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BKH Black Hills

Filed: 14 Feb 20, 4:01pm
0001130464 us-gaap:InterestRateSwapMember us-gaap:AccumulatedNetGainLossFromDesignatedOrQualifyingCashFlowHedgesMember 2018-12-31

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC  20549
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
   
 For the fiscal year ended
December 31, 2019
 Or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
   
 For the transition period from ___________________ to __________________
   
 Commission File Number001-31303
BLACK HILLS CORPORATION
       
Incorporated inSouth Dakota IRS Identification Number46-0458824
       
7001 Mount Rushmore RoadRapid City South Dakota57702
       
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(s)Name of each exchange on which registered
Common stock of $1.00 par valueBKHNew York Stock Exchange
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
 Yes No 
       
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
 Yes No 
       
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
 Yes No 
       
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
 Yes No 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
 Large accelerated filer Accelerated filer 
       
 Non-accelerated filer Smaller reporting company 
       
    Emerging growth company 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
 Yes  No  
         
The aggregate market value of the voting common equity held by non-affiliates of the registrant on the last business day of the registrant’s
most recently completed second fiscal quarter, June 30, 2019, was$4,727,278,183 
         
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, 2020 
Common stock, $1.00 par value61,475,403
shares 

Documents Incorporated by Reference
Portions of the registrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2020 Annual Meeting of Stockholders to be held on April 28, 2020, are incorporated by reference in Part III of this Form 10-K.




TABLE OF CONTENTS


2


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
AOCIAccumulated Other Comprehensive Income (Loss)
Aquila TransactionOur July 14, 2008 acquisition of five utilities from Aquila, Inc.
APSCArkansas Public Service Commission
Arkansas GasBlack Hills Energy Arkansas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Arkansas (doing business as Black Hills Energy).
AROAsset Retirement Obligations
ASCAccounting Standards Codification
ASUAccounting Standards Update as issued by the FASB
ATMAt-the-market equity offering program
AvailabilityThe availability factor of a power plant is the percentage of the time that it is available to provide energy.
Basin ElectricBasin Electric Power Cooperative
BHCBlack Hills Corporation; the Company
BHSCBlack Hills Service Company, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills Colorado IPPBlack Hills Colorado IPP, LLC, a 50.1% owned subsidiary of Black Hills Electric Generation
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 ServicesBlack Hills Energy Services Company, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas commodity supply for the Choice Gas Programs (doing business as Black Hills Energy).
Black Hills Non-regulated HoldingsBlack Hills Non-regulated Holdings, 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
BLMUnited States Bureau of Land Management
BtuBritish thermal unit
Busch Ranch I29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and Black Hills Electric Generation. Colorado Electric and Black Hills Electric Generation each have a 50% ownership interest in the wind farm.
Busch Ranch II
60 MW wind farm near Pueblo, Colorado owned by Black Hills Electric Generation to provide wind energy to Colorado Electric through a power purchase agreement expiring in November 2044.

CAPPCustomer Appliance Protection Plan, which provides appliance repair services to residential natural gas customers through on-going monthly service agreements. The consolidation of the existing Service Guard and CAPP plans into the revamped Service Guard Comfort Plan is currently underway across our service territories.
CFTCUnited States Commodity Futures Trading Commission
Cheyenne Prairie132 MW natural-gas fired generating facility jointly owned by South Dakota Electric and Wyoming Electric in Cheyenne, Wyoming. Cheyenne Prairie was placed into commercial service on October 1, 2014.
Choice Gas ProgramRegulator approved programs in Wyoming and Nebraska that allow certain utility customers to select their natural gas commodity supplier, providing the unbundling of the commodity service from the distribution delivery service.
City of GilletteGillette, Wyoming
City of CheyenneCheyenne, Wyoming

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Colorado ElectricBlack Hills Colorado Electric, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing electric service to customers in Colorado (doing business as Black Hills Energy).
Colorado 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).
Common Use System (CUS)The Common Use System is a joint transmission system we participate in with Basin Electric and Powder River Energy Corporation. The Common Use System provides transmission service over these utilities' combined 230-kilovolt (kV) and limited 69-kV transmission facilities within areas of southwestern South Dakota and northeastern Wyoming.
Consolidated Indebtedness to Capitalization RatioAny Indebtedness outstanding at such time, divided by capital at such time. Capital being consolidated net-worth (excluding noncontrolling interest) plus consolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit Facility.
Cooling Degree Day (CDD)A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days.  Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another.  Normal degree days are based on the National Weather Service data for selected locations.
CorriedaleWind project near Cheyenne, Wyoming, that will be a 52.5 MW wind farm jointly owned by South Dakota Electric and Wyoming Electric and will serve as the dedicated wind energy supply to the Renewable Ready program.
CPCNCertificate of Public Convenience and Necessity
CPPClean Power Plan
CP ProgramCommercial Paper Program
CPUCColorado Public Utilities Commission
CTCombustion turbine
CTIIThe 40 MW Gillette CT, a simple-cycle, gas-fired combustion turbine owned by the City of Gillette.
Cushion 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
DCDirect current
Dividend payout ratioAnnual dividends paid on common stock divided by net income from continuing operations available for common stock
Dodd-FrankDodd-Frank Wall Street Reform and Consumer Protection Act
DSMDemand Side Management
DRSPPDividend Reinvestment and Stock Purchase Plan
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 measurement
ECAEnergy Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of fuel and purchased energy through to customers.
Economy EnergyPurchased energy that costs less than that produced with the utilities’ owned generation.
EIAEnvironmental Improvement Adjustment -- annual adjustment mechanism that allows us to recover from customers eligible investments in, and expense related to, new environmental measures.
EPAUnited States Environmental Protection Agency
Equity UnitEach 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. On November 1, 2018, we completed settlement of the stock purchase contracts that are components of the Equity Units issued in November 2015.
EWGExempt Wholesale Generator
FASBFinancial Accounting Standards Board

4


FDICFederal Deposit Insurance Corporation
FERCUnited States Federal Energy Regulatory Commission
FitchFitch Ratings Inc.
GAAPAccounting principles generally accepted in the United States of America
GCAGas Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of gas and certain services through to customers.
GHGGreenhouse gases
Global SettlementSettlement with a utilities commission where the revenue requirement is agreed upon, but the specific adjustments used by each party to arrive at the amount are not specified in public rate orders.
Happy JackHappy Jack Wind Farm, LLC, owned by Duke Energy Generation Services
Heating Degree Day (HDD)A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
HomeServeWe offer HomeServe products to our natural gas residential customers interested in purchasing additional home repair service plans.
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 producer
IRSUnited States Internal Revenue Service
ITCInvestment tax credit
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).
kVKilovolt
LIBORLondon Interbank Offered Rate
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.
MSHAMine Safety and Health Administration
MTPSCMontana Public Service Commission
MWMegawatts
MWhMegawatt-hours
N/ANot Applicable
NAVNet Asset Value
Nebraska GasBlack Hills Nebraska Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Nebraska (doing business as Black Hills Energy).
NERCNorth American Electric Reliability Corporation
NOx
Nitrogen oxide
NOLNet operating loss
NPSCNebraska Public Service Commission
NYSENew York Stock Exchange
OPEBOther Post-Employment Benefits
OSHAOccupational Safety & Health Administration
OSMUnited States Department of the Interior’s Office of Surface Mining

5


PacifiCorpPacifiCorp, a wholly owned subsidiary of MidAmerican Energy Holdings Company, itself an affiliate of Berkshire Hathaway.
PCAPower Cost Adjustment -- 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 -- annual adjustment that allows us to pass the prudently-incurred purchased capacity costs, incremental to costs included in base rates, through to customers.
Peak View60 MW wind generating project owned by Colorado Electric, placed in service on November 7, 2016 and adjacent to Busch Ranch I.
PPAPower Purchase Agreement
PRPAPlatte River Power Authority
PSAPower Sales Agreement
PSCoPublic Service Company of Colorado
Pueblo Airport Generation420 MW combined cycle gas-fired power generation plants jointly owned by Colorado Electric (220 MW) and Black Hills Colorado IPP (200 MW). Black Hills Colorado IPP owns and operates this facility. The plants commenced operation on January 1, 2012.
PTCProduction tax credit
PUHCA 2005Public Utility Holding Company Act of 2005
Revolving Credit FacilityOur $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which was amended and restated on July 30, 2018 and now terminates on July 30, 2023.
Renewable ReadyVoluntary renewable energy subscription program for large commercial, industrial and governmental agency customers. The Corriedale wind project will provide 52.5 MW of energy for Renewable Ready subscribers in Wyoming and western South Dakota.
RMNGRocky Mountain Natural Gas LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas transmission and wholesale services in western Colorado (doing business as Black Hills Energy).
RSNsRemarketable junior subordinated notes, issued on November 23, 2015 and retired on August 17, 2018.
SCADA
Supervisory control and data acquisition

SDPUCSouth Dakota Public Utilities Commission
SECUnited States Securities and Exchange Commission
Service GuardHome appliance repair product offering for both natural gas and electric residential customers through on-going monthly service agreements. The consolidation of the existing Service Guard and CAPP plans into the revamped Service Guard Comfort Plan is currently underway across our service territories.
Service Guard Comfort PlanNew plan that will consolidate Service Guard and CAPP and provide similar services.
Silver SageSilver Sage Windpower, LLC, owned by Duke Energy Generation Services
SO2
Sulfur dioxide
S&PStandard & Poor’s, a division of The McGraw-Hill Companies, Inc.
SPPSouthwest Power Pool, Inc. which oversees the bulk electric grid and wholesale power market in the central United States
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 ElectricBlack Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and Wyoming (doing business as Black Hills Energy).
SSIRSystem Safety and Integrity Rider
System Peak DemandRepresents the highest point of retail customer usage for a single hour.
TCATransmission Cost Adjustment -- annual adjustment mechanism that allows us to recover from customers eligible transmission investments prior to the next rate review.
TCJATax Cuts and Jobs Act enacted on December 22, 2017

6


Tech ServicesNon-regulated product lines within Black Hills Corporation 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-owner gas infrastructure facilities, typically through one-time contracts.
TFATransmission Facility Adjustment -- annual adjustment mechanism that allows us to recover charges for qualifying new and modified transmission facilities from customers.
VEBAVoluntary Employee Benefit Association
VIEVariable Interest Entity
WDEQWyoming Department of Environmental Quality
WECCWestern Electricity Coordinating Council
Wind Capacity FactorMeasures the amount of electricity a wind turbine produces in a given time period relative to its maximum potential
Working 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 (doing business as Black Hills Energy)
Wyoming ElectricCheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in the Cheyenne, Wyoming area (doing business as Black Hills Energy).
Wyoming GasBlack Hills Wyoming Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Wyoming (doing business as Black Hills Energy).

7


Website Access to Reports

The reports we file with the SEC are available free of charge at our website www.blackhillscorp.com as soon as reasonably practicable after they are filed. In addition, the charters of our Audit, Governance and Compensation Committees are located on our website along with our Code of Business Conduct, Code of Ethics for our Chief Executive Officer and Senior Finance Officers, Corporate Governance Guidelines of the Board of Directors and Policy for Director Independence. The information contained on our website is not part of this document.

Forward-Looking Information

This Form 10-K contains forward-looking statements as defined by the SEC. Forward-looking statements are all statements other than statements of historical fact, including, without limitation, those statements that are identified by the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts” and similar expressions and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 7 - Management’s Discussion & Analysis of Financial Condition and Results of Operations.

Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including, without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. Nonetheless, the Company’s expectations, beliefs or projections may not be achieved or accomplished.

Any forward-looking statement contained in this document speaks only as of the date on which the statement is made and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, 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 Form 10-K, including statements contained within Item 1A - Risk Factors.


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PART I

ITEMS 1 AND 2.BUSINESS AND PROPERTIES

History and Organization

Black Hills Corporation, a South Dakota corporation (together with its subsidiaries, referred to herein as the “Company,” “we,” “us” or “our”), is a customer-focused, growth-oriented utility company headquartered in Rapid City, South Dakota. Our predecessor company, Black Hills Power and Light Company, was incorporated and began providing electric utility service in 1941. It was formed through the purchase and combination of several existing electric utilities and related assets, some of which had served customers in the Black Hills region since 1883. In 1956, with the purchase of the WRDC mine, we began producing and selling energy through non-regulated businesses.

We operate our business in the United States, reporting our operating results through our regulated Electric Utilities, regulated Gas Utilities, Power Generation and Mining segments. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other.

Our Electric Utilities segment generates, transmits and distributes electricity to approximately 214,000 electric utility customers in Colorado, Montana, South Dakota and Wyoming. Our Electric Utilities own 939 MW of generation and 8,892 miles of electric transmission and distribution lines.

Our Gas Utilities segment serves approximately 1,066,000 natural gas utility customers in Arkansas, Colorado, Iowa, Kansas, Nebraska, and Wyoming. Our Gas Utilities own and operate approximately 4,775 miles of intrastate gas transmission pipelines and 41,210 miles of gas distribution mains and service lines, seven natural gas storage sites, nearly 49,000 horsepower of compression and over 500 miles of gathering lines.

Our Power Generation segment produces electric power from its wind, natural gas and coal-fired 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 and delivers it primarily under long-term contracts to adjacent mine-mouth electric generation facilities owned by our Electric Utilities and Power Generation businesses.

Electric Utilities Segment

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

Capacity and Demand. System peak demand for the Electric Utilities’ retail customers for each of the last three years are listed below:
 System Peak Demand (in MW)
 2019 2018 2017
 SummerWinter SummerWinter SummerWinter
Colorado Electric (a)
422297 413313 398299
South Dakota Electric335320
355314
370310
Wyoming Electric (b)
265247 254238 249230
________________________
(a)The Colorado Electric July 2019 summer peak load of 422 surpassed previous summer peak record load of 413 set in June 2018. The October 2018 winter peak load of 313 surpassed previous winter peak load of 310 set in February 2011.
(b)The Wyoming Electric July 2019 summer peak load of 265 surpassed previous summer peak record load of 254 set in July 2018. The December 2019 winter peak load of 247 surpassed the previous winter peak record load of 238 set in December 2018.


9


Regulated Power Plants. As of December 31, 2019, our Electric Utilities’ ownership interests in electric generating plants were as follows:
Unit
Fuel
Type
Location
Ownership
Interest %
Owned Capacity (MW)In Service Date
Colorado Electric:     
Busch Ranch I (a)
WindPueblo, Colorado50%14.52012
Peak View (b)
WindPueblo, Colorado100%60.02016
Pueblo Airport GenerationGasPueblo, Colorado100%180.02011
Pueblo Airport Generation CTGasPueblo, 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 Prairie (c)
GasCheyenne, Wyoming58%55.02014
Wygen III (d)
CoalGillette, Wyoming52%57.22010
Neil Simpson IICoalGillette, Wyoming100%90.01995
Wyodak Plant (e)
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 (c)
GasCheyenne, Wyoming42%40.02014
Cheyenne Prairie CT (c)
GasCheyenne, Wyoming100%37.02014
Wygen IICoalGillette, Wyoming100%95.02008
Total MW Capacity   939.1 
________________________
(a)Busch Ranch I is operated by Colorado Electric. In 2013, the facility was awarded a one-time cash grant in lieu of ITCs under the Section 1603 program created under the American Recovery and Reinvestment Act. Black Hills Electric Generation owns the remaining 50% interest in the wind farm. Colorado Electric has a PPA with Black Hills Electric Generation for its share of power from the wind farm.
(b)The Peak View 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. The PTCs for this facility flow back to customers through a rider mechanism as a reduction to Colorado Electric’s margins. Peak View was placed in service in November 2016.
(c)Cheyenne Prairie serves 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).
(d)Wygen III, a 110 MW mine-mouth coal-fired power plant, is operated by South Dakota Electric. South Dakota Electric owns 52% of the power plant, MDU owns 25% and the City of Gillette owns the remaining 23% interest. Our adjacent WRDC mine supplies all of the fuel for the plant.
(e)Wyodak Plant, 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 mine supplies all of the fuel for the plant.
    






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The Electric Utilities’ annual 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 was as follows:
Fuel Source (dollars per MWh)201920182017
Coal$11.46
$11.10
$10.95
    
Natural Gas$25.92
$33.42
$34.05
    
Diesel Oil (a)
$209.86
$329.27
$210.11
    
Total Weighted Average Fuel Cost$13.86
$13.53
$12.80
    
Purchased Power - Coal, Gas and Oil$43.73
$45.62
$45.63
    
Purchased Power - Renewable Sources$48.61
$54.31
$53.08
______________
(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’ power supply by resource as a percent of the total power supply for our energy needs for the years ended December 31 was as follows:
Power Supply201920182017
Coal30%32%32%
Gas, Oil and Wind12
10
8
Total Generated42
42
40
Purchased (a)
58
58
60
Total100%100%100%
______________
(a)Wind represents approximately 6%, 6% and 6% of our purchased power in 2019, 2018, and 2017, respectively.

Power Purchase and Power Sales Agreements. We have executed various PPAs to support our Electric Utilities’ capacity and energy needs beyond our regulated power plants’ generation. Our Electric Utilities also have various long-term PSAs. Key contracts are disclosed in Note 19 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Transmission and Distribution. Through our Electric Utilities, we own electric transmission and distribution systems composed of high voltage lines (greater than 69 kV) and low voltage lines (69 kV or less). We also jointly own an electric transmission system, referred to as the Common Use System, with Basin Electric and Powder River Energy Corporation.


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At December 31, 2019, our Electric Utilities owned the electric transmission and distribution lines shown below:
UtilityState
Transmission
(in Line Miles)
Distribution
(in Line Miles)
Colorado ElectricColorado598
3,120
South Dakota ElectricSouth Dakota, Wyoming1,219
2,557
South Dakota Electric - Jointly Owned (a)
South Dakota, Wyoming43

Wyoming ElectricWyoming49
1,306
  1,909
6,983
__________________________
(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 and eastern United States, respectively. 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. See Note 4 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

Material contracts are disclosed in Note 19 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K. Additional contracts disclosed below are also key to allowing us to serve our customer load:

Colorado Electric is party to a joint dispatch agreement with PSCo and PRPA.  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 dispatch of the lower-cost generation and decrease dispatch of the higher-cost generation.  This results 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.

South Dakota Electric 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.

Wyoming Electric has a firm network transmission agreement with Western Area Power Administration’s Loveland Area Project that allows us to serve our existing load in Cheyenne, Wyoming.

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 is charged for the use of assets located at the Gillette, Wyoming energy complex 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 BHSC are parties to a shared facilities agreement, whereby BHSC is charged for the use of the Horizon Point facility that is owned by South Dakota Electric and BHSC provides certain operations and maintenance services at the facility.

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

Jointly Owned Facilities agreements are discussed in Note 4 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.


12


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, demand is often greater in the summer and winter months for cooling and heating, respectively.

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 producers for the right to provide electric energy and capacity for Colorado Electric when resource plans require additional resources.

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. 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. 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
        
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
South Dakota ElectricWY9.9%8.13%46.7%/53.3%$46.810/2014ECA65%
 SDGlobal Settlement7.76%Global Settlement$543.910/2014ECA, Energy Efficiency Cost Recovery/DSM, TFA, EIA70%
 FERC10.8%8.76%43%/57%
$138.4 (a)
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
__________
(a)Includes $121.3 million in 2019 rate base for the Common Use System formula rate that is updated annually and $17.1 million in rate base for the DC 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. 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. 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.



13


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 Power
Colorado Electric þþþþþ
South Dakota Electric (SD)þþþþþþ
South Dakota Electric (WY) þþþ þ
South Dakota Electric (FERC)    þ 
Wyoming Electric þþþ þ

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

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

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, 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.

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

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

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

South Dakota Electric has:

An approved annual EIA tariff which recovers costs associated with generation plant environmental improvements. South Dakota Electric also has a TFA tariff which recovers the costs associated with transmission facility improvements. The EIA and TFA were suspended for a six-year moratorium period effective July 1, 2017. On January 7, 2020, South Dakota Electric received approval from the SDPUC on a settlement reached with the SDPUC staff agreeing to extend the 6-year moratorium period by an additional 3 years whereby rate increases for these recovery mechanisms will not go into effect prior to July 1, 2026. See Note 13 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for further information.

An annual cost adjustment clause which provides for the over or under recovery of fuel, transmission and purchased power cost incurred to serve South Dakota customers. Additionally, this 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 $1.0 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 $1.0 million. South Dakota Electric retains the remaining 30%. For the period of July 1, 2017 through March 31, 2023, the 100% credit of power marketing margin increased from $1.0 million to $2.0 million. 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 FERC Transmission Tariff based on a formulaic approach that determines the revenue component of South Dakota Electric’s open access transmission tariff.


14


Wyoming Electric has:

An annual cost adjustment mechanism that allows us to pass the prudently-incurred power costs above costs included in base rates 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.

Tariff Filings. See Note 13 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for tariff filings and additional information regarding current rate activity.


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

 For the year ended December 31,
Degree Days201920182017
 ActualVariance from NormalActualVariance from NormalActualVariance from Normal
Heating Degree Days:      
Colorado Electric5,453
(3)%5,119
4%4,693
(16)%
South Dakota Electric8,284
16%7,749
8%6,870
(4)%
Wyoming Electric7,406
1%7,036
(7)%6,623
(12)%
       
Combined (a)
6,813
5%6,405
3%5,826
(11)%
       
Cooling Degree Days:      
Colorado Electric1,226
37%1,420
58%1,027
14%
South Dakota Electric404
(36)%488
(23)%709
11%
Wyoming Electric462
33%430
24%429
23%
       
Combined (a)
791
14%902
29%798
14%
________________
(a)The combined degree days are calculated based on a weighted average of total customers by state.

