during the first quarter, $0.3 million during the second quarter, $0.2 million during the third quarter and $1.3 million during the fourth quarter.

Included within the Income (loss) from continuing operations inMining. In the fourth quarter of 2017 is a net tax benefit2021, we changed our operating segments to align with the revised manner in which our CODM reviews our financial performance and allocates resources. Our power generation and mining businesses, which were previously presented as separate operating segments, are now part of $7.6 millionour Electric Utilities segment. This change aligns with our vertically integrated business model for our Electric Utilities. Comparative periods presented reflect this change.

Our operating segments are equivalent to our reportable segments.

Segment information was as follows (in thousands):
Total Assets (net of intercompany eliminations) as of December 31,20212020
Electric Utilities$3,796,662 $3,602,233 
Gas Utilities5,246,370 4,376,204 
Corporate and Other88,864 110,349 
Total assets$9,131,896 $8,088,786 
111
Capital Expenditures (a) for the years ended December 31,
202120202019
Electric Utilities$285,770 $288,683 $316,687 
Gas Utilities383,320 449,209 512,366 
Corporate and Other10,500 17,500 20,702 
Total capital expenditures$679,590 $755,392 $849,755 
____________________
(a)    Includes accruals for property, plant and equipment as disclosed in the Supplemental Cash Flow Information to the Consolidated Statement of Cash Flows.

Consolidating Income Statement
Year ended December 31, 2021Electric UtilitiesGas UtilitiesCorporateInter-Company EliminationsTotal
Revenue -
Contracts with customers$825,404 $1,105,430 $— $— $1,930,834 
Other revenues5,336 12,932 — — 18,268 
830,740 1,118,362 — — 1,949,102 
Inter-company operating revenue -
Contracts with customers11,518 6,110 196 (17,824)— 
Other revenues— 393 356,151 (356,544)— 
11,518 6,503 356,347 (374,368)— 
Total revenue842,258 1,124,865 356,347 (374,368)1,949,102 
Fuel, purchased power and cost of natural gas sold248,018 494,738 96 (918)741,934 
Operations and maintenance, including taxes260,036 314,810 293,265 (306,325)561,786 
Depreciation, depletion and amortization131,528 104,160 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), net1,404 
Income tax benefit (expense)(7,169)
Net income251,260 
Net income attributable to non-controlling interest(14,516)
Net income available for common stock$236,744 

112
Consolidating Income Statement
Year ended December 31, 2020Electric UtilitiesGas UtilitiesCorporateInter-Company EliminationsTotal
Revenue -
Contracts with customers$721,108 $959,696 $— $— $1,680,804 
Other revenues6,175 9,962 — $— 16,137 
727,283 969,658 — — 1,696,941 
Inter-company operating revenue -
Contracts with customers11,574 4,724 167 (16,465)— 
Other revenues— 288 352,976 (353,264)— 
11,574 5,012 353,143 (369,729)— 
Total revenue738,857 974,670 353,143 (369,729)1,696,941 
Fuel, purchased power and cost of natural gas sold138,572 354,645 83 (896)492,404 
Operations and maintenance, including taxes265,679 303,577 284,501 (301,980)551,777 
Depreciation, depletion and amortization123,632 100,559 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 income242,763 
Net income attributable to non-controlling interest(15,155)
Net income available for common stock$227,608 

Consolidating Income Statement
Year ended December 31, 2019Electric UtilitiesGas UtilitiesCorporateInter-Company EliminationsTotal
Revenue -
Contracts with customers$719,205 $1,007,187 $— $— $1,726,392 
Other revenues8,124 384 — — 8,508 
727,329 1,007,571 — — 1,734,900 
Inter-company operating revenue -
Contracts with customers12,026 2,459 230 (14,715)— 
Other revenues— — 343,974 (343,974)— 
12,026 2,459 344,204 (358,689)— 
Total revenue739,355 1,010,030 344,204 (358,689)1,734,900 
Fuel, purchased power and cost of natural gas sold145,972 425,898 269 (1,310)570,829 
Operations and maintenance, including taxes259,167 301,844 286,800 (298,902)548,909 
Depreciation, depletion and amortization116,539 92,317 22,065 (21,801)209,120 
Operating income (loss)217,677 189,971 35,070 (36,676)406,042 
Interest expense, net(137,659)
Impairment of investment(19,741)
Other income (expense), net(5,740)
Income tax benefit (expense)(29,580)
Net income213,322 
Net income attributable to non-controlling interest(14,012)
Net income available for common stock$199,310 

113

(17)    SUBSEQUENT EVENTS

Except as described below and in Note 3, there have been no events subsequent to December 31, 2021 which would require recognition in the consolidated financial statements or disclosures.

Winter Storm Uri

On January 27, 2022, Kansas Gas received approval from the impactKCC for their Winter Storm Uri cost recovery settlement with final rates to be implemented in 2022. See Note 2 for additional information.

Transmission Service Agreements

On January 1, 2022, Colorado Electric entered into a firm point-to-point transmission service agreement with Tri-State Generation and Transmission Association Inc. that provides a maximum of the TCJA, as well as58 MW of capacity and associated energy. This agreement expires December 31, 2024.

On January 1, 2022, South Dakota Electric entered into a tax benefitfirm point-to-point transmission service agreement with MEAN that provides a maximum of $4.1 million from a true-up to the filed 2016 SourceGas tax returns related to the SourceGas acquisition.20 MW of capacity and associated energy. This agreement expires December 31, 2023.


Included within the Loss from discontinued operations in the fourth quarter of 2017 is an after-tax non-cash impairment of oil and gas properties of $13.0 million.


ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE


 First QuarterSecond Quarter
Third
Quarter
Fourth
Quarter
 (in thousands, except per share amounts, dividends and common stock prices)
2016    
Revenue$441,584
$317,795
$324,147
$455,390
Operating income (loss)
$91,281
$63,725
$70,844
$110,330
Income (loss) from continuing operations$45,320
$21,128
$24,964
$55,381
Income (loss) from discontinued operations$(5,270)$(17,845)$(7,080)$(33,967)
Net income attributable to noncontrolling interest$(48)$(2,614)$(3,753)$(3,246)
Net income (loss) available for common stock$40,002
$669
$14,131
$18,168
     
Amounts attributable to common shareholders:    
Net income (loss) from continuing operations45,272
18,514
21,211
52,135
Net income (loss) from discontinued operations(5,270)(17,845)(7,080)(33,967)
Net income (loss) available for common stock40,002
669
14,131
18,168
     
Income (loss) per share for continuing operations - Basic$0.88
$0.36
$0.41
$0.98
Income (loss) per share for discontinued operations - Basic(0.10)(0.35)(0.14)(0.64)
Earnings (loss) per share - Basic$0.78
$0.01
$0.27
$0.34
     
Income (loss) per share for continuing operations - Diluted$0.87
$0.35
$0.39
$0.96
Income (loss) per share for discontinued operations - Diluted(0.10)(0.34)(0.13)(0.63)
Earnings (loss) per share - Diluted$0.77
$0.01
$0.26
$0.33
     
Dividends paid per share$0.420
$0.420
$0.420
$0.420
     
Common stock prices - High$61.13
$63.53
$64.58
$62.83
Common stock prices - Low$44.65
$56.16
$56.86
$54.76

Income from continuing operations for each quarter of 2016 included external incremental acquisition and transaction costs. We incurred after-tax external incremental acquisition and transaction expenses of $15 million during the first quarter, $4.1 million during the second quarter, $4.1 million during the third quarter and $5.5 million during the fourth quarter.

Included with loss from discontinued operations in each quarter of 2016 are non-cash impairments of oil and gas properties. We recorded after-tax impairments of oil and gas properties of $8.8 million during the first quarter, $16 million during the second quarter, $7.9 million during the third quarter and $34 million during the fourth quarter.

ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE


None.