  Electric Revenue (in thousands) Quantities Sold (MWh)
  For the year ended December 31, For the year ended December 31,
  201920182017 201920182017
Residential $216,108
$218,558
$210,172
 1,440,551
1,450,585
1,390,952
Commercial 246,704
250,894
258,754
 2,055,253
2,034,917
2,038,495
Industrial 131,831
124,668
122,958
 1,787,412
1,682,074
1,598,755
Municipal 17,206
17,871
18,144
 157,298
160,913
160,882
Subtotal Retail Revenue - Electric 611,849
611,991
610,028
 5,440,514
5,328,489
5,189,084
Contract Wholesale (a)
 19,078
33,688
30,435
 368,360
900,854
722,659
Off-system/Power Marketing Wholesale 25,622
24,800
21,111
 701,633
673,994
661,263
Other 56,203
40,972
43,076
 


Total Revenue and Energy Sold 712,752
711,451
704,650
 6,510,507
6,903,337
6,573,006
Other Uses, Losses or Generation, net (b)
 


 393,573
470,250
468,179
Total Revenue and Energy 712,752
711,451
704,650
 6,904,080
7,373,587
7,041,185
Less cost of fuel and purchased power (c)
 268,297
283,840
274,363
    
Gross Margin (non-GAAP) (c) (d)
 $444,455
$427,611
$430,287
    

15


  Electric Revenue (in thousands) 
Gross Margin (non-GAAP) (d)     (in thousands)
 Quantities Sold (MWh)
  For the year ended December 31, For the year ended December 31, For the year ended December 31,
  201920182017 201920182017 201920182017
Colorado Electric (c)
 $247,332
$251,218
$251,090
 $137,323
$138,901
$140,121
 2,180,985
2,151,918
2,091,676
South Dakota Electric (a)
 291,219
298,080
288,433
 218,104
205,194
200,795
 2,798,887
3,360,396
3,187,392
Wyoming Electric 174,201
162,153
165,127
 89,028
83,516
89,371
 1,924,208
1,861,273
1,762,117
Total Revenue, Gross Margin (non-GAAP), and Quantities Sold $712,752
$711,451
$704,650
 $444,455
$427,611
$430,287
 6,904,080
7,373,587
7,041,185
________________
(a)2019 revenue and purchased power, as well as associated quantities, for a certain wholesale contract have been presented on a net basis.  Prior year amounts were presented on a gross basis and, due to their immaterial nature, were not revised.  This 2019 presentation change has no impact on Gross margin.
(b)Total MWh includes Other Uses, Losses or Generation, net, which is approximately 5%, 6%, and 6% for Colorado Electric, South Dakota Electric and Wyoming Electric, respectively.
(c)
Due to the changes in our segment disclosures discussed in Note 5 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, cost of fuel and purchased power was revised for the years ended December 31, 2018 and December 31, 2017 which resulted in an increase of $6.7 million and $6.0 million, respectively. There were corresponding decreases to Gross margin for both years. These changes had no impact on consolidated financial results.
(d)
For further information on Gross Margin, see “Non-GAAP Financial Measure” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.

 For the year ended December 31,
Quantities Generated and Purchased (MWh)201920182017
    
Coal-fired2,226,028
2,368,506
2,230,617
Natural Gas and Oil600,002
446,373
307,815
Wind238,999
253,180
239,472
Total Generated3,065,029
3,068,059
2,777,904
Purchased (a)
3,839,051
4,305,528
4,263,281
Total Generated and Purchased6,904,080
7,373,587
7,041,185

 For the year ended December 31,
Quantities Generated and Purchased (MWh)201920182017
Generated:   
Colorado Electric443,770
481,446
397,965
South Dakota Electric1,768,456
1,734,222
1,581,915
Wyoming Electric852,803
852,391
798,024
Total Generated3,065,029
3,068,059
2,777,904
Purchased:


Colorado Electric1,737,215
1,670,472
1,693,711
South Dakota Electric (a)
1,030,431
1,626,174
1,605,477
Wyoming Electric1,071,405
1,008,882
964,093
Total Purchased3,839,051
4,305,528
4,263,281
 



Total Generated and Purchased6,904,080
7,373,587
7,041,185
________________
(a)2019 purchased power quantities for a wholesale contract have been presented on a net basis.  Prior year amounts were presented on a gross basis and, due to their immaterial nature, were not revised.  This 2019 presentation change has no impact on Gross margin.


16


 As of December 31,
Customers at End of Year201920182017
Residential183,232
181,459
179,911
Commercial29,921
29,299
29,354
Industrial83
84
86
Other1,024
1,030
914
Total Electric Customers at End of Year214,260
211,872
210,265

 As of December 31,
Customers at End of Year201920182017
Colorado Electric97,890
96,645
95,951
South Dakota Electric73,052
72,533
72,184
Wyoming Electric43,318
42,694
42,130
Total Electric Customers at End of Year214,260
211,872
210,265

Gas Utilities Segment

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 1,066,000 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 49,000 retail distribution customers under the Choice Gas Program in Nebraska and Wyoming. Additionally, we provide services under the Service Guard Comfort Plan and Tech Services and also offer HomeServe products.

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 storage assets in Arkansas, Colorado and Wyoming, 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, 2019:
 StateWorking Capacity (Mcf)Cushion Gas (Mcf)Total Capacity (Mcf)Maximum Daily Withdrawal Capability (Mcfd)
 
 Arkansas8,442,700
13,149,040
21,591,740
196,000
 Colorado2,360,895
6,165,315
8,526,210
30,000
 Wyoming5,733,900
17,145,600
22,879,500
36,000
 Total16,537,495
36,459,955
52,997,450
262,000



17


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, 2019
Arkansas942
4,880
1,161
Colorado693
6,814
2,554
Iowa165
2,813
2,138
Kansas330
2,910
1,355
Nebraska1,311
8,664
3,230
Wyoming1,334
3,472
1,219
Total4,775
29,553
11,657

 For the year ended December 31,
Degree Days2019 2018 2017
 Actual
Variance From
Normal
 ActualVariance From Normal ActualVariance From Normal
Heating Degree Days:        
Arkansas (a)
3,897
(4)% 4,169
3% 3,295
(19)%
Colorado6,672
1% 6,136
(7)% 5,728
(14)%
Iowa7,200
6% 7,192
6% 6,149
(9)%
Kansas (a)
5,190
6% 5,242
7% 4,452
(9)%
Nebraska6,578
7% 6,563
6% 5,554
(10)%
Wyoming8,010
7% 7,425
(1)% 7,123
(5)%
Combined (b)
6,840
5% 6,628
2% 5,862
(10)%
________________
(a)Arkansas and Kansas have weather normalization mechanisms that 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 due to its weather normalization mechanism. Arkansas Gas is partially excluded based on the weather normalization mechanism in effect from November through April.

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/or 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 are 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 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.

18



Our Gas Utilities are authorized to use natural gas cost recovery mechanisms that allow them to adjust their rates to reflect changes in the wholesale cost of natural gas and to ensure that they recover all the costs prudently incurred in purchasing gas for their customers.  In addition to natural gas cost recovery mechanisms, we have other recovery mechanisms, which vary by utility, but 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.  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 Tariffed Mechanisms
Gas Utilities:      
Arkansas GasAR9.61%
6.82% (a)
50.9%/49.1%
$451.5 (b)
10/2018GCA, Main Replacement Program, At-Risk Meter Relocation Program, Legislative or Regulatory Mandated Expenditures, Energy Efficiency, Weather Normalization Adjustment, Billing Determinant Adjustment
Colorado GasCO9.6%8.41%50%/50%$57.512/2012GCA, Energy Efficiency Cost Recovery/DSM
Colorado Gas Dist.CO10.0%8.02%49.52%/ 50.48%$127.112/2010
GCA, Energy Efficiency Cost Recovery/DSM

RMNGCO9.9%6.71%53.37%/ 46.63%$118.76/2018System Safety Integrity Rider, Liquids/Off-system/Market Center Services Revenue Sharing
Iowa GasIAGlobal SettlementGlobal SettlementGlobal Settlement$109.22/2011GCA, Energy Efficiency Cost Recovery, Capital Infrastructure Automatic Adjustment Mechanism, Farm Tap Tracker Adjustment, Gas Supply Optimization revenue sharing
Kansas GasKSGlobal SettlementGlobal SettlementGlobal Settlement$127.91/2015GCA, 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%$161.09/2010GCA, Cost of Bad Debt Collected through GCA, Infrastructure System Replacement Cost Recovery Surcharge, Farm Tap Recovery Mechanism
Nebraska Gas Dist.NE9.6%7.67%
48.84%/
51.16%
$87.6/ $69.8 (c)
6/2012Choice Gas Program, System Safety and Integrity Rider, Bad Debt expense recovered through Choice Supplier Fee
Wyoming GasWY9.4%6.9849.77%/50.23%$354.43/2020GCA, Energy Efficiency Cost Recovery, Rate Base Recovery on Acquisition Adjustment, Wyoming Integrity Rider, Choice Gas Program
__________
(a)Arkansas Gas return on rate base is adjusted to remove current liabilities from rate review capital structure for comparison with other subsidiaries.
(b)Arkansas Gas rate base is adjusted to include current liabilities for comparison with other subsidiaries.
(c)Total Nebraska Gas Distribution rate base of $87.6 million includes amounts allocated to serve non-jurisdictional customers. Jurisdictional Nebraska rate base totals $69.8 million and is used for calculation of jurisdictional base rates.


19


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
Energy EfficiencyIntegrity AdditionsBad DebtWeather NormalPension RecoveryGas CostBilling Determinant Adjustment
Arkansas Gasþþ þ þþ
Colorado Gasþ    þ 
Colorado Gas Distributionþ    þ 
RMNGN/AþN/AN/AN/AN/AN/A
Iowa Gasþþ   þ 
Kansas Gas þþþþþ 
Nebraska Gas þþ  þ 
Nebraska Gas Distribution þþ    
Wyoming Gas (a)
þþ   þ 
__________
(a)The Wyoming Gas integrity rider is effective March 1, 2020.

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

Operating Statistics

  Revenue (in thousands) 
Gross Margin (non-GAAP) (a) (in thousands)
 Quantities Sold and Transported (Dth)
  For the year ended December 31, For the year ended December 31, For the year ended December 31,
  201920182017 201920182017 201920182017
             
Residential $551,701
$567,785
$499,852
 $285,802
$276,858
$255,626
 66,956,080
65,352,164
54,645,598
Commercial 212,229
214,718
197,054
 88,264
82,529
78,249
 32,241,441
30,753,361
27,315,871
Industrial 24,832
26,466
24,454
 8,053
7,056
6,226
 6,548,023
6,309,211
5,855,053
Other (1,361)(7,899)8,647
 (1,361)(7,899)8,647
 


Total Distribution 787,401
801,070
730,007
 380,758
358,544
348,748
 105,745,544
102,414,736
87,816,522
             
Transportation and Transmission 144,710
141,854
135,824
 144,710
141,850
135,824
 153,101,264
148,299,003
141,600,080
             
Total Regulated 932,111
942,924
865,831
 525,468
500,394
484,572
 258,846,808
250,713,739
229,416,602
             
Non-regulated Services 77,919
82,383
81,799
 58,664
62,760
53,455
 


             
Total Revenue, Gross Margin (non-GAAP) and Quantities Sold $1,010,030
$1,025,307
$947,630
 $584,132
$563,154
$538,027
 258,846,808
250,713,739
229,416,602



20


  Revenue (in thousands) 
Gross Margin (non-GAAP) (a) (in thousands)
 Quantities Sold & Transported (Dth)
  For the year ended December 31, For the year ended December 31, For the year ended December 31,
  201920182017 201920182017 201920182017
             
Arkansas $185,201
$176,660
$153,691
 $115,899
$100,917
$94,007
 30,496,243
30,931,390
26,491,537
Colorado 199,369
188,002
180,852
 106,776
99,851
100,718
 33,908,529
29,857,063
28,436,744
Iowa 151,619
161,843
143,446
 70,290
68,384
66,619
 41,795,729
40,668,682
37,013,645
Kansas 105,906
112,306
105,576
 58,020
55,226
53,841
 32,650,854
31,387,672
28,251,947
Nebraska 255,622
278,969
252,631
 155,901
164,513
154,259
 81,481,192
81,658,938
73,890,509
Wyoming 112,313
107,527
111,434
 77,246
74,263
68,583
 38,514,261
36,209,994
35,332,220
Total Revenue, Gross Margin (non-GAAP) and Quantities Sold $1,010,030
$1,025,307
$947,630
 $584,132
$563,154
$538,027
 258,846,808
250,713,739
229,416,602
________________
(a)
For further information on Gross Margin, see “Non-GAAP Financial Measure” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.

 As of December 31,
Customers at End of Year201920182017
    
Residential831,351
821,624
806,744
Commercial82,912
82,498
86,461
Industrial2,208
2,221
2,214
Transportation/Other149,971
147,550
146,839
Total Customers at End of Year1,066,442
1,053,893
1,042,258


 As of December 31,
Customers at End of Year201920182017
    
Arkansas174,447
171,978
169,303
Colorado191,950
186,759
181,876
Iowa159,641
158,485
157,444
Kansas115,846
114,840
114,082
Nebraska293,576
291,723
290,264
Wyoming130,982
130,108
129,289
Total Customers at End of Year1,066,442
1,053,893
1,042,258


21



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, 2019, 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 have been and currently remain in compliance with these standards.

On November 26, 2019, Black Hills Electric Generation placed in service Busch Ranch II. Black Hills Electric Generation provides the wind energy generated from Busch Ranch II to Colorado Electric under a 25-year PPA, which expires in November 2044. This renewable energy will enable Colorado Electric to comply with Colorado's Renewable Energy Standard.

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 South Dakota Electric has 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 proactively integrate alternative and renewable energy into our utility energy supply while mitigating customer rate impacts. Mandatory portfolio standards have increased, and will likely continue to increase, the power supply costs of our Electric Utilities’ 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. BHC is a holding company whose assets consist primarily of investments in our subsidiaries, including subsidiaries that are public utilities and a holding company regulated by FERC under the 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 Utilities’ subsidiaries provide FERC-jurisdictional services subject to FERC’s oversight.

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Our Electric Utilities and Power Generation 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, each files Electric Quarterly Reports 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.

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 gives FERC authority with respect to the books and records of a utility holding company. As a utility holding company with a centralized service company subsidiary, BHSC, we are subject to FERC’s authority under PUHCA 2005.

Power Generation Segment

Our Power Generation segment, which operates through Black Hills Electric Generation and its subsidiaries, acquires, develops, constructs and operates our non-regulated power plants. As of December 31, 2019, we held varying interests in independent power plants with a total net ownership of approximately 423 MW.

We produce electric power from our generating plants and sell the electric capacity and energy, primarily to 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 majority of our non-regulated generating capacity under contracts having terms greater than one year.

As of December 31, 2019, the power plant ownership interests held by our Power Generation segment include:
Power PlantsFuel TypeLocation
Ownership
Interest
Owned Capacity (MW)In Service Date
Wygen I (a)
CoalGillette, Wyoming76.5%68.9
2003
Pueblo Airport GenerationGasPueblo, Colorado50.1%200.0
2012
Busch Ranch I (b)
WindPueblo, Colorado50.0%14.5
2012
Busch Ranch II (c) (e)
WindPueblo, Colorado100.0%60.0
2019
Top of Iowa (d) (e)
WindJoice, Iowa100.0%80.0
2019
    423.4
 
_________________________
(a)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%.
(b)On December 11, 2018, Black Hills Electric Generation purchased a 50% ownership interest in Busch Ranch I. This facility originally qualified under the Section 1603 program grant in lieu of ITCs.
(c)On November 26, 2019, Black Hills Electric Generation placed in service Busch Ranch II.
(d)On February 5, 2019, Black Hills Electric Generation purchased 80 MW of wind generating assets in Iowa. A third-party operates the facility and we sell the wind energy generated in the MISO market.
(e)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.

Power Sales Agreements. Our Power Generation facilities have various long-term power sales agreements. See Note 19 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for further information.

Third Party Noncontrolling Interest in Subsidiary. In 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million to a third party buyer. See Note 12 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.


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The following table summarizes MWh for our Power Generation segment:
 For the year ended December 31,
Quantities Sold, Generated and Purchased (MWh) (a)
201920182017
Sold   
Black Hills Colorado IPP935,997
1,000,577
943,618
Black Hills Wyoming(b)
629,788
582,938
645,810
Black Hills Electric Generation (c)
167,296
5,873

Total Sold1,733,081
1,589,388
1,589,428
    
Generated   
Black Hills Colorado IPP935,997
1,000,577
943,618
Black Hills Wyoming (b)
557,119
501,945
577,124
Black Hills Electric Generation (c)
167,296
5,873

Total Generated1,660,412
1,508,395
1,520,742
    
Purchased   
Black Hills Wyoming (b)
74,199
83,213
69,377
Total Purchased74,199
83,213
69,377
____________________
(a)Company use and losses are not included in the quantities sold, generated and purchased.
(b)
Under the 20-year economy energy PPA (discussed in Note 19 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K) with the City of Gillette, Black Hills Wyoming purchases energy on behalf of the City of Gillette and sells that energy to the City of Gillette. MWh sold may not equal MWh generated and purchased due to a dispatch agreement Black Hills Wyoming has with South Dakota Electric to cover energy imbalances.
(c)Black Hills Electric Generation amounts in this table are related to wind facilities held by our Power Generation segment. Change from 2018 to 2019 is driven by acquisition, and placing in service, of new wind assets.

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

Black Hills Wyoming’s economy energy PPA and other ancillary agreements are discussed in Note 19 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Operating and Maintenance Services Agreement

In conjunction with the sale of a noncontrolling interest in 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 became effective on 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. 


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Shared Services Agreements

South Dakota Electric, Wyoming Electric and Black Hills Wyoming are parties to a shared facilities agreement, whereby each entity is charged 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’s 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.

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

Jointly owned facilities agreements are discussed in Note 4 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

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, eligible power facilities and selling electric energy at wholesale. EWGs are subject to FERC regulation, including rate regulation. We own five EWGs: Wygen I, Pueblo Airport Generation, Busch Ranch I, Busch Ranch II and Top of Iowa. Our EWGs were 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.

Mining Segment

Our Mining segment operates through our WRDC subsidiary. We surface mine, process and sell low-sulfur sub-bituminous coal at our mine near Gillette, Wyoming. The WRDC mine, which we acquired in 1956 from Homestake Mining Company, is located in the Powder River Basin in eastern Wyoming. We produced approximately 3.7 million tons of coal in 2019.

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 reestablish 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, 2019 was 2.30 which increased from the prior year as we continued mining in areas with higher overburden. We expect our stripping ratio to be approximately 2.18 by the end of 2020 as we mine in areas with comparable overburden.


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Mining rights to the reserves are based on three federal leases and one state lease. The federal leases expire between March 31, 2021 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, 2019, we estimated our recoverable reserves to be approximately 185 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 50 years at the current production levels. Our recoverable reserve estimates are periodically updated to reflect past 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 reserves include reserves that can be economically and legally extracted at the time of their determination.

Substantially all of the mine’s production is currently sold under contracts to:

South Dakota Electric for use at the 90 MW Neil Simpson II plant to which we sell approximately 500,000 tons each year. This contract is for the life of the plant;

Wyoming Electric for use at the 95 MW Wygen II plant to which we sell approximately 550,000 tons each year. This contract is for the life of the plant;

The 362 MW Wyodak Plant owned 80% by PacifiCorp and 20% by South Dakota Electric. PacifiCorp is obligated to purchase a minimum of 1.5 million tons each year of the contract term, subject to adjustments for planned outages. South Dakota Electric is also obligated to purchase a minimum of 375,000 tons per year for its 20% share of the power plant, subject to adjustments for planned outages. This contract expires December 31, 2022 and negotiations are underway to extend the contract;

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 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 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 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 sales to a specified return on our mine’s cost-depreciated investment base. The return calculated annually is 400 basis points above Moody’s A-Rated Utility Bond Index 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 supply agreement described above. The agreement included a price adjustment in 2019. The price adjustment essentially allowed us to retain the full economic advantage of the mine’s location adjacent to the plant. The price adjustment was based on market price plus considerations for the avoided costs of rail transportation and an unloading facility, which PacifiCorp would have to incur if it purchased from another mine. In addition, the agreement also provided for the monthly escalation of price based on an escalation factor.

In October 2019, negotiations were completed for the price re-opener in the contract with Wyodak Plant. The new price was
reset at $17.94 per ton effective July 1, 2019, compared to the prior contract price of $18.25 per ton. The current contract price is comprised of three components: 1) avoided transportation costs (approximately 20% of current price); 2) avoided costs of an unloading facility (approximately 30% of current price); and 3) a rolling 12-month average of the Coal Daily spot market price of 8,400 Btu Powder River Basin coal (approximately 50% of current price).

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 Utility 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.


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Competition. Our strategy is to sell the majority of our production to on-site, mine-mouth 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. 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 plans that provide 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 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 $14 million for reclamation costs as of December 31, 2019. See additional information in Note 8 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Environmental Matters

Methane Rules (Greenhouse Gas Emissions). The EPA and the State of Colorado have implemented strict regulatory requirements on hydrocarbon and methane emissions associated with natural gas gathering and transmission systems. The BLM repealed similar hydrocarbon and methane emissions reductions it previously established under the Methane Rule (Venting and Flaring rule). Presently, we have four facilities in our Colorado natural gas transmission operations affected by the hydrocarbon and methane reduction rules.

Our operations are currently in compliance with both EPA and State of Colorado rules. Future modifications to our gathering and transmissions systems are anticipated to trigger EPA methane rules. We plan to develop a corporate-wide methane control strategy to address GHG emissions as we anticipate this will be a requirement in future rule-making efforts.

Water Issues. Our facilities are subject to a variety of state and federal regulations governing existing and potential water/ wastewater discharges and protection 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. In 2017, the EPA postponed the implementation of the rule and set a timeline in 2018 to revise the rule. To date, the rule is being reviewed by the Office of Management and Budget. This rule will have an impact on the Wyodak Plant. Until the EPA issues the rule for publication, we cannot quantify what the potential impact may be on the Wyodak Plant. The terms of this new regulation may impact the next permit renewal, which will be in 2020.

Short-term Emission Limits. The EPA 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 SO2, 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 exceedances if they are reported and corrected immediately 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. 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.


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Regional Haze (Impacts to the Wyodak 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 the Wyodak Plant, of which South Dakota Electric owns 20%. 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 investment would be necessary to bring the Wyodak Plant into compliance. South Dakota Electric’s 20% share of this capital investment for the facility would be approximately $27 million if PacifiCorp is required to install a Selective Catalytic Reactor for NOx control. The case is currently held in abeyance at the 10th circuit court as the parties work on a settlement. Basin Electric, who is part of the legal action, settled with the EPA. In lieu of going to court, PacifiCorp entered into mediation with the EPA and conservation groups. PacifiCorp submitted a “Request for Reconsideration” on October 24, 2019 to the EPA and provided a copy to the court. The purpose of the submittal is to revisit the emission impacts and cost of additional investment.

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 authorize 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. We are currently in discussions with the EPA, state regulators, and/or other third-parties to determine the ultimate resolution to these sites. As of December 31, 2019, our Gas Utilities have two active FMGP sites, which are located in Council Bluffs, Iowa, and McCook, Nebraska. For the Council Bluffs site, the delay in clean-up is due to identifying the Potential Responsible Parties (PRPs or Successors to the Operators) to pay for the clean-up. We are the landowner and not the Successors to the Operator, whom would be responsible for paying for the majority of clean-up.  We have been working with the EPA to identify the PRPs. The EPA has sent out information requests to the PRPs seeking transaction documents to determine the Successors to the Operators of the site who created the contamination. For the McCook, Nebraska site, we have been contacted by a third-party who intends to manage and pay for the clean-up at this site. The third-party is conducting site assessments and working with the State of Nebraska on a clean-up plan.

Affordable Clean Energy Rule. The EPA was directed to repeal, revise, and replace the Clean Power Plan rule. On August 31, 2018, the EPA published the proposed Affordable Clean Energy rule. This rule focuses on heat-rate improvements on coal-fired boiler units. In July 2019, the rule was finalized and applies only to our coal-fired plants. These plants have implemented or plan to implement a majority of the efficiency requirements listed in the rule.

OSM Coal Combustion Residual Rule (CCR). The EPA issued the CCR which is currently effective and establishes requirements to protect surface and groundwater from impacts of coal ash impoundments. WRDC is exempt from the EPA CCR because ash is used for backfill reclamation in areas previously mined. The current administration has not pursued further modification of the CCR.

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 assess risk annually and develop mitigation strategies to successfully and responsibly manage and ensure compliance across the enterprise. For additional information on environmental matters, see Item 1A and Note 19 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Other Properties

In addition to the facilities previously disclosed in Items 1 and 2, we own or lease several facilities throughout our service territories. Our owned facilities are as follows:

In Rapid City, South Dakota, we have a 220,000 square foot corporate headquarters building, Horizon Point, which was completed in 2017.

In Arkansas, Colorado, Iowa, Kansas, Nebraska, and Wyoming we own various office, service center, storage, shop and warehouse space totaling over 1,030,000 square feet utilized by our Gas Utilities.

In Colorado, South Dakota, and Wyoming we own various office, service center, storage, shop and warehouse space totaling approximately 305,000 square feet utilized by our Electric Utilities and Mining segments.

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In addition to our owned properties, we lease 92,527 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.

Employees

At December 31, 2019, we had 2,944 employees. Approximately 25% of our employees are represented by a union. We have not experienced any labor stoppages in recent years. At December 31, 2019, approximately 22% of our total employees and 25% of our Electric and Gas Utilities employees were eligible for regular (age 65 with at least 5 years of service) or early (ages 55 to 64 with at least 5 years of service) retirement.

The following table sets forth the number of employees included in continuing operations:
 Number of Employees
 At December 31, 2019
Corporate and Shared Services1,273
Electric Utilities and Gas Utilities1,609
Power Generation and Mining62
Total2,944

At December 31, 2019, certain employees of our Electric Utilities and Gas Utilities were covered by the following collective bargaining agreements:
UtilityNumber of EmployeesUnion AffiliationExpiration Date of Collective Bargaining Agreement
Colorado Electric102
IBEW Local 667April 15, 2023
South Dakota Electric135
IBEW Local 1250March 31, 2024
Wyoming Electric23
IBEW Local 111June 30, 2024
Iowa Gas113
IBEW Local 204July 31, 2020
Kansas Gas18
Communications Workers of America, AFL-CIO Local 6407December 31, 2024
Nebraska Gas99
IBEW Local 244March 13, 2022
Nebraska Gas (a)
146
CWA Local 7476October 30, 2019
Wyoming Gas (a)
101
CWA Local 7476October 30, 2019
Total737
  
__________
(a)In 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. There are ongoing negotiations with both bargaining units at this time.

ITEM 1A.RISK FACTORS

OPERATING RISKS

The nature of our business subjects us to a number of uncertainties and risks. Risks that may adversely affect the business, financial condition, results of operations or cash flows are described below. These risk factors and other risk factors that we discuss in our periodic reports filed with the SEC should be considered for a better understanding of our Company.

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

Our results of operations depend, in significant part, on our ability to execute our strategic business plans and growth strategy. Technology advancements, disruptive forces and innovations in the marketplace and changing business or regulatory conditions may negatively impact our current plans and strategies. An inability to successfully and timely adapt to changing conditions and execute our strategic plans and growth strategy could materially affect our financial operating results including earnings, cash flow and liquidity.


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We may be subject to unfavorable federal and state regulatory outcomes.

Our regulated Electric and Gas Utilities are subject to cost-of-service 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 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 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 recovery of our costs and the allowed return on invested capital. In addition, rate decisions could be influenced by many factors, including general economic conditions and the political environment.

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 the state 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 financial operating results including earnings, cash flow and liquidity.

We may be subject to future laws, regulations, or actions associated with fossil-fuel generation and GHG emissions.

We own and operate regulated and unregulated electric power plants that burn fossil fuels (natural gas and coal) and a surface mine that extracts and sells coal. We also purchase 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.

Increased 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 storage facilities or 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.
 
Our financial performance depends on the successful management of our facilities operations, including ongoing operation, construction, expansion, and refurbishment.

Operation, construction, expansion and refurbishment of electric generating facilities, electric and natural gas transmission and distribution systems, natural gas storage facilities, and a coal mine involve risks that could result in fires, explosions, property damage and personal injury, including death. These risks include:

Inherent dangers. Electricity and natural gas are dangerous for employees and the general public; contact with power lines, natural gas pipelines, electrical or natural gas service facilities and equipment can result in fires and explosions, causing significant property damage and personal injuries, including death;

Weather, natural conditions and disasters. Severe weather events could negatively impact operations, including our ability to provide energy safely and reliably and our ability to complete construction, expansion or refurbishment of facilities as planned. Extreme natural conditions and other disasters such as wind, lightning, flooding and winter storms, can cause wildfires, electric transmission or distribution pole failures, natural gas pipeline interruptions, outages, property damage and personal injury;

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;

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. Our ability to transition and replace our retirement-eligible utility employees is a risk; at December 31, 2019, approximately 25% of our Electric Utilities and Gas Utilities employees were eligible for regular or early retirement. Our ability to avoid or minimize supply interruptions, work stoppages and labor disputes is also a risk; approximately 25% of our employees are represented by a total of eight collective bargaining agreements.


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Equipment and processes. Breakdown or failure of equipment or processes, the unavailability or increased cost of equipment, and performance below expected levels of output or efficiency could negatively impact our results of operations. New plants may employ recently developed and technologically complex equipment, including newer environmental emission control technology.

Disrupted transmission and distribution. We depend on transmission and distribution facilities, including those operated by unaffiliated parties, to deliver the electricity and 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 product and satisfy our contractual obligations may be hindered;

Natural gas supply for generation and distribution. Our utilities 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 and environmental regulations, which could limit our utilities’ ability to operate their facilities;

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 environmental and pipeline safety laws and regulations; unexpected engineering, environmental and geological problems; and unanticipated cost overruns could negatively impact our results of operations;

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

Disruption in the functioning of our information technology and network infrastructure which is 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.
    
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 and obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance and our rights under contracts, warranties or performance guarantees may not be timely or adequate to cover lost revenues, increased expenses, liability or liquidated damage payments.

Our 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.

Inherent in our businesses are a variety of hazards and operating risks, such as leaks, blowouts, fires, releases of hazardous materials, explosions and operational problems. Many of our transmission and distribution assets are located near populated residential areas, commercial business centers and industrial sites.

These hazards could result in injury or loss of human life, cause environmental pollution, significantly damage property or natural resources or impair our ability to operate our facilities. 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 and could have a material adverse effect on our financial operating results including earnings, cash flow and liquidity.

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

Our financial operating results 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 energy efficiency programs, 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 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 financial operating results including earnings, cash flow and liquidity.

Cyberattacks, terrorism, or other malicious acts 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, SCADA, information technology systems and network infrastructure to 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 gas operations. Attacks targeting other key information 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 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 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. Despite our implementation of security measures and safeguards, all of our information technology systems may be vulnerable to disability, failures or unauthorized access

Risks associated with deployment of capital may impact our ability to execute our business plans and growth strategy.

We have significant capital investment programs planned for the next five years. The successful execution of our capital investment strategy depends on, or could be affected by, a variety of factors that include, but are not limited to: extreme weather conditions, effective management of projects, availability of qualified construction personnel including contractors, changes in commodity and other prices, governmental approvals and permitting and regulatory cost recovery.

Weather conditions may cause fluctuation in customer usage as well as service disruptions.

Our utility businesses are seasonal businesses and weather conditions and patterns can have a material impact on our operating performance. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating, respectively. Demand for natural gas depends heavily upon winter-weather patterns throughout our service territory and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our utility operations have historically generated lower revenues 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 results of operations, financial position or cash flows.

Our businesses are located in areas that could be subject to severe weather events such as snow and ice storms, tornadoes, strong winds, significant thunderstorms, flooding and drought. These events could result in lost operating revenues due to outages, property damage, including inoperable generation facilities and downed transmission and distribution lines, and storm restoration activities. We may not be able to recover the costs incurred following these weather events resulting in a negative impact on our financial operating results including earnings, cash flow and liquidity.

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We may be subject to increased risks of regulatory 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 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.

Certain Federal laws provide special protection to certain designated animal 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.

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.

FINANCING RISKS

A sub-investment grade credit rating could impact our ability to access capital markets.

Our issuer credit rating is Baa2 (Stable outlook) by Moody’s; BBB+ (Stable outlook) by S&P; and BBB+ (Stable outlook) by Fitch. Reduction of our 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.

Derivatives regulations could impede our ability to manage business and financial risks by restricting our use of derivative 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 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 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 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.


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Our hedging activities that are designed to protect against commodity price and financial market risks may cause fluctuations in reported financial results due to mark-to-market accounting treatment.

We use various financial contracts and derivatives, including futures, forwards, options and swaps to manage commodity price and financial market risks. The timing of the recognition of gains or losses on these economic hedges in accordance with GAAP does not always match up with the gains or losses on the commodities being hedged. Fluctuating commodity prices could have a negative effect on our liquidity, financial condition, and results of operations.

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 key valuation assumptions could require us to make significant unplanned contributions to our pension plans 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 these 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.

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 because they depend on our future earnings, capital requirements and financial condition and are subject to declaration by the Board of Directors. See “Liquidity and Capital Resources” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K for further information regarding these restrictions and their impact on our liquidity.

We may be unable to obtain 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.


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

A future recession, if one occurs, may lead to an increase in late payments from retail, 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 ability to obtain insurance 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 coverage may not provide protection against all significant losses.

Our ability to obtain insurance, as well as the cost of such insurance, could be impacted by developments affecting insurance businesses, international, national, state or local events, as well as the financial condition of insurers. Insurance coverage may not continue to be available at all, or at rates or on terms similar to those presently available to us. A loss for which we are not fully insured could materially and adversely affect our financial results. Our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which the Company may be subject, including but not limited to environmental hazards, fire-related liability from natural events or inadequate facility maintenance, distribution property losses, cyber-security risks and dangers that exist in the gathering and transportation of gas in pipelines.

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, and likely will continue to, require changes to our current employee benefit plans and in our administrative and accounting processes. Our 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. Within our utility rates we have generally recovered the cost of providing employee benefits. As benefit costs continue to rise, there can be no assurance that the state public utility commissions will allow recovery. The increasing cost, or inadequate recovery of, rising employee benefit costs may adversely affect our financial operating results including earnings, cash flow, or liquidity.

An effective system of internal control may not be maintained, leading to material weaknesses in internal control over financial reporting.

Section 404 of the Sarbanes-Oxley Act of 2002 requires management to make an assessment of the design 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 to the conclusion that a material weakness in internal control exists. Any control deficiencies we identify in the future could adversely affect our ability to report our financial results on a timely and accurate basis, which could result in a loss of investor confidence in our financial reports or have a material adverse effect on our ability to 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 that the control system’s objectives will be met. If we are unable to assert that our internal controls over financial reporting are effective, market perception of our business, operating results and stock price could be adversely affected.

ENVIRONMENTAL RISKS

Developments in federal and state laws concerning GHG regulations and air emissions relating to climate could materially increase our generation costs and render some of our generating units uneconomical to operate and maintain.

To the extent climate change occurs, our businesses could be adversely impacted. Warmer temperatures during the heating season in our utility service territories, or cooler temperatures during the cooling season in our electric service territories could adversely affect financial results through lower natural gas volumes delivered, lower MWh sold and associated lower revenues.


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We own and operate regulated and non-regulated fossil-fuel generating plants in Colorado, South Dakota and Wyoming. Developments under federal and state laws and regulations governing air emissions from fossil-fuel generating plants may result in more stringent emission limitations, which could have a material impact on our costs of operations. Various pending or final state and EPA regulations that will impact our facilities are also discussed in Item 1 of this Annual Report on Form 10-K under the section “Environmental Matters”.

There is uncertainty surrounding current climate regulation due to legal challenges, new federal climate legislation anticipated in the future, or state climate legislation and regulation. We cannot definitively estimate the effect of GHG legislation or regulation on our results of operations, financial position or cash flows.

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 load of our combined cycle natural gas-fired generation units. To the extent our regulated fossil-fuel generating plants are included in rate base we will attempt to recover costs associated with complying with emission standards or other requirements. We will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel generating plants from utility and other purchasers of the power generated by those non-regulated power plants. Any unrecovered costs could have a material impact on our results of operations and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain; this could cause those generating units to be de-commissioned, potentially resulting in impairment costs. We will attempt to recover any remaining asset value; however, any unrecovered costs could have a material impact on our results of operations and financial condition.

The costs to achieve or maintain compliance with existing or future governmental laws, regulations or requirements, or failure to comply, could increase significantly.

Our business segments are subject to numerous environmental laws 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.

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.

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.

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 financial operating results including earnings, cash flow and liquidity could be adversely impacted.


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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 19, “Commitments and Contingencies”, of our Notes to the 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 Dodd-Frank is included in Exhibit 95 of this Annual Report.


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INFORMATION ABOUT OUR EXECUTIVE OFFICERS

David R. Emery, age 57, has been Executive Chairman since January 1, 2019, Chairman and Chief Executive Officer from 2016 through 2018, 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 30 years of experience with the Company.

Linden R. Evans, age 57, 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 18 years of experience with the Company.

Scott A. Buchholz, age 58, 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 39 years of experience with the Company, including 28 years with Aquila.

Brian G. Iverson, age 57, 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 16 years of experience with the Company.

Richard W. Kinzley, age 54, 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 20 years of experience with the Company.

Jennifer C. Landis, age 45, 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 18 years of experience with the Company.

Karen Beachy, age 48, has been Senior Vice President - Growth and Strategy since August 26, 2019. She served as Vice President - Growth and Strategy from 2018 to August 2019, Vice President - Supply Chain from 2016 to 2018, and Director of Supply Chain from 2014 to 2016. Ms. Beachy has 5 years of experience with the Company.

Stuart Wevik, age 58, 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 34 years of experience with the Company.


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PART II

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

Our common stock is traded on the New York Stock Exchange under the symbol BKH. As of December 31, 2019, we had 3,586 common shareholders of record and 32,285 beneficial owners, representing all 50 states, the District of Columbia and 6 foreign countries.

We have paid a regular quarterly cash dividend each year since the incorporation of our predecessor company in 1941 and expect to continue paying a regular quarterly dividend for the foreseeable future. At its January 29, 2020 meeting, our Board of Directors declared a quarterly dividend of $0.535 per share, equivalent to an annual dividend rate of $2.14 per share. This equivalent rate, if declared and paid in 2020, will represent 50 consecutive years of annual dividend increases.

For additional discussion of our dividend policy and factors that may limit our ability to pay dividends, see “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 2019.

ISSUER PURCHASES OF EQUITY SECURITIES
There were no equity securities acquired for the twelve months ended December 31, 2019.


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ITEM 6.SELECTED FINANCIAL DATA

(Minor differences may result due to rounding)
Years Ended December 31,2019 2018 2017 
2016 (a)
 2015 
(dollars in thousands, except per share amounts)         
           
Total Assets 
$7,558,457
 $6,963,327
 $6,658,902
 $6,541,773
 $4,626,643
 
           
Property, Plant and Equipment 
          
Property, plant and equipment$6,784,679
 $6,000,015
 $5,567,518
 $5,315,296
 $3,849,309
 
Accumulated depreciation and depletion(1,281,493) (1,145,136) (1,026,088) (929,119) (794,695) 
Total property, plant and equipment, net$5,503,186
 $4,854,879
 $4,541,430
 $4,386,177
 $3,054,614
 
           
Capital Expenditures          
Continuing Operations$849,755
 $502,424
 $337,689
 $460,450
 $289,896
 
Discontinued Operations (b)

 2,402
 23,222
 6,669
 168,925
 
Total Capital Expenditures$849,755
 $504,826
 $360,911
 $467,119
 $458,821
 
           
Capitalization (excluding noncontrolling interests)
          
Current maturities of long-term debt$5,743
 $5,743
 $5,743
 $5,743
 $
 
Notes payable349,500
 185,620
 211,300
 96,600
 76,800
 
Long-term debt, net of current maturities3,140,096
 2,950,835
 3,109,400
 3,211,189
 1,853,682
 
Total stockholders’ equity2,362,123
 2,181,588
 1,708,974
 1,614,639
 1,465,867
 
Total capitalization$5,857,462
 $5,323,786
 $5,035,417
 $4,928,171
 $3,396,349
 
           
Total Operating Revenues$1,734,900
 $1,754,268
 $1,680,266
 $1,538,916
 $1,261,322
 
           
Net Income Available for Common Stock         
Income from continuing operations available for common stock199,310
(c) (g)265,329
(c)(f)194,133
(c) (d)137,132
(c) (d)141,548
(d)
Income (loss) from discontinued operations, net of tax (b)

 (6,887) (17,099) (64,162) (173,659) 
Net income (loss) available for common stock$199,310
 $258,442
 $177,034
 $72,970
 $(32,111) 
           
Common Stock Data(e) (in thousands)
          
Shares outstanding, average basic60,662
 54,420
 53,221
 51,922
 45,288
 
Shares outstanding, average diluted60,798
 55,486
 55,120
 53,271
 45,288
 
Shares outstanding, end of year61,477
 60,004
 53,541
 53,382
 51,192
 


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SELECTED FINANCIAL DATA continued

Years Ended December 31,2019 2018 2017 2016 2015 
(dollars in thousands, except per share amounts)         
           
Earnings (Loss) Per Share of Common Stock (in dollars)
        
Basic earnings (loss) per average share -          
Continuing operations$3.52
 $5.14
 $3.92
 $2.83
 $3.12
 
Discontinued operations (b)

 (0.13) (0.32) (1.23) (3.83) 
Non-controlling interest (c)
(0.23) (0.26) (0.27) (0.19) 
 
Total$3.29
 $4.75
 $3.33
 $1.41
 $(0.71) 
Diluted earnings (loss) per average share -         
Continuing operations$3.51
 $5.04
 $3.78
 $2.75
 $3.12
 
Discontinued operations (b)

 (0.12) (0.31) (1.20) (3.83) 
Non-controlling interest (c)
(0.23) (0.26) (0.26) (0.18) 
 
Total$3.28
 $4.66
 $3.21
 $1.37
 $(0.71) 
           
Cash Dividends Paid on Common Stock$124,647
 $106,591
 $96,744
 $87,570
 $72,604
 
           
Dividends Declared per Share$2.05
 $1.93
 $1.81
 $1.68
 $1.62
 
           
Book Value Per Share, End of Year$38.42
 $36.36
 $31.92
 $30.25
 $28.63
 
          
____________________________________
(a)Effective February 12, 2016, we completed the SourceGas Transaction. Total cash consideration paid, net of debt assumed and working capital adjustment received, was $1.124 billion, funded with a combination of the issuance of 6.3 million shares of our common stock on November 23, 2015, 5.98 million equity units issued on November 23, 2015, $546 million of net proceeds from the issuance of senior unsecured notes on January 13, 2016, cash on hand and draws under our revolving credit facility.
(b)On November 1, 2017, we made the decision to divest our Oil and Gas assets which was completed in 2018. Oil and Gas results are shown in discontinued operations. 2017 includes a non-cash 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 impairment charges to crude oil and natural gas properties of $158 million.
(c)On April 14, 2016, Black Hills Electric Generation sold a 49.9% interest in Black Hills Colorado IPP. Net income available for common stock for 2019, 2018, 2017 and 2016 was reduced by $14 million, $14 million, $14 million and $9.6 million, respectively, attributable to this noncontrolling interest.
(d)2017, 2016 and 2015 include incremental SourceGas Transaction costs, after-tax of $2.8 million, $30 million and $6.7 million, respectively.
(e)In 2019, we issued 1.33 million shares at an average share price of $75.28 under our ATM equity offering program. On November 1, 2018, we issued 6.3 million shares of common stock upon conversion of our Equity Units. In 2016, we issued 1.97 million shares at an average share price of $60.95 under our ATM equity offering program.
(f)
The increase in 2018 included a $73 million tax benefit resulting from legal entity restructuring. See Note 15 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.
(g)
2019 includes a non-cash after-tax impairment of $15 million in our investment in equity securities of a privately held oil and gas company. See Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.


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 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

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ITEMS 7 & and 7A.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


Executive Summary

We are a customer-focused, growth-oriented electric and natural gas utility company with a mission of improving life with energy and a vision to be the energy partner of choice. The Company provides electricity and natural gas through its Electric and Gas Utilities to 1.3 million customers in 824 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming. 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’s Electric Utilities are supported by our Power Generation and Mining segments. The Power Generation segment produces electric power from its five generating facilities and sells most of the electric capacity and energy to our Electric Utilities under long-term contracts. Our Mining segment produces coal at our only location near Gillette, Wyoming, and sells nearly all production to fuel the on-site, mine-mouth power generation facilities.

The Company has provided energy and served customers for 136 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. Our strategic focus has not changed in over a century - serving customers with affordable, reliable and safe energy. Our strategy today continues that emphasis on serving customers, but with a renewed focus on better engaging with the people and communities we serve. Customer expectations are rapidly changing with the advancement of technology and customers are demanding simpler, faster and more convenient solutions to their energy needs. We are Ready to serve as we have done for the past 136 years.

Our strategy consists of five primary areas that focus on improving the way we serve customers with safe, reliable and affordable energy while improving the lives of the customers and communities we serve. The strategy is to 1) become the safest energy company in the utility industry; 2) transform the customer experience; 3) grow our electric and natural gas customer load; 4) pursue operating efficiencies; and 5) modernize utility infrastructure. This strategic focus will present the company with significant investment needs as we modernize our infrastructure systems and meet customer growth. It will also allow us to better understand our customer and community needs while providing more intuitive and cost-effective interactions.