ITEM 9A.CONTROLS AND PROCEDURES

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, 2017.2021. 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 Security Exchange Act, of 1934, as amended, is recorded, processed, summarized and reported, within the time periods specified in the Commission’sSEC’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, 2017,2021, there were no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934)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
Management’s Report on Internal Control over Financial Reporting is presented on Page 88 of this Annual Report on Form 10-K.

ITEM 9B.OTHER INFORMATION


None.





ITEM 9C.    DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

None.
114
PART III


ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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 20182022 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.


David R. Emery, age 55, has been Chairman and Chief Executive Officer since January 2016 and Chairman, President and Chief Executive Officer from 2005 through 2015. Prior to that, he held various positions with the Company, including President and Chief Executive Officer and member of the Board of Directors from 2004 to 2005, President and Chief Operating Officer — Retail Business Segment from 2003 to 2004 and Vice President — Fuel Resources from 1997 to 2003. Mr. Emery has 28 years of experience with the Company.

ITEM 11.EXECUTIVE COMPENSATION
Scott A. Buchholz, age 56, has been our Senior Vice President — Chief Information Officer since the closing of the Aquila Transaction in 2008. Prior to joining the Company, he was Aquila’s Vice President of Information Technology from 2005 until 2008, Six Sigma Deployment Leader/Black Belt from 2004 until 2005, and General Manager, Corporate Information Technology from 2002 until 2004. Mr. Buchholz has 37 years of experience with the Company, including 28 years with Aquila.

Linden R. Evans, age 55, has been President and Chief Operating Officer of the Company since January 2016 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 served as our Associate Counsel from 2001 to 2003. Mr. Evans has 16 years of experience with the Company.

Brian G. Iverson, age 55, has been Senior Vice President, General Counsel and Chief Compliance Officer since April 2016. He served as Senior Vice President - Regulatory and Governmental Affairs and Assistant General Counsel from 2014 to April 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 14 years of experience with the Company.

Richard W. Kinzley, age 52, has been Senior Vice President and Chief Financial Officer since January 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 18 years of experience with the Company.

Jennifer C. Landis, age 43, 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 16 years of experience with the Company.

ITEM 11.EXECUTIVE COMPENSATION

Information required under this item is set forth in the Proxy Statement for our 20182022 Annual Meeting of Shareholders, which is incorporated herein by reference.




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

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 20182022 Annual Meeting of Shareholders, which is incorporated herein by reference.


EQUITY COMPENSATION PLAN INFORMATION

The following table includes information as of December 31, 2017 with respect to our equity compensation plans. These plans include the 2005 Omnibus Incentive Plan and 2015 Omnibus Incentive Plan.ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Equity Compensation Plan Information
Plan categoryNumber of securities to be issued upon exercise of outstanding options, warrants and rightsWeighted-average exercise price of outstanding options, warrants and rightsNumber 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 holders240,190
(1) 
 $44.83
(1) 
979,464
(2) 
Equity compensation plans not approved by security holders—
  $—
 —
 
Total240,190
  $44.83
 979,464
 
_________________________
(1)
Includes 143,441 full value awards outstanding as of December 31, 2017, comprised of restricted stock units, performance shares, short-term incentive plan (STIP) units and Director common stock units. The weighted average exercise price does not include the restricted stock units, performance shares, STIP or common stock units. In addition, 267,284 shares of unvested restricted stock were outstanding as of December 31, 2017, which are not included in the above table because they have already been issued.
(2)Shares available for issuance are from the 2015 Omnibus Incentive Plan. The 2015 Omnibus Incentive Plan permits the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock based awards.

ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Information regarding certain relationships and related transactions and director independence is set forth in the Proxy Statement for our 20182022 Annual Meeting of Shareholders, which is incorporated herein by reference.


ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES

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 20182022 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

1.    Consolidated Financial Statements

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

2.    Schedules

All other schedules have been omitted because of the absence of the conditions under which they are required or because the required information is included in our consolidated financial statements and notes thereto. Consolidated valuation and qualifying accounts are detailed within Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

3.Exhibits

Exhibits filed herewithin are designated by an asterisk (*). All exhibits not so designated are incorporated by reference to a prior filing, as indicated. Items constituting a board of director or management compensatory plan are designated by a cross (†).