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Key Elements of our Business Strategy

Modernize, replace and operate utility infrastructure to meet our customers’ energy needs while providing safe, reliable and affordable energy. Our utilities own and operate large electric and natural gas infrastructure systems that span nearly 1,600 miles. Our Electric Utilities own and operate 939 MW of generation capacity and 8,900 miles of transmission and distribution lines and our Gas Utilities own and operate 46,000 miles of natural gas transmission and distribution pipelines. A key strategic focus is to modernize this utility infrastructure to meet customers’ and communities’ varied energy needs and to ensure the continued delivery of safe, reliable and affordable energy. In addition, we need to invest in the accessibility, 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, our Electric Utilities utilize a distribution integrity program to ensure the timely repair and replacement of aging infrastructure. Our Gas Utilities utilize a programmatic approach to system-wide pipeline system 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. Many of our Gas Utilities are authorized to use system safety, integrity and replacement cost recovery mechanisms that provide for customer rate adjustments which reflect the cost incurred in repairing and replacing the gas delivery systems.

We estimate our five-year capital investment to be approximately $2.7 billion, with most of that investment targeted toward upgrading existing utility infrastructure and to support customer and community growth needs. Our actual 2019 and forecasted capital expenditures and depreciation for next five years from 2020 through 2024 are as follows (in millions):chart-a069200ae3409a0e969a04.jpg

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 ActualPlannedPlannedPlannedPlannedPlanned
Capital Expenditures By Segment201920202021202220232024
(in millions)      
Electric Utilities$223
$246
$203
$170
$137
$152
Gas Utilities512
391
309
285
316
293
Power Generation85
7
9
11
6
6
Mining9
8
12
9
9
9
Corporate and Other21
17
22
11
12
10
Total$850
$669
$555
$486
$480
$470


Efficiently plan, construct and operate rate base power generation facilities to serve our Electric Utilities. We believe that we best serve customers and communities with a vertically integrated business model for our Electric Utilities. This business model remains a core strength and strategy today as we invest in and operate efficient power generation resources to cost-effectively supply electricity to our customers. We strive to provide power at reasonable rates to our customers and earn competitive returns for our investors.

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, efficiency in converting fuel into energy, low per unit operating and maintenance costs and high levels of power plant availability. For our coal-fired power plants, we leverage our mine-mouth location advantage to eliminate coal transportation costs that often represent the largest component of the delivered cost of coal for many other utilities. Additionally, we operate our plants with high levels of availability as compared to industry benchmarks.

We continue to believe that ownership of power generation facilities by our Electric Utilities best serves customers. 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 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, reasonable, stable return on their investment.

Proactively integrate alternative and renewable energy into our utility energy supply while mitigating customer rate impacts. Some of our customers, particularly our larger customers, are demanding more renewable and cleaner sources of energy to meet their sustainability goals. In addition, there is more interest from voters, regulators and legislators to increase the use of renewable and other alternative energy sources. To support this interest, we have created and received approvals for new, voluntary renewable energy tariffs to serve certain commercial, industrial and governmental agency customer requests for renewable energy resources in South Dakota and Wyoming. To meet the renewable energy commitments under the new tariffs, we also received approval from the Wyoming Public Service Commission to build the Corriedale wind project, a 52.5 MW wind farm to be constructed near Cheyenne, Wyoming. The $79 million project is expected to be in service by year-end 2020. Supporting our renewable energy efforts in Colorado, in November 2019, we successfully commissioned Busch Ranch II, a 60 MW wind farm near Pueblo, Colorado, to provide renewable energy to our Colorado Electric utility.


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To date, 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 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 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 affordable 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.

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 an important 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. In addition, relationships that we have established with wholesale power customers have developed into other opportunities. MEAN, MDU and the City of Gillette, Wyoming were wholesale power customers that are now joint minority owners in two of our power plants, Wygen I and Wygen III, reducing risk and providing steady revenues.

Vertically integrate businesses that are supportive of our Electric and Gas utility businesses. While our primary 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 power generation and mining 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.

The Power Generation segment currently owns five power facilities, four of which are contracted with our affiliate Electric Utilities under long-term power purchase agreements. Our Power Generation segment has an experienced staff with significant expertise in planning, building and operating power plants. The power generation team has constructed 20 coal-fired, gas-fired and renewable generation projects since 1995 with aggregate project costs in excess of $2.1 billion. This team 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 Power 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.

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 majority interests in four of our five power plants. We own 20% of the fifth power plant which is operated by a majority owner. The mine provides 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 other coal-fired and gas-fired power plants. Nearly all of the mine’s production is sold to the five on-site, mine-mouth 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.

Expand utility operations through selective acquisitions of electric and gas utilities. The electric and natural gas utility industries have consolidated significantly over the past two decades and continue to consolidate. We have successfully acquired and integrated numerous utility systems since 2005, including two large, transformational acquisitions - the Aquila Transaction in 2008 and SourceGas Transaction 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 can 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. As pipeline regulations continue to increase, we believe there will be more opportunities to purchase these smaller and more rural utility systems.


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Grow our dividend. We are extremely proud of our track record of annual dividend increases for shareholders. In January 2020, our Board of Directors declared a quarterly dividend of $0.535 per share, equivalent to an annual dividend of $2.14 per share. This current annual equivalent rate of $2.14 per share, if declared and paid in 2020, will represent 50 consecutive years of annual dividend increases. We intend to continue our record of annual dividend increases with a targeted dividend payout ratio of 50% to 60%.

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 predominately 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 the need for capital deployment at our utilities and continued focus on improving efficiencies and controlling 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 executing our long-term strategic plan. Prospective information for our operating segments should be read in conjunction with our business strategy discussed above, and our 2019 company highlights discussed below.



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Our discussion and analysis for the year ended December 31, 2019 compared to 2018, as well as discussion and analysis of the results of operations for the year ended December 31, 2018 compared to 2017 given segment reporting changes adopted by the Company in 2019, is included herein. For further discussion and analysis that remains unchanged for the year ended December 31, 2018 compared to 2017, 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, 2018, which was filed with the SEC on February 19, 2019.

Segment 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.


Results of Operations

Consolidated Summary and Overview
 For the Years Ended December 31,
 2019 2018 2017
(in millions, except per diluted share amounts)IncomeEPS IncomeEPS IncomeEPS
         
Net income from continuing operations available for common stock$199.3
$3.28
 $265.3
$4.78
 $194.1
$3.52
Net (loss) from discontinued operations

 (6.9)(0.12) (17.1)(0.31)
Net income available for common stock$199.3
$3.28
 $258.4
$4.66
 $177.0
$3.21
         

2019 Compared to 2018

The variance to the prior year included the following:

Electric Utilities’ adjusted operating income increased $4.4 million due to reduced purchased power capacity costs, increased rider revenues and the prior year Wyoming Electric PCA settlement partially offset by higher operating expenses driven by outside services and employee costs;
Gas Utilities’ adjusted operating income increased $4.7 million primarily due to new customer rates and rider revenues, customer growth and increased transport and transmission driven by increased volumes from new and existing customers partially offset by higher operating expenses driven by outside services and employee costs;
Power Generation’s adjusted operating income increased $2.2 million primarily due to higher revenue from increased wind MWh sold and higher PPA pricing partially offset by higher depreciation and property taxes from new wind assets;
Mining’s adjusted operating income decreased $3.7 million primarily due to lower tons sold driven by planned and unplanned generating facility outages partially offset by lower operating expenses;
Corporate and Other expenses decreased $1.4 million primarily due to prior year expenses related to the oil and gas segment that were not reclassified to discontinued operations;
A $20 million pre-tax non-cash impairment in 2019 of our investment in equity securities of a privately held oil and gas company;
We expensed $5.4 million of development costs related to projects we no longer intend to construct; and
Increased tax expense of $53 million primarily due to a prior year $73 million tax benefit resulting from legal entity restructuring partially offset by a prior year $4.0 million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes and current year $5.9 million federal PTCs and related state ITCs associated with new wind assets.

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2018 Compared to 2017

The variance when comparing 2018 to 2017 included the following:

Electric Utilities’ adjusted operating income decreased $21.9 million due to TCJA benefits delivered to customers, the Wyoming Electric PCA settlement and higher operating expenses partially offset by increased rider revenues and favorable weather;
Gas Utilities’ adjusted operating income increased $0.1 million primarily due to colder winter weather, new customer rates, customer growth and increased transport and transmission offset by TCJA benefits delivered to customers and higher operating expenses;
Power Generation’s adjusted operating income decreased $4.1 million primarily due to a decrease in MWh sold and higher operating expenses;
Mining’s adjusted operating income increased $2.8 million primarily due to increase in price per ton sold and lower operating expenses;
Corporate and Other expenses decreased $3.3 million primarily due to prior year acquisition costs; and
Increased tax benefit of $97 million primarily due to a $73 million tax benefit resulting from legal entity restructuring and a reduction in the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018.

The following table summarizes select financial results by operating segment and details significant items (in thousands):
 For the Years Ended December 31,
 2019Variance2018Variance2017
 (in thousands)
Revenue     
Revenue$1,885,669
$(11,573)$1,897,242
$83,721
$1,813,521
Intercompany eliminations(150,769)(7,795)(142,974)(9,719)(133,255)
 $1,734,900
$(19,368)$1,754,268
$74,002
$1,680,266
      
Adjusted operating income (a)
     
Electric Utilities$160,297
$4,428
$155,869
$(21,868)$177,737
Gas Utilities189,971
4,732
185,239
134
185,105
Power Generation44,779
2,165
42,614
(4,076)46,690
Mining12,627
(3,713)16,340
2,840
13,500
Corporate and Other(1,632)1,393
(3,025)3,271
(6,296)
 406,042
9,005
397,037
(19,699)416,736
      
Interest expense, net(137,659)2,316
(139,975)(2,873)(137,102)
Impairment of investment(19,741)(19,741)


Other income (expense), net(5,740)(4,560)(1,180)(3,288)2,108
Income tax benefit (expense)(29,580)(53,247)23,667
97,034
(73,367)
Income from continuing operations213,322
(66,227)279,549
71,174
208,375
(Loss) from discontinued operations, net of tax
6,887
(6,887)10,212
(17,099)
Net income213,322
(59,340)272,662
81,386
191,276
Net income attributable to noncontrolling interest(14,012)208
(14,220)22
(14,242)
Net income available for common stock$199,310
$(59,132)$258,442
$81,408
$177,034
      
_____________
(a)
In 2019, we changed our measure of segment performance to adjusted operating income, which impacted our segment disclosures for all periods presented. See Note 5 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.



48


2019 Overview of Business Segments and Corporate Activity

Electric Utilities

On December 13, 2019, Colorado Electric issued a request for proposals for its Renewable Advantage program, to potentially add up to 200 MW of renewable energy to its southern Colorado system. A competitive solicitation process for the addition of cost-effective, utility-scale renewable energy projects includes wind, solar and battery storage to supplement existing natural gas and wind generation power supplies Bidders have until February 15, 2020, to submit proposals, which will be reviewed by an independent evaluator overseen by the CPUC. Based on the outcome of the bidding process, projects would be placed in service no later than 2023.

In July 2019, South Dakota Electric and Wyoming Electric received approvals for the Renewable Ready program and related jointly-filed CPCN to construct Corriedale. The wind project will be jointly owned by the two electric utilities to deliver renewable energy for large commercial, industrial and governmental agency customers. In November 2019, South Dakota Electric received approval from the SDPUC to increase the offering under the program by 12.5 MW. The two electric utilities also received a determination from the WPSC to increase the project to 52.5 MW. The $79 million project is expected to be in service by year-end 2020.

On September 17, 2019, South Dakota Electric completed construction on the final 94-mile segment of a 175-mile electric transmission line from Rapid City, South Dakota, to Stegall, Nebraska. The first 48-mile segment was placed in service on July 25, 2018, and the second 33-mile segment was placed in service on November 20, 2018.

Colorado Electric set a new all-time and summer peak load:

On July 19, 2019, Colorado Electric set a new all-time and summer peak load of 422 MW, exceeding the previous peak of 413 MW set in June 2018.

Wyoming Electric set a new all-time and summer peak load, and also set a new winter peak load:

On July 19, 2019, Wyoming Electric set a new all-time and summer peak load of 265 MW, exceeding the previous peak of 254 MW set in July 2018.

On December 16, 2019, Wyoming Electric set a new winter peak load of 247 MW, exceeding the previous peak of 238 MW set in December 2018.

Cooling degree days for the year ended December 31, 2019 were 14% higher than the normal compared to 29% higher than normal in 2018.

Heating degree days for the year ended December 31, 2019 were 5% higher than normal compared to 3% higher than normal in 2018.

Gas Utilities

Gas Utilities continued to consolidate utility jurisdictions within the States of Colorado, Nebraska, and Wyoming:

On December 11, 2019, Wyoming Gas received approval from the WPSC to consolidate the rates, tariffs and services of its four existing gas distribution territories. A new, single statewide rate structure will be effective March 1, 2020. New rates are expected to generate $13 million in new revenue based on a return on equity of 9.40% and a capital structure of 50.23% equity and 49.77% debt. The approval also allows for a rider to recover integrity investments for system safety and reliability.

On February 1, 2019, Colorado Gas submitted a rate review with the CPUC to consolidate rates, tariffs and services of its two existing gas distribution territories. The rate review requested $2.5 million in new revenue to recover investments in safety, reliability and system integrity. Colorado Gas also requested a new rider mechanism to recover future safety and integrity investments in its system. On December 27, 2019, the ALJ issued a recommended decision denying the company’s plan to consolidate rate territories and recommending a rate decrease. Colorado Gas has filed exceptions to the ALJ’s recommended decision. A decision by the CPUC is expected by the end of March 2020. Legal consolidation was previously approved by the CPUC in late 2018 and completed in early 2019.

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On October 29, 2019, Nebraska Gas received approval from the NPSC to merge its two natural gas distribution companies. Legal consolidation was effective January 1, 2020, and a rate review is expected to be filed by mid-year 2020 to consolidate the rates, tariffs and services.

On December 1, 2019, Wyoming Gas placed in service the $54 million, 35-mile Natural Bridge pipeline project to enhance supply reliability and delivery capacity for customers in central Wyoming. The new 12-inch steel pipeline interconnects from a supply point near Douglas, Wyoming, to facilities near Casper, Wyoming. The associated investment was included in the Wyoming Gas rate review completed in December 2019.

Heating degree days at the Gas Utilities for the year ended December 31, 2019 were 5% higher than normal compared to 2% higher than normal in 2018.

Power Generation

On November 26, 2019, Black Hills Electric Generation placed in service Busch Ranch II. Through a competitive bidding process, Black Hills Electric Generation was selected to deliver renewable energy under a 25-year PPA to Colorado Electric.

On August 2, 2019, Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for approval of a new 60 MW PPA. The agreement would fulfill the capacity need for Wyoming Electric at the expiration of the current agreement on December 31, 2022. If approved, Black Hills Wyoming will continue to deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and for 20 additional years. On December 23, 2019, the Company filed a response to questions from the FERC and awaits a decision from FERC.

Mining

In October 2019, negotiations were completed for the price reopener in the contract with the Wyodak power plant. Effective July 1, 2019, the new price was reset at $17.94 per ton with customary escalators, compared to the prior contract price of $18.25 per ton. The contract expires on December 31, 2022 and negotiations are underway to extend the contract.

Corporate and Other

On October 3, 2019, we completed a public debt offering of $700 million in senior unsecured notes. Proceeds were used to repay the $400 million Corporate term loan due June 17, 2021, retire the $200 million 5.875% senior notes due July 15, 2020 and repay a portion of short-term debt.

During the year ended December 31, 2019, we issued a total of 1.3 million shares of common stock for net proceeds of $99 million under our ATM equity offering program.

On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million and extended the term through June 17, 2021 on substantially similar terms and covenants. The net proceeds were used to pay down short-term debt. Proceeds from the October 3, 2019 debt transaction were used to repay this term loan.

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, 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 measure due to the exclusion of depreciation and amortization from the measure. The presentation of gross margin is intended to supplement investors’ understanding of our operating performance.

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Gross margin for our Electric Utilities is calculated as operating revenue less cost of fuel and purchased power. Gross margin for our Gas Utilities is calculated as operating revenues less cost of gas sold. Our gross margin is impacted by the fluctuations in power and natural gas purchases and other fuel supply costs. However, while these fluctuating costs impact gross margin as a percentage of revenue, they only impact total gross margin if the costs cannot be passed through to our customers.

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 results for the years ended December 31 for the Electric Utilities were as follows (in thousands):
 2019Variance2018Variance2017
      
Revenue$712,752
$1,301
$711,451
$6,801
$704,650
      
Total fuel and purchased power268,297
(15,543)283,840
9,477
274,363
      
Gross margin (non-GAAP)444,455
16,844
427,611
(2,676)430,287
      
Operations and maintenance195,581
9,406
186,175
13,868
172,307
Depreciation and amortization88,577
3,010
85,567
5,324
80,243
Total operating expenses284,158
12,416
271,742
19,192
252,550
      
Adjusted operating income (a)
$160,297
$4,428
$155,869
$(21,868)$177,737
____________________
(a)
Due to the changes in our segment disclosures discussed in Note 5 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, Electric Utilities Adjusted operating income was revised for the years ended December 31, 2018 and December 31, 2017 which resulted in an increase of $6.4 million and $7.1 million, respectively.

2019 Compared to 2018

Gross margin increased over the prior year as a result of:
 (in millions)
Reduction in purchased power capacity costs$6.5
Prior year Wyoming Electric PCA Stipulation settlement3.7
Rider recovery3.1
Increased commercial and industrial demand1.9
Weather0.2
Other1.4
Total increase in Gross margin (non-GAAP)$16.8

Operations and maintenance expense increased primarily due to $4.7 million of higher employee costs and $2.9 million of higher outside services expenses. Various other expenses comprise the remainder of the increase compared to the prior year.

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


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2018 Compared to 2017

Gross margin decreased over the prior year as a result of:
 (in millions)
TCJA revenue reserve$(22.3)
Wyoming Electric PCA Stipulation settlement(2.6)
Other(1.4)
Horizon Point shared facility revenue (a)
9.8
Rider recovery5.1
Weather3.6
Power Marketing, transmission and Tech Services3.5
Residential customer growth1.6
Total increase (decrease) in Gross margin (non-GAAP)$(2.7)
____________________
(a)Horizon Point shared facility revenue was offset by facility expenses at our operating segments and had no impact on consolidated results.

Operations and maintenance expense increased primarily due to $4.5 million of higher facility costs, $4.1 million of higher outside services expenses, $3.6 million of higher employee costs, and $1.0 million of higher property taxes due to a higher asset base.

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

 For the year ended December 31,
Contracted power plant fleet availability (a)
201920182017
    
Coal-fired plants  (b)
92.1%93.9%88.9%
Natural gas fired plants and Other plants (c)
87.9%96.4%96.1%
Wind95.6%96.9%93.3%
Total availability89.9%95.6%93.6%
    
Wind capacity factor38.7%39.2%36.7%
____________________
(a)Availability and wind capacity factor are calculated using a weighted average based on capacity of our generating fleet.
(b)2019 included planned outages at Neil Simpson II and Wygen III and unplanned outages at Wyodak Plant and Wygen III.
(c)2019 included planned outages at Neil Simpson CT and Lange CT.



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Gas Utilities

Operating results for the years ended December 31 for the Gas Utilities were as follows (in thousands):
 2019Variance2018Variance2017
Revenue:     
Natural gas - regulated$932,111
$(10,813)$942,924
$77,093
$865,831
Other - non-regulated services77,919
(4,464)82,383
584
81,799
Total revenue1,010,030
(15,277)1,025,307
77,677
947,630
      
Cost of natural gas sold:     
Natural gas - regulated406,643
(35,887)442,530
61,271
381,259
Other - non-regulated services19,255
(368)19,623
(8,721)28,344
Total cost of sales425,898
(36,255)462,153
52,550
409,603
      
Gross margin (non-GAAP)584,132
20,978
563,154
25,127
538,027
      
Operations and maintenance301,844
10,363
291,481
22,291
269,190
Depreciation and amortization92,317
5,883
86,434
2,702
83,732
Total operating expenses394,161
16,246
377,915
24,993
352,922
      
Adjusted operating income$189,971
$4,732
$185,239
$134
$185,105

2019 Compared to 2018

Gross margin increased over the prior year as a result of:
 (in millions)
New rates$16.2
Customer growth - distribution5.2
Increased transport and transmission2.6
Weather(2.2)
Decreased mark-to-market on non-utility natural gas commodity contracts(3.3)
Other2.5
Total increase in Gross margin (non-GAAP)$21.0

Operations and maintenance expense increased primarily due to $5.5 million of higher outside services expenses, $1.2 million higher employee costs and $2.0 million of higher property taxes due to a higher asset base driven by prior and current year capital expenditures. Various other expenses comprise the remainder of the increase compared to the prior year.
 
Depreciation and amortization increased primarily due to a higher asset base driven by prior and current year capital expenditures.


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2018 Compared to 2017

Gross margin increased over the prior year as a result of:
 (in millions)
Weather (a)
$13.8
New rates10.7
Customer growth - distribution5.2
Increased mark-to-market on non-utility natural gas commodity contracts4.0
Increased transport and transmission3.6
Natural gas volumes sold3.2
Non-utility - Choice Gas, Tech Services and appliance repair2.7
Other2.4
TCJA revenue reserve(20.5)
Total increase (decrease) in Gross margin (non-GAAP)$25.1
___________________
(a)Heating degree days at the Gas Utilities for the year ended December 31, 2018 were 2% higher than normal compared to 10% lower than normal in 2017.

Operations and maintenance expense increased primarily due to $11.8 million of higher employee costs, $4.7 million of higher facility costs, $4.0 million of higher outside services expenses and $2.1 million of higher bad debt expense driven by an increase in revenues.

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

Power Generation

Our Power Generation segment operating results for the years ended December 31 were as follows (in thousands):
 2019Variance2018Variance2017
      
Revenue$101,258
$8,807
$92,451
$(2,169)$94,620
      
Total fuel9,059
467
8,592
(748)9,340
Operations and maintenance28,429
3,294
25,135
2,093
23,042
Depreciation and amortization18,991
2,881
16,110
562
15,548
Total operating expenses56,479
6,642
49,837
1,907
47,930
      
Adjusted operating income (a)
$44,779
$2,165
$42,614
$(4,076)$46,690
____________________
(a)
Due to the changes in our segment disclosures discussed in Note 5 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, Power Generation Adjusted operating income was revised for the years ended December 31, 2018 and December 31, 2017 which resulted in a decrease of $(5.7) million and $(6.5) million, respectively.

2019 Compared to 2018

Revenue increased in the current year due to increased wind MWh sold and higher PPA prices. Operating expenses increased in the current year primarily due to higher depreciation and property taxes from new wind assets.



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2018 Compared to 2017

Revenue decreased in 2018 due to a decrease in MWh sold, primarily from a planned outage at Wygen I. Operating expenses increased due to higher maintenance expenses primarily related to outage costs at Wygen I and higher depreciation.

 For the year ended December 31,
Contracted power plant fleet availability (a)
201920182017
    
Coal-fired plant (b)
94.5%85.8%96.9%
Natural gas-fired plants98.6%99.4%99.2%
Wind (c)
90.6%N/AN/A
Total availability95.0%95.9%98.6%
    
Wind capacity factor (c)
23.5%N/AN/A
___________
(a)Availability and wind capacity factor are calculated using a weighted average based on capacity of our generating fleet.
(b)Wygen I experienced a planned outage in 2018
(c)Change from 2018 to 2019 is driven by Black Hills Electric Generation’s acquisition of new wind assets.


Mining

Mining operating results for the years ended December 31 were as follows (in thousands):
 2019Variance2018Variance2017
      
Revenue$61,629
$(6,404)$68,033
$1,412
$66,621
      
Operations and maintenance40,032
(3,696)43,728
(1,154)44,882
Depreciation, depletion and amortization8,970
1,005
7,965
(274)8,239
Total operating expenses49,002
(2,691)51,693
(1,428)53,121
      
Adjusted operating income$12,627
$(3,713)$16,340
$2,840
$13,500

The following table provides certain operating statistics for the Mining segment (in thousands):
 201920182017
Tons of coal sold3,716
4,085
4,183
Cubic yards of overburden moved8,534
8,970
9,018
Coal reserves at year-end (in tons)185,448
189,164
194,909
    
Revenue per ton$15.94
$16.11
$15.93

2019 Compared to 2018

Current year revenue decreased primarily due to 9% fewer tons sold driven primarily by planned and unplanned generation facility outages at the Wyodak Plant. Operating expenses decreased primarily due to lower royalties and production taxes on decreased revenues and lower fuel, labor, and major maintenance expenses.


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2018 Compared to 2017

Revenue increased primarily due to a 1% increase in price per ton sold. Current year revenue is also reflective of lease and rental revenue, previously reported in Other income, net. Operating expenses decreased primarily due to lower major maintenance expenses.

Corporate and Other

Corporate and Other operating results for the years ended December 31 were as follows (in thousands):
(in thousands)2019Variance2018Variance2017
      
Adjusted operating (loss) (a)
$(1,632)$1,393
$(3,025)$3,271
$(6,296)
____________
(a)
Due to the changes in our segment disclosures discussed in Note 5 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, Corporate and Other Adjusted operating (loss) was revised for the years ended December 31, 2018 and December 31, 2017 which resulted in a decrease of $(0.7) million and $(0.6) million, respectively.

2019 Compared to 2018

The variance in Adjusted operating (loss) was primarily due to prior year expenses related to the oil and gas segment that were not reclassified to discontinued operations.

2018 Compared to 2017

The variance in Adjusted operating (loss) was primarily due to prior year acquisition costs.

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

(in thousands)2019Variance2018Variance2017
      
Interest expense, net$(137,659)$2,316
$(139,975)$(2,873)$(137,102)
Impairment of investment(19,741)(19,741)


Other income (expense), net(5,740)(4,560)(1,180)(3,288)2,108
Income tax benefit (expense)(29,580)(53,247)23,667
97,034
(73,367)

2019 Compared to 2018

Impairment of Investment

For the year ended December 31, 2019, we recorded a pre-tax non-cash write-down of $20 million in our investment in equity
securities of a privately held oil and gas company. The impairment was triggered by a deterioration in earnings performance of
the privately held oil and gas company and an adverse change in future natural gas prices. See Note 1 of the Notes to
Consolidated Financial Statements for additional details.

Other Income (Expense)

For the year ended December 31, 2019, we expensed $5.4 million of development costs related to projects we no longer intend to construct.



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Income Tax Benefit (Expense)

The increase in tax expense was primarily due to a prior year $73 million tax benefit resulting from legal entity restructuring partially offset by:

A prior year $(4.0) million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes;
Current year $3.8 million of federal PTCs and $2.1 million of related state ITCs associated with new wind assets;
A current year $1.9 million tax benefit from increased repair activity in flow-through regulatory jurisdictions;
A current year $1.4 million tax benefit for incremental excess deferred tax amortization related to tax reform; and
A current year $3.4 million tax benefit from a federal tax loss carry-back claim including interest. We identified certain qualified expenses that extend beyond the typical two-year carry-back period.

2018 Compared to 2017

Other Income (Expense)

The variance in Other income (expense), net was primarily due to the presentation change of non-service pension costs to Other income (expense) in 2018, previously reported in Operations and maintenance.

Income Tax Benefit (Expense)

The variance in Income tax benefit (expense) was primarily due to a $73 million tax benefit in 2018 resulting from legal entity restructuring and the reduction in the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018, partially offset by a $(4.0) million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes.


Liquidity and Capital Resources

OVERVIEW

Our company requires significant cash to support and grow our businesses. Our predominant source of cash is from our operations and supplemented with corporate financings. 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 and during periods of high natural gas prices, as well as during the construction season.

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.


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The following table provides an informational summary of our financial position as of December 31 (dollars in thousands):
Financial Position Summary20192018
Cash and cash equivalents$9,777
$20,776
Restricted cash and equivalents$3,881
$3,369
Notes payable$349,500
$185,620
Short-term debt, including current maturities of long-term debt$5,743
$5,743
Long-term debt (a)
$3,140,096
$2,950,835
Stockholders’ equity$2,362,123
$2,181,588
   
Ratios  
Long-term debt ratio57%57%
Total debt ratio60%59%
______________
(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 fund our cash requirements, there are many factors with the potential to influence our cash flow position, including weather 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 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, 2019, we had sufficient liquidity to cover collateral that could be required to be posted under these 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 a percentage of our forecasted natural gas supply consumption using options, futures, basis swaps and physical fixed price purchases.

Interest Rates

Some of our debt instruments have a variable interest rate component which can change significantly depending on the economic climate. We do not have any interest rate swap agreements at December 31, 2019; 90% of our interest rate exposure has been mitigated through fixed interest rates.


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Federal and State Regulations

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 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.

CASH GENERATION AND CASH REQUIREMENTS

Cash Generation

Our primary sources of cash are generated from operating activities, our five-year Revolving Credit Facility expiring in 2023, our CP Program, our ATM equity offering program and our ability to access the public and private capital markets through debt and equity 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 with the counterparty to meet these obligations. The cash collateral we were required to post at December 31, 2019 was not material.

DEBT, EQUITY AND LIQUIDITY

Debt

Revolving Credit Facility and CP Program

On July 30, 2018, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 30, 2023 with two one-year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. See Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.

We have a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million. See Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.

Our Revolving Credit Facility and CP Program had the following borrowings, outstanding letters of credit, and available capacity (in millions):
  CurrentShort-term borrowings atLetters of Credit atAvailable Capacity at
Credit FacilityExpirationCapacityDecember 31, 2019December 31, 2019December 31, 2019
Revolving Credit Facility and CP ProgramJuly 30, 2023$750
$350
$30
$370

The weighted average interest rate on short-term borrowings at December 31, 2019 was 2.03%. Short-term borrowing activity for the twelve months ended December 31, 2019 was:
 (dollars in millions)
Maximum amount outstanding - short-term borrowing (based on daily outstanding balances)$357
Average amount outstanding - short-term borrowing (based on daily outstanding balances)$187
Weighted average interest rates - short-term borrowing2.47%


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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. We were in compliance with these covenants as of December 31, 2019. See Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.

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.

Cross-Default Provisions

Our $7 million Corporate term loan contains 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 the 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.

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 (2.210% at December 31, 2019). 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, 2019, money pool balances included (in thousands):
Subsidiary
Borrowings From
Money Pool Outstanding
BHSC$148,041
South Dakota Electric57,585
Wyoming Electric37,993
Total Money Pool borrowings from Parent$243,619

Equity

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. The shelf registration expires in August 2020. 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, 2019, we had approximately 61 million shares of common stock outstanding and no shares of preferred stock outstanding.

ATM

In 2019, we issued a total of 1,328,332 shares of common stock under the ATM for proceeds of $99 million, net of $1.2 million in issuance costs. As of December 31, 2019, all shares were settled.


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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.

On January 29, 2020, our Board of Directors declared a quarterly dividend of $0.535 per share, equivalent to an annual dividend rate of $2.14 per share. The table below provides our historical three-year dividend payout ratio and dividends paid per share:
 201920182017
Dividend Payout Ratio63%40%50%
Dividends Per Share$2.05$1.93$1.81

Our three-year compound annualized dividend growth rate was 6.9% 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. 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 BHSC 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. 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. 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 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. See additional information in Note 6 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

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. See additional information in Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Covenants within Wyoming Electric's financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of December 31, 2019, we were in compliance with these covenants.


Financing Activities

Financing activities in 2019 consisted of the following:

We issued a total of 1.3 million shares of common stock under the ATM equity offering program for proceeds of $99 million, net of $1.2 million in issuance costs.

On October 3, 2019, we completed a public debt offering of $700 million principal amount in senior unsecured notes. The debt offering consisted of $400 million of 3.05% 10-year senior notes due October 15, 2029, and $300 million of 3.875% 30-year senior notes due October 15, 2049. Proceeds were used to repay the $400 million Corporate term loan due June 17, 2021, retire the $200 million 5.875% senior notes due July 15, 2020, and repay a portion of short-term debt.


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On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million, extended the term through June 17, 2021 and continued to have substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The net proceeds were used to pay down short-term debt. Proceeds from the October 3, 2019 debt transaction were used to repay this term loan.

Short-term borrowings from our Revolving Credit Facility and CP Program.

Future Financing Plans

We anticipate the following financing activities in 2020:

Renew our shelf registration and ATM;

Continued equity issuance under the ATM or assess other equity issuance options;

Refinance a portion of short-term borrowings held through the Revolving Credit Facility and CP Program to long-term debt; and

Continue to assess debt and equity needs to support our capital expenditure plan.

CASH FLOW ACTIVITIES

The following table summarizes our cash flows (in thousands):
 201920182017
Cash provided by (used in)   
Operating activities$505,513
$488,811
$428,261
Investing activities$(816,210)$(465,849)$(317,118)
Financing activities$300,210
$(17,057)$(108,695)

2019 Compared to 2018

Operating Activities:

Net cash provided by operating activities was $17 million higher than in 2018. The variance to the prior year was primarily attributable to:

Cash earnings (income from continuing operations plus non-cash adjustments) were $37 million higher than prior year driven primarily by higher margins at our Electric and Gas Utilities;

Net outflows from operating assets and liabilities were $25 million higher than prior year, primarily attributable to:

Cash outflows increased by approximately $40 million as a result of changes in accounts payable and accrued liabilities, driven by the impact of higher outside services, employee costs and other working capital requirements;

Cash inflows increased by approximately $59 million compared to the prior year primarily as a result of lower accounts receivable driven by lower pass-through revenues reflecting lower commodity prices; and

Cash inflows decreased by approximately $44 million primarily as a result of changes in our current regulatory liabilities due to the TCJA tax rate change that has subsequently been returned to customers and from changes in our current regulatory assets driven by lower fuel cost adjustments and the impact of lower commodity prices; and

Cash outflows decreased approximately $5.5 million due to the absence of operating activities of discontinued operations in 2019.


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Investing Activities:

Net cash used in investing activities was $816 million in 2019, compared to net cash used in investing activities of $466 million in 2018 for a variance of $350 million. This variance was primarily due to:

Capital expenditures of approximately $818 million in 2019 compared to $458 million in 2018. The $361 million increase from the prior year was due to higher capital expenditures driven by higher programmatic safety, reliability and integrity spending at our Electric and Gas Utilities segments, the Corriedale Wind Energy Project at our Electric Utilities segment, construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota, to Stegall, Nebraska, at our Electric Utilities segment, the 35-mile Natural Bridge pipeline project at our Gas Utilities segment, and construction of Busch Ranch II at our Power Generation segment; and

Net cash used in investing activities decreased $4.0 million due to prior year activities associated with divesting of our oil and gas segment.

Financing Activities:

Net cash provided by financing activities was $300 million in 2019 as compared to net cash used by financing activities of $17 million in 2018, an increase of $317 million due to the following:

Increase of $539 million due to issuances of long and short-term debt in excess of required maturities that were used to fund our capital program

Decrease of $199 million in common stock issued primarily due to prior year gross proceeds of approximately $299 million from the Equity Unit conversion partially offset by current year net proceeds of $99 million through our ATM equity offering program;

Cash dividends on common stock of $125 million were paid in 2019 compared to $107 million paid in 2018; and

Cash outflows for other financing activities increased by approximately $5.5 million driven primarily by current year financing costs incurred in the October 3, 2019 debt transaction.




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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 Key Elements of our Business Strategy above in Item 7 - Executive Summary and Business Strategy for forecasted capital expenditure requirements.

A significant portion of our capital expenditures relates to safety, reliability and integrity assets benefiting customers that may be included in utility rate base and can be recovered from our utility customers following regulatory approval. Those capital expenditures also earn a rate of return authorized by the commissions in the jurisdictions in which we operate.

Historical Capital Requirements

Our primary capital requirements for the three years ended December 31 were as follows (in thousands):
 2019 2018 2017
Property additions: (a)
     
Electric Utilities (b)
$222,911
 $152,524
 $138,060
Gas Utilities (c)
512,366
 288,438
 184,389
Power Generation (d)
85,346
 30,945
 1,864
Mining8,430
 18,794
 6,708
Corporate and Other20,702
 11,723
 6,668
Capital expenditures before discontinued operations849,755
 502,424
 337,689
Discontinued operations
 2,402
 23,222
Total capital expenditures849,755
 504,826
 360,911
Common stock dividends124,647
 106,591
 96,744
Maturities/redemptions of long-term debt905,743
 854,743
 105,743
Total capital requirements$1,880,145
 $1,466,160
 $563,398
____________________________
(a)
Includes accruals for property, plant and equipment as disclosed in Note 17 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
(b)Current year capital expenditures at our Electric Utilities segment increased due to higher programmatic safety, reliability and integrity spending, the Corriedale wind project and construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota, to Stegall, Nebraska.
(c)Current year capital expenditures at our Gas Utilities segment increased due to higher programmatic safety, reliability and integrity spending and the 35-mile Natural Bridge pipeline project.
(d)Current year capital expenditures at our Power Generation segment increased due to construction of Busch Ranch II.


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. 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. BHC notes 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.


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The following table represents the credit ratings, outlook and risk profile of BHC at December 31, 2019:
Rating AgencySenior Unsecured RatingOutlook
S&P (a)
BBB+Stable
Moody’s (b)
Baa2Stable
Fitch (c)
BBB+Stable
__________
(a)On February 28, 2019, S&P affirmed our BBB+ rating and maintained a Stable outlook.
(b)On December 20, 2019, Moody’s affirmed our Baa2 rating and maintained a Stable outlook.
(c)On August 29, 2019, Fitch affirmed our BBB+ rating and maintained a Stable outlook.

Certain of our fees and our interest rates under various bank credit agreements 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 downgraded our senior unsecured debt, we will be required to pay higher fees and interest rates under these bank credit agreements.

The following table represents the credit ratings of South Dakota Electric at December 31, 2019:
Rating AgencySenior Secured Rating
S&P (a)
A
Moody’s (b)
A1
Fitch (c)
A
__________
(a)On April 30, 2019, S&P affirmed A rating.
(b)On December 20, 2019, Moody’s affirmed A1 rating.
(c)On August 29, 2019, Fitch affirmed 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.


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CONTRACTUAL OBLIGATIONS AND OTHER COMMITMENTS

Contractual Obligations

In addition to our capital expenditure programs, we 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, 2019. Actual future obligations may differ materially from these estimated amounts (in thousands):

 Payments Due by Period
Contractual Obligations20202021202220232024ThereafterTotal
Long-term debt(a)
$5,743
$8,435
$
$525,000
$2,855
$2,635,000
$3,177,033
Interest payments (a)
131,859
131,842
131,756
131,756
109,390
1,273,648
1,910,251
Unconditional purchase obligations(b)
181,773
159,827
134,018
105,583
54,098
126,147
761,446
Lease obligations(c)
1,144
991
869
844
724
2,009
6,581
AROs (d)
330
231
144
33
9,362
54,105
64,205
Employee benefit plans(e)
18,921
19,678
19,736
19,944
19,896
35,580
133,755
CP Program349,500





349,500
Total contractual cash obligations(f)
$689,270
$321,004
$286,523
$783,160
$196,325
$4,126,489
$6,402,771
__________
(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, 2019.
(b)
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 2019 and price assumptions using existing prices at December 31, 2019. Our transmission obligations are based on filed tariffs as of December 31, 2019.
(c)Includes leases associated with several office and operating facilities, communication tower sites, equipment and materials storage.
(d)
Represents estimated payments for AROs associated with long-lived assets primarily related to retirement and reclamation of natural gas pipelines, mining sites, wind farms and an evaporation pond. See Notes 1 and 8 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
(e)
Represents estimated employer contributions to the Defined Benefit Pension Plan, the Non-Pension Defined Benefit Postretirement Healthcare Plan and the Supplemental Non-Qualified Defined Benefit Plans through the year 2029 as discussed in Note 18 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
(f)
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, 2019. These amounts have been excluded as it is impractical to reasonably estimate the final amount and/or timing of any associated payments; (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; (3) our $4.2 million liability for unrecognized tax benefits in accordance with accounting guidance for uncertain tax positions as discussed in Note 15 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Our Gas Utilities have 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, 2019, we are committed to purchase 3.7 million MMBtu, 3.7 million MMBtu, and 1.8 million MMBtu in each of the years from 2020 to 2022, respectively.

Off-Balance Sheet Commitments

We have entered into various off-balance sheet commitments in the form of guarantees and letters of credit.

Guarantees

We provide various guarantees supporting certain of our subsidiaries under specified agreements or transactions. For more information on these guarantees, see Note 20 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.


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Letters of Credit

Letters of credit reduce the borrowing capacity available on our corporate Revolving Credit Facility. For more information on these letters of credit, see Note 7 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.


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. 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 our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Regulation

Our regulated Electric and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our retail electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time.

Management continually assesses the probability of future recoveries associated with regulatory assets and future obligations associated with regulatory liabilities. Factors such as the current regulatory environment, recently issued rate orders, and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings.

To some degree, each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs) outside of a base rate review. To the extent we are able to pass through such costs to our customers, and a state 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.

As of December 31, 2019 and 2018, we had total regulatory assets of $271 million and $284 million, respectively, and total regulatory liabilities of $537 million and $541 million, respectively. See Note 13 of the Notes to the Consolidated Financial Statements for further information.


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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 our testing date with our financial planning process.   

Accounting standards for testing goodwill for impairment require a two-step process be performed 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, compares the estimated fair value of a reporting unit with its carrying amount, including goodwill. If the carrying amount exceeds fair value under the first step, then the second step of the impairment test is performed to measure the amount of any impairment loss.

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 management 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 5% to 6% and long-term growth rate projections in the 1% to 2% range were utilized in the goodwill impairment test performed in the fourth quarter of 2019. Although 1% to 2% 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. 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, 2019, 2018, and 2017, there were no impairment losses recorded. At December 31, 2019, the fair value substantially exceeded the carrying value at all reporting units.

As described in Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, we have prospectively adopted ASU 2017-04, Simplifying the Test for Goodwill Impairment, on January 1, 2020.

Pension and Other Postretirement Benefits

As described 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, one defined post-retirement healthcare plan and several non-qualified retirement plans. A Master Trust holds the assets for the pension plan. A 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 2020 pension benefit cost for our non-contributory funded pension plan is expected to be $10.2 million compared to $2.1 million in 2019. The increase in pension benefit cost is driven primarily by a decrease in the discount rate and lower expected return on assets.

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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
2019
Increase/(Decrease)
PBO/APBO (a)
 
2020
 Increase/(Decrease) Expense - Pretax
     
Pension    
Discount rate (b)
 +/- 0.5(28,998)/31,912 (3,965)/4,311
Expected return on assets +/- 0.5N/A (2,036)/2,036
     
OPEB    
Discount rate (b)
 +/- 0.5(2,836)/3,095 90/116
Expected return on assets +/- 0.5N/A (39)/39
__________________________
(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.

Income Taxes

The Company and its subsidiaries file consolidated federal income tax returns. Each entity records income taxes as if it were a separate taxpayer for both federal and state income tax purposes and consolidating adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss.

The Company uses the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements.

As of December 31, 2019, we have a regulatory liability associated with TCJA related items of $285 million, completing our accounting for the revaluation of deferred taxes pursuant to the TCJA. A significant portion 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, 2019, the Company has amortized $6.5 million of regulatory liability associated with TCJA related items. The portion that was eligible for amortization under the average rate assumption method in 2019, 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.
 
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 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

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Market Risk Disclosures

Our market risk disclosures are detailed in Note 9 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, with additional information provided in the following paragraphs.

Our exposure to the market risks detailed in Note 9 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K is also affected by other factors including the size, duration 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.

The Black Hills Corporation Risk Policies and Procedures have been approved by our Executive Risk Committee. These policies relate to numerous matters including governance, control infrastructure, authorized commodities and trading instruments, prohibited activities and employee conduct. We report any issues or concerns pertaining to the Risk Policies and Procedures to the Audit Committee of our Board of Directors. The Executive Risk Committee, which includes senior level executives, meets at least quarterly and as necessary, appropriate or desirable, to review our business and credit activities and to ensure that these activities are conducted within the authorized policies.

Electric and Gas Utilities

We produce, purchase and distribute power in four states, and purchase and distribute natural gas in six states. Our utilities have various provisions that allow them to pass the prudently-incurred cost of energy through to the customer. To the extent energy prices are higher or lower than amounts in our current billing rates, adjustments are made on a periodic basis to “true-up” billed amounts to match the actual energy cost we incurred. In Colorado, South Dakota and Wyoming, we have ECA or PCA provisions that adjust electric rates when energy costs are higher or lower than the costs included in our tariffs. In Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming, we have GCA provisions that adjust natural gas rates when our natural gas costs are higher or lower than the energy cost included in our tariffs. These adjustments are subject to periodic prudence reviews by the state utility commissions. See additional information in Note 9 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Wholesale Power

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

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, 2019, we had no interest rate swaps in place. As discussed in Item 7 - Liquidity and Capital Resources, 90% of our variable interest rate exposure has been mitigated through issuing fixed rate debt.