ITEM 15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)Exhibit Number1.Consolidated Financial Statements
Financial statements required under this item are included in Item 8 of Part II
2.Schedules
Schedule II — Consolidated Valuation and Qualifying Accounts for the years ended December 31, 2017, 2016 and 2015
3.Exhibits
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.


SCHEDULE II
BLACK HILLS CORPORATION
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2017, 2016 AND 2015
 
Description Balance at Beginning of Year 
Adjustments (a)
 Additions Charged to Costs and Expenses Recoveries and Other Additions Write-offs and Other Deductions Balance at End of Year
  (in thousands)
Allowance for doubtful accounts:          
2017 $2,392
 $—
 $4,926
 $8,262
 $(12,499) $3,081
2016 $1,741
 $2,158
 $2,704
 $4,915
 $(9,126) $2,392
2015 $1,516
 $—
 $3,860
 $4,132
 $(7,767) $1,741
__________________
(a)Represents allowance balances added with the SourceGas acquisition.



3.Exhibits

Description
Exhibit NumberDescription
2.1*2.1
115
Table of Contents
2.2*2.2
2.3*2.3
3.1*3.1
3.2*3.2
4.1*4.1
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).
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).
4.2*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
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*4.3
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*4.4


4.5*
Purchase Contract and Pledge Agreement dated as of November 23, 2015 between Black Hills Corporation and U.S. Bank National Association, as purchase contract agent, collateral agent, custodial agent and securities intermediary (filed as Exhibit 4.4 to the Registrant’s Form 8-K filed on November 23, 2015).
4.6*
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).
116
Table of Contents
4.5
10.1*†10.1†
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*†10.2†
10.3*†10.3†
10.3.1†
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).
10.4*†10.4†
10.4.1†
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).
10.5*†10.5†
10.6†
10.6.1†
First Amendment to the Omnibus Plan (filed as Exhibit 10.11 to the Registrant’s Form 10-K for 2008).
10.6.2†
Second Amendment to the Omnibus Plan (filed as Exhibit 10 to the Registrant’s Form 8-K filed on May 26, 2010).
10.6*10.7*†
10.7*†10.8†
10.9†
10.8*†10.10†
10.9*10.11*†
10.12†
10.10*†10.13†
10.14†
10.11*10.15*†
10.16*†
10.12*†10.17†
10.13*†10.18†


10.14*†10.19†
10.15*†10.20†
117
Table of Contents
10.20.1†
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).
10.20.2†
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).
10.20.3†
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).
10.20.4†
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).
10.16†10.20.5†
Fifth Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2018.2018 (filed as Exhibit 10.16 to the Registrant’s Form 10-K for 2017).
10.20.6†
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).
10.17*†10.21†
10.18*10.22
10.19*
Equity Distribution Sales Agreement dated August 4, 20172020 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, 2017)2020).
10.20*10.23
10.21*
Bond Purchase Agreement dated as of June 30, 2014 by and among Cheyenne Light Fuel and Power Company, New York Life Insurance Company, New York Life Insurance and Annuity Corporation, Teachers Insurance and Annuity Association of America, John Hancock Life Insurance Company (U.S.A.), John Hancock Life & Health Insurance Company, John Hancock Life Insurance Company of New York, Mutual of Omaha Insurance Company, United of Omaha Life Insurance Company and American Equity Investment Life Insurance Company (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on July 2, 2014).
10.22*
Third Amended and Restated Term Loan Credit Agreement, dated August 9, 2016 (relating to $340 million SourceGas Acquisition Credit Agreement - $0 balance at 12/31/2016) among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and J.P. Morgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.3 to the Registrant’s Form 8-K filed on August 10, 2016).
10.23*
SecondFourth Amended and Restated Credit Agreement dated August 9, 2016as 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 August 10, 2016)July 19, 2021). Amendment No. 1 to Second Amended and Restated
10.24
10.24*
Credit Agreement dated August 9, 2016 (relating to $500 million, three-year term loan - $300 million balance at 12/31/2017),February 24, 2021 among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and JPMorgan ChaseU.S. Bank N.A.,National Association, as Administrative Agent (filed as Exhibit 10.210.1 to the Registrant’s Form 8-K8–K filed on August 10, 2016). Amendment No. 1 to Credit Agreement dated as of December 7, 2016 (filed as Exhibit 10.25 to the Registrant’s Form 10-K for 2016)February 25, 2021).