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.

Credit Risk

Our credit risk disclosures are detailed in Note 9 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, with additional information provided below.

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.



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New Accounting Pronouncements

See Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for information on new accounting standards adopted in 2019 or pending adoption.




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ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS





72



Management’s Report on Internal Control over Financial Reporting

We are responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2019, 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, 2019.

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, 2019. Deloitte & Touche LLP's report on Black Hills Corporation's internal control over financial reporting is included herein.

Black Hills Corporation

73







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, 2019 and 2018, the related consolidated statements of income, comprehensive income, cash flows, and equity, for each of the three years in the period ended December 31, 2019, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, 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, 2019, based on criteria established in Internal Control--Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 14, 2020, expressed an unqualified opinion on the Company’s internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Accounting--Impact of Rate Regulation on the Financial Statements--Refer to Note 1 and Note 13 to the financial statements
Critical Audit Matter Description
The Company is subject to cost-of-service regulation and earnings oversight by federal and state utility commissions (collectively, the “Commissions”), which have jurisdiction over the Company’s electric rates in Colorado, Montana, South Dakota and Wyoming and natural gas rates in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; revenue; operating expenses; and income tax benefit (expense).

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Rates are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of the costs, as reviewed and approved in a regulatory proceeding. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. While the Company has indicated its regulatory assets are probable of recovery in current rates or in future proceedings, there is a risk that the Commissions will not judge all costs to have been prudently incurred or that the rate regulation process in which rates are determined will 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) a refund or a future reduction 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 evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
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 to the Company’s recorded regulatory asset and liability balances for completeness and for any evidence that might contradict management’s assertions.
We obtained 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 a future reduction in rates.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota
February 14, 2020

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


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Black Hills Corporation

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Black Hills Corporation and subsidiaries (the "Company") as of December 31, 2019, 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, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements and financial statement schedule of the Company as of and for the year ended December 31, 2019, and our report dated February 14, 2020 expressed an unqualified opinion on those consolidated financial statements and financial statement schedule.
Basis for Opinion
The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota
February 14, 2020




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BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Year endedDecember 31, 2019December 31, 2018December 31, 2017
 (in thousands, except per share amounts)
    
Revenue$1,734,900
$1,754,268
$1,680,266
    
Operating expenses:   
Fuel, purchased power and cost of natural gas sold570,829
625,610
563,288
Operations and maintenance495,994
481,706
454,605
Depreciation, depletion and amortization209,120
196,328
188,246
Taxes - property and production52,915
51,746
51,578
Other operating expenses
1,841
5,813
Total operating expenses1,328,858
1,357,231
1,263,530
    
Operating income406,042
397,037
416,736
    
Other income (expense):   
Interest charges -   
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)(145,847)(143,720)(140,533)
Allowance for funds used during construction - borrowed6,556
2,104
2,415
Interest income1,632
1,641
1,016
Allowance for funds used during construction - equity472
619
2,321
Impairment of investment(19,741)

Other income (expense), net(6,212)(1,799)(213)
Total other income (expense)(163,140)(141,155)(134,994)
Income before income taxes242,902
255,882
281,742
Income tax benefit (expense)(29,580)23,667
(73,367)
Income from continuing operations213,322
279,549
208,375
Net (loss) from discontinued operations
(6,887)(17,099)
Net income213,322
272,662
191,276
Net income attributable to noncontrolling interest(14,012)(14,220)(14,242)
Net income available for common stock$199,310
$258,442
$177,034
    
Amounts attributable to common shareholders:   
Net income from continuing operations$199,310
$265,329
$194,133
Net (loss) from discontinued operations
(6,887)(17,099)
Net income available for common stock$199,310
$258,442
$177,034
    
Earnings (loss) per share of common stock, Basic -   
Earnings from continuing operations$3.29
$4.88
$3.65
(Loss) from discontinued operations
(0.13)(0.32)
Total earnings per share of common stock, Basic$3.29
$4.75
$3.33
    
Earnings (loss) per share of common stock, Diluted -   
Earnings from continuing operations$3.28
$4.78
$3.52
(Loss) from discontinued operations
(0.12)(0.31)
Total earnings per share of common stock, Diluted$3.28
$4.66
$3.21
    
Weighted average common shares outstanding:   
Basic60,662
54,420
53,221
Diluted60,798
55,486
55,120

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

77


BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year endedDecember 31, 2019December 31, 2018December 31, 2017
 (in thousands)
Net income$213,322
$272,662
$191,276
    
Other comprehensive income (loss), net of tax:   
Benefit plan liability adjustments - net gain (loss) (net of tax of $1,886, $(660) and $1,030, respectively)(6,253)2,155
(1,890)
Benefit plan liability adjustments - prior service costs (net of tax of $2, $0 and $0, respectively)(8)

Reclassification adjustment of benefit plan liability - net loss (net of tax of $434, $(586) and $(585), respectively)1,179
1,901
1,072
Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $19, $43 and $69, respectively)(58)(135)(128)
Derivative instruments designated as cash flow hedges:   
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(666), $(599) and$(1,029) , respectively)2,185
2,252
1,912
Net unrealized gains (losses) on commodity derivatives (net of tax of $126, $(228) and $(135), respectively)(422)755
231
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $55, $(31) and $154, respectively)(362)99
(516)
Other comprehensive income (loss), net of tax(3,739)7,027
681
    
Comprehensive income209,583
279,689
191,957
Less: comprehensive income attributable to non-controlling interest(14,012)(14,220)(14,242)
Comprehensive income available for common stock$195,571
$265,469
$177,715

See Note 16 for additional disclosures related to Comprehensive Income.

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


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BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
 As of
 December 31, 2019December 31, 2018
 (in thousands)
ASSETS  
Current assets:  
Cash and cash equivalents$9,777
$20,776
Restricted cash and equivalents3,881
3,369
Accounts receivable, net255,805
269,153
Materials, supplies and fuel117,172
117,299
Derivative assets, current342
1,500
Income tax receivable, net16,446
12,978
Regulatory assets, current43,282
48,776
Other current assets26,479
29,982
Total current assets473,184
503,833
   
Investments21,929
41,013
   
Property, plant and equipment6,784,679
6,000,015
Less accumulated depreciation and depletion(1,281,493)(1,145,136)
Total property, plant and equipment, net5,503,186
4,854,879
   
Other assets:  
Goodwill1,299,454
1,299,454
Intangible assets, net13,266
14,337
Regulatory assets, non-current228,062
235,459
Other assets, non-current19,376
14,352
Total other assets, non-current1,560,158
1,563,602
TOTAL ASSETS$7,558,457
$6,963,327

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



79


BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
(Continued)
 As of
 December 31, 2019December 31, 2018
 (in thousands, except share amounts)
LIABILITIES AND EQUITY  
Current liabilities:  
Accounts payable$193,523
$210,609
Accrued liabilities226,767
215,501
Derivative liabilities, current2,254
947
Regulatory liabilities, current33,507
29,810
Notes payable349,500
185,620
Current maturities of long-term debt5,743
5,743
Total current liabilities811,294
648,230
   
Long-term debt, net of current maturities3,140,096
2,950,835
   
Deferred credits and other liabilities:  
Deferred income tax liabilities, net360,719
311,331
Regulatory liabilities, non-current503,145
510,984
Benefit plan liabilities154,472
145,147
Other deferred credits and other liabilities124,662
109,377
Total deferred credits and other liabilities1,142,998
1,076,839
   
Commitments and contingencies (See Notes 6, 7, 8, 9, 14, 18, 19, and 20)


   
Equity:  
Stockholders’ equity -  
Common stock $1 par value; 100,000,000 shares authorized; issued: 61,480,658 and 60,048,567, respectively61,481
60,049
Additional paid-in capital1,552,788
1,450,569
Retained earnings778,776
700,396
Treasury stock at cost - 3,956 and 44,253, respectively(267)(2,510)
Accumulated other comprehensive income (loss)(30,655)(26,916)
Total stockholders’ equity2,362,123
2,181,588
Noncontrolling interest101,946
105,835
Total equity2,464,069
2,287,423
   
TOTAL LIABILITIES AND TOTAL EQUITY$7,558,457
$6,963,327

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


80


BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year endedDecember 31, 2019December 31, 2018December 31, 2017
 (in thousands)
Operating activities:   
Net income$213,322
$272,662
$191,276
Loss from discontinued operations, net of tax
6,887
17,099
Income from continuing operations213,322
279,549
208,375
Adjustments to reconcile net income to net cash provided by operating activities:   
Depreciation, depletion and amortization209,120
196,328
188,246
Deferred financing cost amortization7,838
7,845
8,261
Impairment of investment19,741


Stock compensation12,095
12,390
7,626
Deferred income taxes38,020
(24,239)80,992
Employee benefit plans12,406
14,068
10,141
Other adjustments, net16,485
5,836
(4,773)
Change in certain operating assets and liabilities:   
Materials, supplies and fuel2,052
(2,919)(10,089)
Accounts receivable and other current assets7,578
(45,966)4,534
Accounts payable and other current liabilities(34,906)5,305
(28,222)
Regulatory assets - current23,619
33,608
(15,407)
Regulatory liabilities - current(15,158)18,533
(4,536)
Contributions to defined benefit pension plans(12,700)(12,700)(27,700)
Other operating activities, net6,001
6,689
(8,418)
Net cash provided by operating activities of continuing operations505,513
494,327
409,030
Net cash provided by (used in) operating activities of discontinued operations
(5,516)19,231
Net cash provided by operating activities505,513
488,811
428,261
    
Investing activities:   
Property, plant and equipment additions(818,376)(457,524)(326,010)
Purchase of investment
(24,429)
Other investing activities2,166
(4,281)1,011
Net cash (used in) investing activities of continuing operations(816,210)(486,234)(324,999)
Net cash provided by investing activities of discontinued operations
20,385
7,881
Net cash (used in) investing activities(816,210)(465,849)(317,118)
    
Financing activities:   
Dividends paid on common stock(124,647)(106,591)(96,744)
Common stock issued101,358
300,834
4,408
Net (payments) borrowings of short-term debt163,880
(25,680)114,700
Long-term debt - issuance1,100,000
700,000

Long-term debt - repayments(905,743)(854,743)(105,743)
Distributions to noncontrolling interests(17,901)(19,617)(18,397)
Other financing activities(16,737)(11,260)(6,919)
Net cash provided by (used in) financing activities300,210
(17,057)(108,695)
    
Net change in cash, restricted cash and cash equivalents(10,487)5,905
2,448
    
Cash, restricted cash and cash equivalents beginning of year24,145
18,240
15,792
Cash, restricted cash and cash equivalents end of year$13,658
$24,145
$18,240


See Note 17 for supplemental disclosure of cash flow information.

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

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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, 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
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
Net income (loss) available for common stock




258,442

14,220
272,662
Other comprehensive income (loss), net of tax





7,027

7,027
Reclassification of certain tax effects from AOCI





740

740
Reclassification to regulatory asset





6,519

6,519
Dividends on common stock




(106,591)

(106,591)
Share-based compensation92,830
93
5,189
(204)7,301



7,190
Issuance of common stock6,371,690
6,372


292,628



299,000
Issuance costs



(15)


(15)
Dividend reinvestment and stock purchase plan4,061
4


216



220
Other stock transactions



154
(72)

82
Redemption of and distributions to noncontrolling interest






(19,617)(19,617)
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 (loss) available for common stock




199,310

14,012
213,322
Other comprehensive income (loss), net of tax





(3,739)
(3,739)
Dividends on common stock




(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 noncontrolling 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
__________________
Dividends per share paid were $2.05, $1.93 and $1.81 for the years ended December 31, 2019, 2018 and 2017, respectively.

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




82


BLACK HILLS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2019, 2018 and 2017

(1)
BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES

Business Description

Black Hills Corporation is a customer-focused, growth-oriented utility company headquartered in Rapid City, South Dakota. We are a holding company that, through our subsidiaries, conducts our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. 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. All of our operations and assets are located within the United States.

Our Electric Utilities segment includes the operating results of the regulated electric utility operations of Colorado Electric, South Dakota Electric, and Wyoming Electric, which supply regulated electric utility services to areas in Colorado, Montana, South Dakota and Wyoming. Our Gas Utilities segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming.

Most 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 Colorado, Iowa and Wyoming. Our Mining segment, which is conducted through WRDC, engages in mining activities located near Gillette, Wyoming. For further descriptions of our reportable business segments, see Note 5.

On November 1, 2017, our Board of Directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture of our Oil and Gas segment in 2018. The Oil and Gas segment assets and liabilities were classified as held for sale and the results of operations were shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which did not meet the criteria for income (loss) from discontinued operations in 2018 or 2017. 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.
 
Principles of Consolidation

The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. For additional information on intercompany revenues, see Note 5.

Our Consolidated Statements of Income include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our ownership interest in any jointly-owned electric utility generating facility, wind project or transmission tie. See Note 4 for additional information.

Variable Interest Entities

We evaluate arrangements and contracts with other entities to determine if they are VIEs and if we are the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements.

83



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 noncontrolling 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.

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 and cash equivalents. We maintain cash accounts for various specified purposes, which are classified as restricted cash.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable for our Electric and Gas Utilities business segments primarily consists of sales to residential, commercial, industrial, municipal 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. Accounts receivable for our Power Generation and Mining business segments consists of amounts due from sales of electric energy and capacity and coal.
We maintain an allowance for doubtful accounts 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.

In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accounts 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, 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.

84



Following is a summary of accounts receivable as of December 31 (in thousands):
2019Accounts Receivable, TradeUnbilled RevenueLess Allowance for Doubtful AccountsAccounts Receivable, net
Electric Utilities$41,428
$33,886
$(592)$74,722
Gas Utilities97,607
79,616
(1,683)175,540
Power Generation2,164


2,164
Mining2,277


2,277
Corporate1,271

(169)1,102
Total$144,747
$113,502
$(2,444)$255,805

2018Accounts Receivable, TradeUnbilled RevenueLess Allowance for Doubtful AccountsAccounts Receivable, net
Electric Utilities$39,721
$35,125
$(448)$74,398
Gas Utilities96,123
90,521
(2,592)184,052
Power Generation1,876


1,876
Mining3,988


3,988
Corporate5,008

(169)4,839
Total$146,716
$125,646
$(3,209)$269,153


Changes to allowance for doubtful accounts for the years ended December 31, were as follows (in thousands):
  Balance at Beginning of Year Additions Charged to Costs and Expenses Recoveries and Other Additions Write-offs and Other Deductions Balance at End of Year
2019 $3,209
 $5,795
 $3,942
 $(10,502) $2,444
2018 $3,081
 $6,859
 $4,092
 $(10,823) $3,209
2017 $2,392
 $4,926
 $8,262
 $(12,499) $3,081

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):
 20192018
Materials and supplies$82,809
$75,081
Fuel - Electric Utilities2,425
2,850
Natural gas in storage31,938
39,368
Total materials, supplies and fuel$117,172
$117,299


Materials and supplies represent parts and supplies for all of our business segments. Fuel - 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.


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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. We engaged a third-party valuation consultant to estimate the fair value of our investment. The valuation was primarily based on an income approach but also considered a market valuation approach. The significant inputs used to estimate the fair value were the oil and gas reserve quantities and values utilizing forward market price curves, industry standard reserve adjustment factors and a discount rate of 10%. Based on the results of the valuation, 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, which was the difference between the carrying amount and the fair value of the investment.

The following table presents the carrying value of our investments (in thousands) as of December 31:
 20192018
Investment in privately held oil and gas company$8,359
$28,100
Cash surrender value of life insurance contracts13,056
12,812
Other investments514
101
Total investments$21,929
$41,013



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.

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 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 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.  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, 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.

86



Our goodwill impairment analysis includes an income approach and a market approach to estimate the fair value of our reporting units. 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, long-term earnings and merger multiples for comparable companies.

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 amounts have not changed since 2016. As of December 31, 2019, 2018 and 2017, Goodwill balances were as follows (in thousands):

Electric UtilitiesGas UtilitiesPower GenerationTotal
Goodwill$248,479
$1,042,210
$8,765
$1,299,454


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):
 201920182017
Intangible assets, net, beginning balance$14,337
$7,559
$8,392
Additions (a)

7,602

Amortization expense (b)
(1,071)(824)(833)
Intangible assets, net, ending balance$13,266
$14,337
$7,559
_________________
(a)
The 2018 addition is related to the Busch Ranch 1 contract intangible asset. See Note 4 for further information.
(b)Amortization expense for existing intangible assets is expected to be $1.1 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):
 20192018
Accrued employee compensation, benefits and withholdings$62,837
$63,742
Accrued property taxes44,547
42,510
Customer deposits and prepayments54,728
43,574
Accrued interest31,868
31,759
CIAC current portion1,952
1,485
Other (none of which is individually significant)30,835
32,431
Total accrued liabilities$226,767
$215,501


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 8.

87



Fair Value Measurements

Financial Instruments

We use the following fair value hierarchy for determining inputs for our financial instruments. Our financial instruments’ assets and liabilities for financial instruments are classified and disclosed in one of the following fair value categories:

Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. Level 1 instruments primarily consist of highly liquid and actively traded financial instruments with quoted pricing information on an ongoing basis.

Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets other than quoted prices in Level 1, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3 — Pricing inputs are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments.

Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable, such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

Valuation Methodologies for Derivatives

The commodity contracts for our Electric and Gas Utilities are valued using the market approach and include Level 2 exchange-traded futures, options, basis swaps and over-the-counter swaps for natural gas contracts. For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable instrument. For over-the-counter instruments, fair value was obtained by utilizing a nationally recognized service that obtains observable inputs to compute fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a CVA based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position.

Additional information on fair value measurements is included in Notes 10, 11 and 18.

Derivatives and Hedging Activities

All our derivatives are measured at fair value and recognized as either assets or liabilities on the Consolidated Balance Sheets, except for derivative contracts that qualify for and are elected under the normal purchase and normal sales exception. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time, and price is not tied to an unrelated underlying derivative.  Normal purchase and sales contracts are recognized when the underlying physical transaction is completed under the accrual basis of accounting. As part of our Electric and Gas Utilities’ operations, we enter into contracts to buy and sell energy to meet the requirements of our customers.

In addition, certain derivatives contracts approved by regulatory authorities are either recovered or refunded through customer rates. Any changes in the fair value of these approved derivative contracts are deferred as a regulatory asset or regulatory liability pursuant to ASC 980.


88


We also have some derivatives that qualify for hedge accounting and are designated as cash flow hedges. The effective portion of the derivative gain or loss is deferred in AOCI and reclassified into earnings when the corresponding hedged transaction is recognized in earnings. Changes in the fair value of all other derivatives 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 counterpart when a legal right of offset exists.

Deferred Financing Costs

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

Regulatory Accounting

Our regulated Electric Utilities and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. Our Electric and Gas Utilities account for income and expense items in accordance with accounting standards for regulated operations. These accounting policies differ in some respects from those used by our non-regulated businesses. Under these regulated operations accounting standards:

Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates.

Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred

Management continually assesses the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders, and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings.

If changes in the regulatory environment occur, we may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from our balance sheet. Such changes could adversely affect our results of operations, financial position or cash flows.

As of December 31, 2019 and 2018, we had total regulatory assets of $271 million and $284 million respectively, and total regulatory liabilities of $537 million and $541 million respectively. See Note 13 for further information.

Income Taxes

The Company and its subsidiaries file consolidated federal income tax returns. Each entity records both federal and state income taxes as if it were a separate taxpayer and consolidating expense adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss.

We use the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements.


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It is our policy to apply the flow-through method of accounting for ITCs. Under the flow-through method, ITCs are reflected in net income as a reduction to income tax expense in the year they qualify. An exception to this general policy is the deferral method, which applies to our regulated businesses. Such a method results in the ITC being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit.

We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit on the Consolidated Statements of Income.

We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities or in Deferred income tax liabilities, net on the accompanying Consolidated Balance Sheets. See Note 15 for additional information.

Earnings per Share of Common Stock

Basic earnings per share from continuing and discontinued operations is computed by dividing Net income (loss) from continuing and discontinued operations by the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed by including all dilutive common shares outstanding during each year. Diluted common shares are primarily due to equity units, outstanding stock options, restricted stock and performance shares under our equity compensation plans.

A reconciliation of share amounts used to compute earnings per share is as follows for the years ended December 31 (in thousands):
 201920182017
    
Net income available for common stock$199,310
$258,442
$177,034
    
Weighted average shares - basic60,662
54,420
53,221
Dilutive effect of:   
Equity Units
898
1,783
Equity compensation136
168
116
Weighted average shares - diluted60,798
55,486
55,120
    
Net income available for common stock, per share - Diluted$3.28
$4.66
$3.21


The following securities were excluded from the diluted earnings per share computation for the years ended December 31 because of their anti-dilutive nature (in thousands):
 201920182017
    
Equity compensation1
16
11
Anti-dilutive shares excluded from computation of earnings per share1
16
11


Noncontrolling Interests

We account for changes in our controlling interests of subsidiaries according to ASC 810, Consolidations. ASC 810 requires that the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the noncontrolling 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.


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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.

Recently Issued Accounting Standards

Simplifying the Accounting for Income Taxes, ASU 2019-12

In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes as part of its overall simplification initiative to reduce costs and complexity in applying accounting standards while maintaining or improving the usefulness of the information provided to users of the financial 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 partially based on income. The new guidance is effective for interim and annual periods beginning after December 15, 2020 with early adoption permitted. We are currently reviewing this standard to assess the impact on our financial position, results of operations and cash flows.

Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, ASU 2018-15

In August 2018, the FASB issued ASU 2018-15, Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, which aligns the requirements for recording implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. As a result, certain categories of implementation costs that previously would have been charged to expense as incurred are now capitalized as prepayments and amortized over the term of the arrangement. The new guidance is effective for annual periods beginning after December 15, 2019, and interim periods within those fiscal years. The new guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. Early adoption is permitted. We adopted this standard prospectively on January 1, 2020. Adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

Simplifying the Test for Goodwill Impairment, ASU 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 adopted this standard prospectively on January 1, 2020. Adoption of this guidance is not expected to have any impact on our financial position, results of operations or cash flows.

Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, ASU 2018-19

In June 2016, the FASB issued ASU 2016-13, Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, which was subsequently amended by ASU 2018-19, ASU 2019-04, 2019-05, 2019-10, and 2019-11. The standard introduces new accounting guidance for credit losses on financial instruments within its scope, including trade receivables. This new guidance adds an impairment model that is based on expected losses rather than incurred losses. It is effective for interim and annual reporting periods beginning after December 15, 2019, with early adoption permitted.

We adopted this standard on January 1, 2020 with prior year comparative financial information remaining as previously reported when transitioning to the new standard. On January 1, 2020, we recorded an increase to our allowance for doubtful accounts, primarily associated with the inclusion of expected losses on unbilled revenue. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows.



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Recently Adopted Accounting Standards

Leases, ASU 2016-02

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) to increase transparency and comparability among organizations by requiring the recognition of right-of-use assets and lease liabilities on the balance sheet for most leases, whereas previously only financing-type lease liabilities (capital leases) were recognized on the balance sheet. Under the new standard, disclosures are required to meet the objective of enabling users of financial statements to assess the amount, timing and uncertainty of cash flows arising from leases.

We adopted the standard effective January 1, 2019. We elected not to recast comparative periods coinciding with the new lease standard transition and will report these comparative periods as presented under previous lease guidance. In addition, we elected the package of practical expedients permitted under the transition guidance with the new standard, which among other things, allowed us to carry forward the historical lease classification. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for existing land easement agreements.

Adoption of the new standard resulted in the recording of an operating lease right-of-use asset of $3.1 million, an operating lease obligation liability of $3.2 million, and an accrued receivable of $4.5 million, as of January 1, 2019. The cumulative effect of the adoption, net of tax impact, was $3.4 million, which was recorded as an adjustment to retained earnings at January 1, 2019.

See Note 14 for additional details on leases.

Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities, ASU 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. We have adopted this standard on January 1, 2019. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows.


(2)    REVENUE

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, 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 and Power Generation segments have 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.


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Coal supply agreements - Our Mining segment sells coal primarily under long-term contracts to utilities for use at their power generating plants, including affiliate electric utilities, and an affiliate non-regulated power generation entity. 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 Electric and Gas 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 the revenue is variable based on the units delivered or services provided.

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 reporting segments, for the years ended December 31, 2019 and 2018. Sales tax and other similar taxes are excluded from revenues.
Year ended December 31, 2019 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer types:(in thousands)
Retail$605,756
$817,840
$
$59,233
$(32,053)$1,450,776
Transportation
143,390


(1,042)142,348
Wholesale20,884

99,157

(91,577)28,464
Market - off-system sales23,817
691


(7,736)16,772
Transmission/Other57,104
47,725


(16,797)88,032
Revenue from contracts with customers707,561
1,009,646
99,157
59,233
(149,205)1,726,392
Other revenues5,191
384
2,101
2,396
(1,564)8,508
Total revenues$712,752
$1,010,030
$101,258
$61,629
$(150,769)$1,734,900







Timing of revenue recognition:





Services transferred at a point in time$
$
$
$59,233
$(32,053)$27,180
Services transferred over time707,561
1,009,646
99,157

(117,152)1,699,212
Revenue from contracts with customers$707,561
$1,009,646
$99,157
$59,233
$(149,205)$1,726,392


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Year ended December 31, 2018 Electric Utilities Gas Utilities
 Power Generation (a)
 Mining
Inter-company Revenues (a)
Total
Customer types:(in thousands)
Retail$594,329
$833,379
$
$65,803
$(32,194)$1,461,317
Transportation
140,705


(1,348)139,357
Wholesale33,687

90,791

(84,957)39,521
Market - off-system sales24,799
866


(8,102)17,563
Transmission/Other56,209
49,402


(14,827)90,784
Revenue from contracts with customers709,024
1,024,352
90,791
65,803
(141,428)1,748,542
Other revenues2,427
955
1,660
2,230
(1,546)5,726
Total revenues$711,451
$1,025,307
$92,451
$68,033
$(142,974)$1,754,268
       
Timing of revenue recognition:      
Services transferred at a point in time$
$
$
$65,803
$(32,194)$33,609
Services transferred over time709,024
1,024,352
90,791

(109,234)1,714,933
Revenue from contracts with customers$709,024
$1,024,352
$90,791
$65,803
$(141,428)$1,748,542

(a)
Due to the changes in our segment disclosures discussed in Note 5, Power Generation Wholesale revenue was revised for the year ended December 31, 2018, which resulted in an increase of $38 million. The changes to Power Generation Wholesale revenue were offset by a decrease to Power Generation Other revenues of $35 million and a decrease to eliminations in Inter-company Revenues of $3.5 million. There was no impact to our consolidated Total Revenues.

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 table above include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 842, derivative revenue under ASC 815 and alternative revenue programs revenue under ASC 980. Effective January 1, 2019, we changed how we account for the PPA between Black Hills Colorado IPP and Colorado Electric at the segment level and now recognize on an accrual basis, rather than a finance lease. See Note 5 for additional information.

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 further discussed in Note 1. We do not typically incur costs that would be capitalized to obtain or fulfill a contract.


(3)    PROPERTY, PLANT AND EQUIPMENT

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

 20192018Lives (in years)
Electric UtilitiesProperty, Plant and EquipmentWeighted Average Useful Life (in years)
Property, Plant and Equipment (b)
Weighted Average Useful Life (in years)MinimumMaximum
       
Electric plant:      
Production$1,348,049
41$1,318,643
413246
Electric transmission483,640
51437,082
514354
Electric distribution861,042
47793,725
484650
Plant acquisition adjustment (a)
4,870
324,870
323232
General259,266
28233,531
282633
Total electric plant in service2,956,867
 2,787,851
   
Construction work in progress102,268
 60,480
   
Total electric plant3,059,135
 2,848,331
   
Less accumulated depreciation and amortization(670,861) (615,365)   
Electric plant net of accumulated depreciation and amortization$2,388,274
 $2,232,966
   
_____________
(a)The plant acquisition adjustment is included in rate base and is being recovered with 11 years remaining.
(b)
Due to the changes in our segment disclosures discussed in Note 5, Total electric plant in service, Accumulated depreciation and amortization, and Electric plant net of accumulated depreciation and amortization were revised as of December 31, 2018 which resulted in an increase (decrease) of ($261) million, $91 million and ($170) million, respectively. There was no impact on our consolidated Plant, property and equipment.





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 20192018Lives (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$13,000
35$13,580
352471
Gas transmission516,172
50423,873
482267
Gas distribution1,857,233
431,595,644
423056
Cushion gas - depreciable (a)
3,539
283,539
282828
Cushion gas - not depreciable (a)
44,443
N/A46,369
N/AN/AN/A
Storage46,977
3129,335
302749
General437,054
20355,920
191024
Total gas plant in service2,918,418
 2,468,260
   
Construction work in progress63,080
 38,271
   
Total gas plant2,981,498
 2,506,531
   
Less accumulated depreciation and amortization(336,721) (279,580)   
Gas plant net of accumulated depreciation and amortization$2,644,777
 $2,226,951
   
_____________
(a)Depreciation of Cushion gas is determined by the respective regulatory jurisdiction in which the Cushion gas resides.

2019Lives (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$532,397
$2,121
$534,518
$(154,362)$380,156
31240
Mining$179,198
$1,275
$180,473
$(118,585)$61,888
13259


2018Lives (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 (a)
$435,438
$11,796
$447,234
$(137,832)$309,402
31240
Mining$175,650
$
$175,650
$(111,689)$63,961
13259
_____________
(a)
Due to the changes in our segment disclosures discussed in Note 5, Property, plant and equipment, Accumulated depreciation and amortization, and Net property, plant and equipment were revised as of December 31, 2018 which resulted in an increase (decrease) of $261 million, ($73) million and $188 million, respectively. There was no impact on our consolidated Plant, property and equipment.


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2019Lives (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
Corporate$5,721
$23,334
$29,055
$(964)$28,091
10330


2018Lives (in years)
 Property, Plant and EquipmentConstruction Work in ProgressTotal Property Plant and EquipmentLess Accumulated Depreciation and AmortizationNet Property, Plant and EquipmentWeighted Average Useful LifeMinimumMaximum
Corporate (a)
$5,721
$16,548
$22,269
$(670)$21,599
8330
___________
(a)
Due to the changes in our segment disclosures discussed in Note 5, Corporate Accumulated depreciation and amortization and Net property, plant and equipment were revised as of December 31, 2018 which resulted in an increase (decrease) of ($18) million and ($18) million respectively. There was no impact on our consolidated Plant, property and equipment.


(4)    JOINTLY OWNED FACILITIES

Our consolidated financial statements include our share of several jointly-owned utility and non-regulated 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. Each owner of the facility is responsible for financing its investment in the jointly-owned facilities.

South Dakota Electric owns a 20% interest in the Wyodak Plant, a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage 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, 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.

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), an AC-DC-AC transmission tie. Basin Electric owns the remaining ownership percentage. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the WECC and SPP regions. The total transfer capacity of the tie is 400 MW, including 200 MW from West to East and 200 MW from East to West. South Dakota Electric is committed to pay its proportionate share of the additions and replacements and operating and maintenance expenses of the transmission tie.

South Dakota Electric owns 52% of the Wygen III generation facility. MDU and the City of Gillette each owns 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. South Dakota Electric retains responsibility for plant operations. Our Mining subsidiary supplies fuel to Wygen III for the life of the plant.

Black Hills Wyoming owns 76.5% of the Wygen I plant while MEAN owns the remaining ownership percentage. 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 subsidiary during the life of the facility. Black Hills Wyoming retains responsibility for plant operations.


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At December 31, 2019, 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$116,074
$729
$(64,413)$52,390
Transmission Tie$19,862
$4,161
$(6,612)$17,411
Wygen I$120,824
$289
$(48,703)$72,410
Wygen III$146,161
$400
$(25,518)$121,043


Jointly Owned Facility - Related Party

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. On December 11, 2018, Black Hills Electric Generation purchased its 50% ownership interest in Busch Ranch I for $16 million. Colorado Electric retains responsibility for operations of the wind farm. We recorded this purchase as an asset acquisition at fair value with $8.7 million of the purchase price recorded as wind generation assets, and $7.6 million recorded as an intangible asset, reflective of the fair value of the PPA. Black Hills Electric Generation provides its share of energy from the wind farm to Colorado Electric through a PPA, which expires in October 2037.

(5)    BUSINESS SEGMENT INFORMATION

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.

Accounting standards for presentation of segments require an approach based on the way we organize the segments for making operating decisions and how the chief operating decision maker (CODM) assesses performance.  Effective January 1, 2019, we concluded that adjusted operating income, instead of net income available for common stock which was used previously, is the most relevant metric for measuring segment performance. The change to our segment performance measure resulted in a revision of the Company’s segment disclosures for all periods to report adjusted operating income as the measure of segment performance.

Prior to January 1, 2019, operating income for the Electric Utilities and Power Generation segments and Corporate and Other included the impacts of finance lease accounting relating to Colorado Electric’s PPA with Black Hills Colorado IPP. This PPA provides 200 MW of energy and capacity to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines and expires on December 31, 2031. Finance lease accounting required us to de-recognize the asset from Black Hills Colorado IPP (Power Generation segment), which legally owns the asset, and recognize it at Colorado Electric (Electric Utilities segment).

The CODM assesses the performance of our segments using adjusted operating income, which recognizes intersegment revenues, costs, and assets for Colorado Electric’s PPA with Black Hills Colorado IPP on an accrual basis rather than as a finance lease. Effective January 1, 2019, we changed how we account for this PPA at the segment level, which impacts disclosures for all periods for revenues, fuel and purchased power cost, operating income and total assets for the Electric Utilities and Power Generation segments as well as Corporate and Other. There were no revisions to Gas Utilities and Mining segments and this change had no effect on our consolidated revenues, fuel and purchased power cost, operating income or total assets.

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Segment information was as follows (in thousands):
Total Assets (net of intercompany eliminations) as of December 31,20192018
Electric Utilities (a)
$2,900,983
$2,707,695
Gas Utilities4,032,339
3,623,475
Power Generation (a)
417,715
342,085
Mining77,175
80,594
Corporate and Other130,245
209,478
Total assets$7,558,457
$6,963,327
__________________
(a)Due to the changes in our segment disclosures, Electric Utilities and Power Generation Total assets were revised as of December 31, 2018 which resulted in an increase (decrease) of ($188) million and $188 million, respectively. There was no impact on our consolidated Total assets.

Capital Expenditures (a) for the years ended December 31,
20192018
Capital expenditures  
Electric Utilities$222,911
$152,524
Gas Utilities512,366
288,438
Power Generation85,346
30,945
Mining8,430
18,794
Corporate and Other20,702
11,723
Total capital expenditures of continuing operations849,755
502,424
Total capital expenditures of discontinued operations
2,402
Total capital expenditures$849,755
$504,826
_________________
(a)
Includes accruals for property, plant and equipment as disclosed in Note 17.

Property, Plant and Equipment as of December 31,20192018
Electric Utilities (a)
$3,059,135
$2,848,331
Gas Utilities2,981,498
2,506,531
Power Generation (a)
534,518
447,234
Mining180,473
175,650
Corporate and Other29,055
22,269
Total property, plant and equipment$6,784,679
$6,000,015
_______________
(a)Due to the changes in our segment disclosures, Electric Utilities and Power Generation Property, Plant and Equipment were revised as of December 31, 2018 which resulted in an increase (decrease) of ($261) million and $261 million, respectively. There was no impact on our consolidated Property, Plant and Equipment.



98


 Consolidating Income Statement
Year ended December 31, 2019Electric UtilitiesGas UtilitiesPower GenerationMiningCorporateInter-Company EliminationsTotal
 
Revenue -






Contracts with customers$684,445
$1,007,187
$7,580
$27,180
$
$
$1,726,392
Other revenues5,191
384
1,859
1,074


8,508
 689,636
1,007,571
9,439
28,254


1,734,900
Inter-company operating revenue -






Contracts with customers23,116
2,459
91,577
32,053
230
(149,435)
Other revenues

242
1,322
343,975
(345,539)
 23,116
2,459
91,819
33,375
344,205
(494,974)
Total revenue712,752
1,010,030
101,258
61,629
344,205
(494,974)1,734,900
        
Fuel, purchased power and cost of natural gas sold268,297
425,898
9,059

268
(132,693)570,829
Operations and maintenance195,581
301,844
28,429
40,032
286,799
(303,776)548,909
Depreciation, depletion and amortization88,577
92,317
18,991
8,970
22,065
(21,800)209,120
Adjusted operating income (loss)$160,297
$189,971
$44,779
$12,627
$35,073
$(36,705)$406,042
        
Interest expense, net      (137,659)
Impairment of investment (a)
      (19,741)
Other income (expense), net      (5,740)
Income tax benefit (expense)      (29,580)
Income from continuing operations      213,322
(Loss) from discontinued operations, net of tax      
Net income      213,322
Net income attributable to noncontrolling interest      (14,012)
Net income available for common stock      $199,310

________________
(a)
In 2019 we recorded an impairment of our investment in equity securities of a privately held oil and gas company. See Note 1 for additional information.

    

99


 Consolidating Income Statement
Year ended December 31, 2018
Electric Utilities (b)
Gas Utilities
Power Generation (b)
MiningCorporate
Inter-Company Eliminations (b)
Total
  
Revenue -       
Contracts with customers$686,272
$1,022,828
$5,833
$33,609
$
$
$1,748,542
Other revenues2,427
955
1,413
931

$
5,726
 688,699
1,023,783
7,246
34,540


1,754,268
Inter-company operating revenue -      
Contracts with customers22,752
1,524
84,959
32,194
148
(141,577)
Other revenues

246
1,299
379,775
(381,320)
 22,752
1,524
85,205
33,493
379,923
(522,897)
Total revenue711,451
1,025,307
92,451
68,033
379,923
(522,897)1,754,268
        
Fuel, purchased power and cost of natural gas sold283,840
462,153
8,592

44
(129,019)625,610
Operations and maintenance186,175
291,481
25,135
43,728
324,916
(336,142)535,293
Depreciation, depletion and amortization85,567
86,434
16,110
7,965
21,161
(20,909)196,328
Adjusted operating income (loss)155,869
185,239
42,614
16,340
33,802
(36,827)397,037
 






Interest expense, net      (139,975)
Other income (expense), net      (1,180)
Income tax benefit (expense) (a)
      23,667
Income from continuing operations      279,549
(Loss) from discontinued operations, net of tax      (6,887)
Net income      272,662
Net income attributable to noncontrolling interest      (14,220)
Net income available for common stock      $258,442
        

________________
(a)
Income tax benefit (expense) includes a tax benefit of $73 million resulting from legal entity restructuring. See Note 15.
(b)Due to changes in our segment disclosures, Adjusted operating income and related income statement accounts were revised for the year ended December 31, 2018, which resulted in an increase (decrease) as follows (in millions):
Year ended December 31, 2018Electric UtilitiesPower GenerationInter-Company EliminationsTotal
Inter-company operating revenue - Contracts with customers$
$3.5
$(3.5)$
Fuel, purchased power and cost of natural gas sold6.7

(6.7)
Depreciation, depletion and amortization(13.1)9.2
3.9

Adjusted operating income (loss)$6.4
$(5.7)$(0.7)$




100


 Consolidating Income Statement
Year ended December 31, 2017
Electric Utilities (b)
Gas Utilities
Power Generation (b)
MiningCorporate
Inter-Company Eliminations (b)
Total
  
Revenue$689,945
$947,595
$7,263
$35,463
$
$
$1,680,266
Inter-company revenue14,705
35
87,357
31,158
344,685
(477,940)
Total revenue704,650
947,630
94,620
66,621
344,685
(477,940)1,680,266
        
Fuel, purchased power and cost of natural gas sold274,363
409,603
9,340

151
(130,169)563,288
Operations and maintenance172,307
269,190
23,042
44,882
296,067
(293,492)511,996
Depreciation, depletion and amortization80,243
83,732
15,548
8,239
21,031
(20,547)188,246
Adjusted operating income (loss)177,737
185,105
46,690
13,500
27,436
(33,732)416,736
 






Interest expense, net      (137,102)
Other income (expense), net      2,108
Income tax benefit (expense)      (73,367)
Income from continuing operations      208,375
(Loss) from discontinued operations, net of tax(a)
      (17,099)
Net income      191,276
Net income attributable to noncontrolling interest      (14,242)
Net income available for common stock      $177,034

________________
(a)
Discontinued operations includes oil and gas property impairments. See Note 21.
(b)Due to changes in our segment disclosures, Adjusted operating income and related income statement accounts were revised for the year ended December 31, 2017, which resulted in an increase (decrease) as follows (in millions):
Year ended December 31, 2017Electric UtilitiesPower GenerationInter-Company EliminationsTotal
Inter-company revenue$
$3.1
$(3.1)$
Fuel, purchased power and cost of natural gas sold6.0

(6.0)
Depreciation, depletion and amortization(13.1)9.6
3.5

Adjusted operating income (loss)$7.1
$(6.5)$(0.6)$





101


(6)    LONG-TERM DEBT

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


Interest Rate atBalance Outstanding
 Due DateDecember 31, 2019December 31, 2019December 31, 2018
Corporate    
Senior unsecured notes due 2023November 30, 20234.25%$525,000
$525,000
Senior unsecured notes due 2020July 15, 2020N/A
200,000
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 2033May 1, 20334.35%400,000
400,000
Senior unsecured notes, due 2046September 15, 20464.20%300,000
300,000
Senior unsecured notes, due 2029October 15, 20293.05%400,000

Senior unsecured notes, due 2049October 15, 20493.88%300,000

Corporate term loan due 2021 (a)
June 17, 2021N/A
300,000
Corporate term loan due 2021June 7, 20212.32%7,178
12,921
Total Corporate debt  2,632,178
2,437,921
Less unamortized debt discount  (6,462)(5,122)
Total Corporate debt, net  2,625,716
2,432,799
     
South Dakota Electric    
Series 94A Debt, variable rate (b)
June 1, 20241.84%2,855
2,855
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 debt  342,855
342,855
Less unamortized debt discount  (82)(86)
Total South Dakota Electric debt, net  342,773
342,769
     
Wyoming Electric    
Industrial development revenue bonds due 2021(a)
September 1, 20211.68%7,000
7,000
Industrial development revenue bonds due 2027(a)
March 1, 20271.68%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 debt  202,000
202,000
Less unamortized debt discount  

Total Wyoming Electric debt, net  202,000
202,000
     
Total long-term debt  3,170,489
2,977,568
Less current maturities  5,743
5,743
Less unamortized deferred financing costs (b)
  24,650
20,990
Long-term debt, net of current maturities and deferred financing costs  $3,140,096
$2,950,835
_______________
(a)Variable interest rate.
(b)Includes deferred financing costs associated with our Revolving Credit Facility of $1.7 million and $2.3 million as of December 31, 2019 and December 31, 2018, respectively.

102


Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands):
2020$5,743
2021$8,435
2022$
2023$525,000
2024$2,855
Thereafter$2,635,000


Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2019.

Substantially all of the tangible utility property of South Dakota Electric and Wyoming Electric is subject to the lien of indentures securing their first mortgage bonds. First mortgage bonds of South Dakota Electric and Wyoming Electric may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures.

Debt Transactions

On October 3, 2019, we completed a public debt offering of $700 million principal amount in senior unsecured noted. The debt offering consisted of $400 million of 3.05% 10-year senior notes due October 15, 2029 and $300 million of 3.875% 30-year senior notes due October 15, 2049 (together the “Notes”). The proceeds of the Notes were used for the following:

• Repay the $400 million Corporate term loan under the Amended and Restated Credit Agreement due June 17, 2021;

• Retire the $200 million 5.875% senior notes due July 15, 2020; and

• Repay a portion of short-term debt.

On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million, extended the term through June 17, 2021, and had substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The net proceeds from the increase in total commitments were used to pay down short-term debt. Proceeds from the October 3, 2019 public debt offering were used to repay this term loan.

On December 12, 2018, we paid off the $250 million, 2.5% senior unsecured notes due January 11, 2019. Proceeds from the November 1, 2018 Equity Unit conversion were used to pay off this debt.

On August 17, 2018, we issued $400 million principal amount, 4.350% senior unsecured notes due May 1, 2033. A portion of these notes were issued in a private exchange that resulted in the retirement of all $299 million principal amount of our RSNs due 2028. The remainder of the notes were sold for cash in a public offering, with the net proceeds being used to pay down short-term debt.