10.25
10.25*10.26
10.27Coal Leases between WRDC and the Federal Government

     -Dated May 1, 1959 (filed as Exhibit 5(i) to the Registrant’s Form S‑7, File No. 2‑60755)

        -Modified January 22, 1990 (filed as Exhibit 10(h) to the Registrant’s Form 10‑K for 1989)

     -Dated April 1, 1961 (filed as Exhibit 5(j) to the Registrant’s Form S‑7, File No. 2‑60755)

        -Modified January 22, 1990 (filed as Exhibit 10(i) to Registrant’s Form 10‑K for 1989)

     -Dated October 1, 1965 (filed as Exhibit 5(k) to the Registrant’s Form S‑7, File No. 2‑60755)

        -Modified January 22, 1990 (filed as Exhibit 10(j) to the Registrant’s Form 10‑K for 1989).
10.28


10.26*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).
2121*
23.123.1*
23.231.1*
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.
31.231.2*
32.132.1*
32.232.2*
9595*
101.INS*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
101101.SCH*Financial Statements in XBRL FormatTaxonomy Extension Schema Document
101.CAL*XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*XBRL Taxonomy Extension Label Linkbase Document
________________________
118
Table of Contents
*101.PRE*Previously filed as part of the filing indicated and incorporated by reference herein.
XBRL Taxonomy Extension Presentation Linkbase Document
†104*Indicates a board of director or management compensatory plan.Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)




ITEM 16.FORM 10-K SUMMARY

ITEM 16.FORM 10-K SUMMARY

None.

119


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/ DAVIDLINDEN R. EMERYEVANS
DavidLinden R. Emery, ChairmanEvans, President and Chief Executive Officer
Dated:February 23, 201815, 2022


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. MILLSDirector andFebruary 15, 2022
Steven R. MillsChairman
/S/ DAVIDLINDEN R. EMERYEVANSDirector andFebruary 23, 201815, 2022
DavidLinden R. Emery, ChairmanEvans, PresidentPrincipal Executive Officer
and Chief Executive Officer
/S/ RICHARD W. KINZLEYPrincipal Financial andFebruary 23, 201815, 2022
Richard W. Kinzley, Senior Vice PresidentAccounting Officer
and Chief Financial Officer
/S/ MICHAEL H. MADISONBARRY M. GRANGERDirectorFebruary 23, 201815, 2022
Michael H. MadisonBarry M. Granger
/S/ LINDA K. MASSMANTONY A. JENSENDirectorFebruary 23, 201815, 2022
Linda K. MassmanTony A. Jensen
/S/ STEVEN R. MILLSKATHLEEN S. MCALLISTERDirectorFebruary 23, 201815, 2022
Steven R. MillsKathleen S. McAllister
/S/ ROBERT P. OTTODirectorFebruary 23, 201815, 2022
Robert P. Otto
/S/ SCOTT M. PROCHAZKADirectorFebruary 15, 2022
Scott M. Prochazka
/S/ REBECCA B. ROBERTSDirectorFebruary 23, 201815, 2022
Rebecca B. Roberts
/S/ MARK A. SCHOBERDirectorFebruary 23, 201815, 2022
Mark A. Schober
/S/ TERESA A. TAYLORDirectorFebruary 23, 201815, 2022
Teresa A. Taylor
/S/ JOHN B. VERINGDirectorFebruary 23, 201815, 2022
John B. Vering
/S/ THOMAS J. ZELLERDirectorFebruary 23, 2018
Thomas J. Zeller

177120