The issuance of the $400 million senior notes was the culmination of a series of transactions that also included the contractually required remarketing of such RSNs on behalf of the holders of our Equity Units, with the proceeds being deposited as collateral to secure the obligations of those holders under the purchase contracts included in the Equity Units (see Note 12). As a result of the remarketing, the annual interest rate on such RSNs was automatically reset to 4.579% (however, because the RSNs were then immediately retired, no interest accrued at this reset rate).

On July 30, 2018, we amended and restated our unsecured term loan due August 2019. This amended and restated term loan, with $300 million outstanding at December 31, 2018, had a maturity date of July 30, 2020 and had substantially similar terms and covenants as the amended and restated Revolving Credit Facility. This term loan was later amended on June 17, 2019 and then repaid using proceeds from the October 3, 2019 public debt offering.


103



Amortization Expense

Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income were as follows (in thousands):
Deferred Financing Costs Remaining at Amortization Expense for the years ended December 31,
December 31, 2019 201920182017
$24,650
 $3,242
$2,829
$3,349


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. As of December 31, 2019, 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, 2019:

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, 2019, the restricted net assets at our Electric and Gas Utilities were approximately $156 million.

Wyoming Electric and South Dakota Electric are generally limited to the amount of dividends allowed to be paid to our utility holding company under certain financing agreements. 


(7)    NOTES PAYABLE

We had the following short-term debt outstanding at the Consolidated Balance Sheets date (in thousands):
 December 31, 2019December 31, 2018
 Balance Outstanding
Letters of Credit (a)
Balance Outstanding
Letters of Credit (a)
Revolving Credit Facility$
$30,274
$
$22,311
CP Program349,500

185,620

Total$349,500
$30,274
$185,620
$22,311

_______________
(a)Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility.

Revolving Credit Facility and CP Program

On July 30, 2018, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 30, 2023 with 2 one year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments 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 Corporate credit rating from S&P, Fitch, and Moody's for our senior unsecured long-term debt. Based on our 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, 2019. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at December 31, 2019.


104


We have a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million. The notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration exemption.

Our net short-term borrowings (payments) during 2019 were $164 million. As of December 31, 2019, the weighted average interest rate on short-term borrowings was 2.03%.

Total accumulated deferred financing costs on the Revolving Credit Facility of $6.7 million are being amortized over its estimated useful life and were included in Interest expense on the accompanying Consolidated Statements of Income. See Note 6 above for additional details.

Debt Covenants

Under our 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 Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness, which includes letters of credit and certain guarantees issued by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interest in subsidiaries. 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. As of December 31, 2019, we were in compliance with these covenants.


(8)    ASSET RETIREMENT OBLIGATIONS

We have identified legal retirement obligations related to reclamation of mining sites in the Mining segment and removal of fuel tanks, transformers containing polychlorinated biphenyls, and an evaporation pond at our Electric Utilities, wind turbines at our Electric Utilities and Power Generation segments, retirement of gas pipelines at our Gas Utilities and removal of asbestos at our Electric and Gas Utilities. We periodically review and update estimated costs related to these AROs. 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 included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands):
 December 31, 2018Liabilities IncurredLiabilities SettledAccretion
Revisions to Prior Estimates (a) (b)
December 31, 2019
Electric Utilities (c)
$6,258
$
$
$385
$2,686
$9,329
Gas Utilities34,627


1,458

36,085
Power Generation (c)
300
3,445

158
836
4,739
Mining15,615

(380)740
(1,923)14,052
Total$56,800
$3,445
$(380)$2,741
$1,599
$64,205


105



 December 31, 2017Liabilities IncurredLiabilities SettledAccretion
Revisions to Prior Estimates (b)
December 31, 2018
Electric Utilities$6,287
$
$
$269
$2
$6,558
Gas Utilities33,238
152

1,237

34,627
Mining12,499

(4)649
2,471
15,615
Total$52,024
$152
$(4)$2,155
$2,473
$56,800
_____________________
(a)The increase in Electric Utilities Revisions to Prior Estimates was primarily driven by an increase to the estimated cost to decommission certain regulated wind farm assets.
(b)The changes in the Mining Revision to Prior Estimates were primarily driven by changes in estimated costs associated with back-filling the pit with overburden removed during the mining process.
(c)We reclassified $0.3 million of ARO as of December 31, 2018 related to Busch Ranch I from Electric Utilities to the Power Generation segment as a result of Black Hills Electric Generation’s purchase of its 50% ownership interest in Busch Ranch I. Additional liabilities were incurred in 2019 from new wind assets.

We also have legally required AROs related to certain assets within our electric transmission and distribution systems. These retirement obligations are pursuant to an easement or franchise agreement and are only required if we discontinue our utility service under such easement or franchise agreement. Accordingly, it is not possible to estimate a time period when these obligations could be settled and therefore, a liability for the cost of these obligations cannot be measured at this time.


(9)    RISK MANAGEMENT ACTIVITIES

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. Valuation methodologies for our derivatives are detailed within Note 1.

Market Risk

Market risk is the potential loss that may occur as a result of an adverse change in market price, rate or supply. We are exposed to the following market risks, including, but not limited to:

Commodity price risk associated with our retail natural gas marketing activities and our fuel procurement for several of our gas-fired generation assets, which include market fluctuations due to unpredictable factors such as weather, market speculation, pipeline constraints, and other factors that may impact natural gas supply and demand;

Interest rate risk associated with our variable debt as described in Notes 6 and 7.

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 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, 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 and any specific customer collection issue that is identified.

Our credit exposure at December 31, 2019 was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies. Our derivative and hedging activities included in the accompanying Consolidated Balance Sheets, Consolidated Statements of Income and Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 10.

106


Utilities

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. Therefore, as allowed or required by state utility commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, options, over-the-counter swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP.

For our regulated Utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Consolidated Balance Sheets in accordance with the state utility commission guidelines. When the related costs are recovered through our rates, the hedging activity is 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/or sales during time frames ranging from January 2020 through December 2021. 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 the ineffective portion, if any, is reported in Fuel, purchased power and cost of natural gas sold. Effectiveness of our hedging position is evaluated at least quarterly.

The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our Utilities are comprised of both short and long positions. We had the following net long positions as of:
 December 31, 2019December 31, 2018
 Notional (MMBtus)
Maximum Term (months) (a)
Notional (MMBtus)
Maximum Term (months) (a)
Natural gas futures purchased1,450,000
124,000,000
24
Natural gas options purchased, net3,240,000
34,320,000
13
Natural gas basis swaps purchased1,290,000
123,960,000
24
Natural gas over-the-counter swaps, net (b)
4,600,000
243,660,000
24
Natural gas physical commitments, net (c)
13,548,235
1218,325,852
30

__________
(a)Term reflects the maximum forward period hedged.
(b)As of December 31, 2019, 1,415,000 MMBtus of natural gas over-the-counter swaps purchased were designated as cash flow hedges.
(c)Volumes exclude contracts that qualify for normal purchase, normal sales exception.

Based on December 31, 2019 prices, a $0.5 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.


107


Cash Flow Hedges

The impact of cash flow hedges on our Consolidated Statements of Income is presented below for the years ended December 31, 2019, 2018 and 2017 (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.
 December 31, 2019
Derivatives in Cash Flow Hedging RelationshipsLocation of Reclassifications from AOCI into IncomeAmount of Gain/(Loss) Reclassified from AOCI into Income
   
Interest rate swapsInterest expense$(2,851)
Commodity derivativesFuel, purchased power and cost of natural gas sold417
Total impact from cash flow hedges $(2,434)

 December 31, 2018
Derivatives in Cash Flow Hedging RelationshipsLocation of Reclassifications from AOCI into IncomeAmount of Gain/(Loss) Reclassified from AOCI into Income
   
Interest rate swapsInterest expense$(2,851)
Commodity derivativesFuel, purchased power and cost of natural gas sold(130)
Total impact from cash flow hedges $(2,981)

 December 31, 2017
Derivatives in Cash Flow Hedging RelationshipsLocation of Reclassifications from AOCI into IncomeAmount of Gain/(Loss) Reclassified from AOCI into Income
   
Interest rate swapsInterest expense$(2,941)
Commodity derivativesNet (loss) from discontinued operations913
Commodity derivativesFuel, purchased power and cost of natural gas sold(243)
Total impact from cash flow hedges $(2,271)

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, 2019, 2018 and 2017 (in thousands).

 December 31, 2019December 31, 2018December 31, 2017
  
Increase (decrease) in fair value:   
Forward commodity contracts$(548)$983
$366
Recognition of (gains) losses in earnings due to settlements:   
Interest rate swaps2,851
2,851
2,941
Forward commodity contracts(417)130
(670)
Total other comprehensive income (loss) from hedging$1,886
$3,964
$2,637



108


Derivatives Not Designated as Hedge Instruments

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income for the years ended December 31, 2019, 2018 and 2017 (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.
  December 31, 2019December 31, 2018December 31, 2017
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 derivativesFuel, purchased power and cost of natural gas sold$(1,100)$1,101
$(2,207)
  $(1,100)$1,101
$(2,207)


As discussed above, financial instruments used in our regulated 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 hedges in our Utilities were $3.3 million and $6.2 million at December 31, 2019 and 2018, respectively.


(10)    FAIR VALUE MEASUREMENTS

Nonrecurring Fair Value Measurement

A discussion of the fair value of our investment in equity securities of a privately held oil and gas company, a Level 3 asset, is included in Note 1.

Recurring Fair Value Measurements

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.

A discussion of fair value of financial instruments is included in Note 11. 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):
 As of December 31, 2019
 Level 1Level 2Level 3 Cash Collateral and Counterparty NettingTotal
Assets:      
Commodity derivatives - Utilities$
$1,433
$
 $(1,085)$348
Total$
$1,433
$
 $(1,085)$348
       
Liabilities:      
Commodity derivatives - Utilities$
$5,254
$
 $(2,909)$2,345
Total$
$5,254
$
 $(2,909)$2,345




109


 As of December 31, 2018
 Level 1Level 2Level 3 Cash Collateral and Counterparty NettingTotal
Assets:      
Commodity derivatives - Utilities$
2,927
$
 $(1,408)$1,519
Total$
$2,927
$
 $(1,408)$1,519
       
Liabilities:      
Commodity derivatives - Utilities$
$6,801
$
 $(5,794)$1,007
Total$
$6,801
$
 $(5,794)$1,007

     

   

Fair Value Measures 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 permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements and the impact of legally enforceable 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):
  December 31,
 Balance Sheet Location20192018
Derivatives designated as hedges:   
Asset derivative instruments:   
Current commodity derivativesDerivative assets - current$1
$415
Noncurrent commodity derivativesOther assets, non-current3
18
Liability derivative instruments:   
Current commodity derivativesDerivative liabilities - current(490)(114)
Noncurrent commodity derivativesOther deferred credits and other liabilities(29)(4)
Total derivatives designated as hedges$(515)$315
    
Not designated as hedges:   
Asset derivative instruments:   
Current commodity derivativesDerivative assets - current$341
$1,085
Noncurrent commodity derivativesOther assets, non-current2
1
Liability derivative instruments:   
Current commodity derivativesDerivative liabilities - current(1,764)(833)
Noncurrent commodity derivativesOther deferred credits and other liabilities(63)(56)
Total derivatives not designated as hedges$(1,484)$197



110


Derivatives Offsetting

It is our policy to offset, in our 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, 2019 and 2018, 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, 2019 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
Commodity derivative assets subject to a master netting agreement or similar arrangement$1,085
$(1,085)$
Commodity derivative assets not subject to a master netting agreement or similar arrangement348

348
Total derivative assets$1,433
$(1,085)$348

Derivative LiabilitiesGross Amounts of Derivative LiabilitiesGross Amounts Offset on Consolidated Balance SheetsNet Amount of Total Derivative Liabilities on Consolidated Balance Sheets
Commodity derivative liabilities subject to a master netting agreement or similar arrangement$2,908
$(2,908)$
Commodity derivative liabilities not subject to a master netting agreement or similar arrangement2,345

2,345
Total derivative liabilities$5,253
$(2,908)$2,345

Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of December 31, 2018 were 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
Commodity derivative assets subject to a master netting agreement or similar arrangement$1,408
$(1,408)$
Commodity derivative assets not subject to a master netting agreement or similar arrangement1,519

1,519
Total derivative assets$2,927
$(1,408)$1,519

Derivative LiabilitiesGross Amounts of Derivative LiabilitiesGross Amounts Offset on Consolidated Balance SheetsNet Amount of Total Derivative Liabilities on Consolidated Balance Sheets
Commodity derivative liabilities subject to a master netting agreement or similar arrangement$5,794
$(5,794)$
Commodity derivative liabilities not subject to a master netting agreement or similar arrangement1,007

1,007
Total derivative liabilities$6,801
$(5,794)$1,007



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(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):
 20192018
 Carrying AmountFair ValueCarrying AmountFair Value
Cash and cash equivalents (a)
$9,777
$9,777
$20,776
$20,776
Restricted cash and equivalents (a)
$3,881
$3,881
$3,369
$3,369
Notes payable (b)
$349,500
$349,500
$185,620
$185,620
Long-term debt, including current maturities (c)
$3,145,839
$3,479,367
$2,956,578
$3,039,108

_______________
(a)Carrying value approximates fair value. Cash, cash equivalents, and restricted cash are classified in Level 1 in the fair value hierarchy.
(b)Notes payable consist of commercial paper borrowings. 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. 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

At-the-Market Equity Offering Program

Our ATM equity offering program allows us to sell shares of our common stock with an aggregate value of up 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. During the twelve months ended December 31, 2019, we issued a total of 1,328,332 shares of common stock under the ATM equity offering program for $99 million, net of $1.2 million in issuance costs. As of December 31, 2019, all shares were settled. We did not issue any common shares under the ATM equity offering program during the twelve months ended December 31, 2018 and 2017.

Equity Units

On November 23, 2015, we issued 5.98 million Equity Units for total gross proceeds of $299 million. Each Equity Unit had a stated amount of $50.00 and consisted 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.


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On October 29, 2018, we announced the settlement rate for the stock purchase contracts that are components of the Equity Units issued on November 23, 2015. The settlement rate was based upon the minimum settlement rate, as adjusted to account for past dividends, because the average of the closing price per share of BHC common stock on the New York Stock Exchange for the 20 consecutive trading days ending on October 29, 2018 exceeded the threshold appreciation price. Each holder of the Equity Units on that date, following payment of $50.00 for each unit which it holds, received 1.0655 shares of BHC common stock for each such unit. The holders' obligations to make such payments were satisfied with proceeds generated by the successful remarketing on August 17, 2018, of the RSNs that formerly constituted a component of the Equity Units. See Note 6 for additional information.

Upon settlement of all outstanding stock purchase obligations, the Company received gross proceeds of approximately $299 million in exchange for approximately 6.372 million shares of common stock. Proceeds were used to pay down the $250 million senior unsecured notes due January 11, 2019, with the balance used to pay down short-term debt.

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 672,049 shares available to grant at December 31, 2019.

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, 2019, total unrecognized compensation expense related to non-vested stock awards was approximately $12 million and is expected to be recognized over a weighted-average period of 2 years. Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income was as follows for the years ended December 31 (in thousands):
 201920182017
Stock-based compensation expense$12,095
$12,390
$7,626

Stock Options

The Company has not issued any stock options since 2014 and has 14,000 stock options outstanding at December 31, 2019. 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, 2019, was as follows:
 Restricted StockWeighted-Average Grant Date Fair Value
 (in thousands) 
Balance at beginning of period236
$57.50
Granted92
73.66
Vested(120)56.33
Forfeited(16)62.02
Balance at end of period192
$65.66



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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)
2019$73.66
$8,438
2018$57.31
$6,776
2017$60.63
$7,909


As of December 31, 2019, there was $9.0 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 2.1 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 $2.9 million at December 31, 2019 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, 2017January 1, 2017 - December 31, 2019460%200%
January 1, 2018January 1, 2018 - December 31, 2020500%200%
January 1, 2019January 1, 2019 - December 31, 2021370%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, 2019
 (in thousands) (in thousands) 
Performance Shares balance at beginning of period77
$57.66
77
 
Granted20
68.72
20
 
Forfeited(4)64.60
(4) 
Vested(26)47.76
(26) 
Performance Shares balance at end of period67
$64.32
67
$89.63
_____________________
(a)The grant date fair values for the performance shares granted in 2019, 2018 and 2017 were determined by Monte Carlo simulation using a blended volatility of 21%, 21% and 23%, 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.


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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, 2019$68.72
December 31, 2018$61.82
December 31, 2017$63.52

Performance plan payouts have been as follows (in thousands):
Performance PeriodYear PaidStock IssuedCash PaidTotal Intrinsic Value
January 1, 2016 to December 31, 2018201944
$2,860
$5,720
January 1, 2015 to December 31, 2017 


January 1, 2014 to December 31, 2016 





On January 28, 2020, the Compensation Committee of our Board of Directors determined that the Company’s total shareholder return for the January 1, 2017 through December 31, 2019 performance period was at the 36.3 percentile of its peer group and confirmed a payout equal to 58.86% of target shares, valued at $2.2 million. The payout was fully accrued at December 31, 2019.

As of December 31, 2019, there was $3.4 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 until March 1, 2018, after which we began purchasing shares on the open market. At December 31, 2019, there were 214,967 shares of unissued stock available for future offering under the plan.

Preferred Stock

Our articles of incorporation authorize the issuance of 25 million shares of preferred stock of which we had 0 shares of preferred stock outstanding.

Noncontrolling Interest in Subsidiary

Black Hills Colorado IPP owns and operates a 200 MW, combined-cycle natural gas generating facility located in Pueblo, Colorado. In April 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million to a third-party buyer. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Colorado Electric.

The accounting for a partial sale of a subsidiary in which control is maintained and the subsidiary continues to be consolidated, is specified under ASC 810. The partial sale is required to be recorded as an equity transaction with no resulting gain or loss on the sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. Distributions of net income attributable to noncontrolling interests 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, 2019, 2018 and 2017 was reduced by $14 million, $14 million, and $14 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.


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Black Hills Colorado IPP has been determined to be a VIE in which the Company has a variable interest. Black Hills Electric Generation has been determined to be the primary beneficiary of the VIE as Black Hills Electric Generation is the operator and manager of the generation facility and, as such, has the power to direct the activities that most significantly impact Black Hills Colorado IPP’s economic performance. Black Hills Electric Generation, as the primary beneficiary, continues to consolidate Black Hills Colorado IPP. Black Hills Colorado IPP has not received financial or other support from the Company outside of pre-existing contractual arrangements during the reporting period. Black Hills Colorado IPP does not have any debt and its cash flows from operations are sufficient to support its ongoing operations.

We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above as of December 31 (in thousands):
 2019 2018
Assets   
Current assets$13,350
 $13,620
Property, plant and equipment of variable interest entities, net$193,046
 $199,839
    
Liabilities   
Current liabilities$6,013
 $5,174



(13)    REGULATORY MATTERS

We had the following regulatory assets and liabilities as of December 31 (in thousands):
 20192018
Regulatory assets  
Deferred energy and fuel cost adjustments (a)
$34,088
$29,661
Deferred gas cost adjustments (a)
1,540
3,362
Gas price derivatives (a)
3,328
6,201
Deferred taxes on AFUDC (b)
7,790
7,841
Employee benefit plans (c)
115,900
110,524
Environmental (a)
1,454
959
Loss on reacquired debt (a)
24,777
21,001
Renewable energy standard adjustment (a)
1,622
1,722
Deferred taxes on flow through accounting (c)
41,220
31,044
Decommissioning costs (a)
10,670
11,700
Gas supply contract termination (a)
8,485
14,310
Other regulatory assets (a)
20,470
45,910
Total regulatory assets271,344
284,235
Less current regulatory assets(43,282)(48,776)
Regulatory assets, non-current$228,062
$235,459
   
Regulatory liabilities  
Deferred energy and gas costs (a)
$17,278
$6,991
Employee benefit plan costs and related deferred taxes (c)
43,349
42,533
Cost of removal (a)
166,727
150,123
Excess deferred income taxes (c)
285,438
310,562
TCJA revenue reserve3,418
18,032
Other regulatory liabilities (c)
20,442
12,553
Total regulatory liabilities536,652
540,794
Less current regulatory liabilities(33,507)(29,810)
Regulatory liabilities, non-current$503,145
$510,984
__________
(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.

116



Regulatory assets represent items we expect to recover from customers through probable future rates.

Deferred Energy and Fuel Cost Adjustments - 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 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. The recovery period for these costs is less than a year.

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. The recovery period for these costs is less than a year.

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. Gas price derivatives at December 31, 2019 are hedged over a maximum forward term of two years.

Deferred Taxes on AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a regulator’s action, it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment.

Employee Benefit Plans - 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.

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.

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. In 2018, Arkansas Gas received approval to record Liquefied Natural Gas Plant decommissioning costs in a regulatory asset, with recovery to be determined in a future regulatory filing.


117


Gas Supply Contract Termination - Agreements under the previous ownership 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 Colorado, Nebraska, 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, which 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 CPUC, NPSC and WPSC on the basis that these agreements were 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 was recorded as an excess deferred income tax to be refunded to customers primarily using the normalization principles as prescribed in the TCJA.

TCJA Revenue Reserve - Revenue to be returned to customers as a result of the TCJA. See Note 15 for additional information.

Regulatory Matters

Electric Utilities Regulatory Activity

South Dakota Electric

Settlement

On January 7, 2020, South Dakota Electric received approval from the SDPUC on a settlement agreement to extend the 6-year moratorium period by an additional 3 years to June 30, 2026. Also, as part of the settlement, we withdrew our application for deferred accounting treatment and expensed $5.4 million of development costs related to projects we no longer intend to construct. This settlement amends a previous agreement approved by the SDPUC on June 16, 2017, whereby South Dakota Electric would not increase base rates, absent an extraordinary event, for a 6 year moratorium period effective July 1, 2017. The moratorium period also includes suspension of both the TFA and EIA.

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, 2019 the annual revenue requirement increased by $1.9 million and included estimated weighted average capital additions of $31 million for 2018 and 2019 combined. The annual transmission revenue requirement has a true up mechanism that is posted in June of each year.


118


South Dakota Electric and Wyoming Electric

Renewable Ready

In July 2019, South Dakota Electric and Wyoming Electric received approvals for the Renewable Ready program and related jointly-filed CPCN to construct Corriedale. The wind project will be jointly owned by the two electric utilities to deliver renewable energy for large commercial, industrial and governmental agency customers. In November 2019, South Dakota Electric received approval from the SDPUC to increase the offering under the program by 12.5 MW. The 2 electric utilities also received a determination from the WPSC to increase the project to 52.5 MW. The $79 million project is expected to be in service by year-end 2020.
 
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