0001130464 us-gaap:InterestRateSwapMember us-gaap:AccumulatedNetGainLossFromDesignatedOrQualifyingCashFlowHedgesMember 2018-12-31

Table of Contents


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC  20549
Form 10-K
x☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2016
For the fiscal year ended
December 31, 2019
oOr
☐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
For the transition period from ___________________ to __________________

Commission File Number 001-31303

BLACK HILLS CORPORATION
BLACK HILLS CORPORATION
Incorporated inSouth Dakota625 Ninth StreetIRS Identification Number46-0458824
 Rapid City, South Dakota  5770146-0458824
7001 Mount Rushmore Road
Rapid CitySouth 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
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☐
Yes           x           No           o

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           o           No           x

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           x           No           o

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).
Yes           x           No           o

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

Indicate by check mark whether the Registrantregistrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, (as definedor 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).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
Large accelerated filer    x
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Accelerated filer    o
Yes
Non-accelerated filer   o
☐
Smaller reporting company o
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 by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes           o           No           x

State the aggregate market value of the voting stock held by non-affiliates of the Registrant.
At June 30, 2016                                  $3,248,873,889

Indicate the number of shares outstanding of each of the Registrant’s classes of common stock, as of the latest practicable date.
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.
ClassOutstanding at January 31, 20172020
Common stock, $1.00 par value53,384,25961,475,403

shares

Documents Incorporated by Reference
Portions of the Registrant’sregistrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 20172020 Annual Meeting of Stockholders to be held on April 25, 2017,28, 2020, are incorporated by reference in Part III of this Form 10-K.






TABLE OF CONTENTS


   Page
GLOSSARY OF TERMS AND ABBREVIATIONS
3
WEBSITE ACCESS TO REPORTS
8
FORWARD-LOOKING INFORMATION
8
Part I
   
WEBSITE ACCESS TO REPORTS
ITEMS 1. and 2.
8BUSINESS AND PROPERTIES
9
 
History and Organization
9
Electric Utilities
9
Gas Utilities
17
Utility Regulation Characteristics
22
Power Generation
23
Mining
25
Environmental Matters
27
Other Properties
28
Employees
29
ITEM 1A.
RISK FACTORS
29
ITEM 1B.
UNRESOLVED STAFF COMMENTS
37
ITEM 3.
LEGAL PROCEEDINGS
37
ITEM 4.
MINE SAFETY DISCLOSURES
37
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
38
Part II
   
FORWARD-LOOKING INFORMATION
ITEM 5.
8
Part I
ITEMS 1. and 2.BUSINESS AND PROPERTIES
8
ITEM 1A.RISK FACTORS
57
ITEM 1B.UNRESOLVED STAFF COMMENTS
69
ITEM 3.LEGAL PROCEEDINGS
69
ITEM 4.MINE SAFETY DISCLOSURES
69
Part II
ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
7039
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
7140
ITEMS 7. and 7A.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
7442
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
12272
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
204143
ITEM 9A.
CONTROLS AND PROCEDURES
143
ITEM 9B.
OTHER INFORMATION
143
Part III
   
ITEM 9A.
CONTROLS AND PROCEDURES10.
204
ITEM 9B.OTHER INFORMATION
204
Part III
ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
205144
ITEM 11.
EXECUTIVE COMPENSATION
144
ITEM 11.
EXECUTIVE COMPENSATION12.
205
ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
206144
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
206144
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
144
Part IV
   
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES15.
206
Part IV
ITEM 15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES
207145
ITEM 16.
ITEM 16.
FORM 10-K SUMMARY
212148
SIGNATURES
SIGNATURES
213149
INDEX TO EXHIBITS
214


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
AltaGasAltaGas Renewable Energy Colorado LLC, a subsidiary of AltaGas Ltd.
AOCIAccumulated Other Comprehensive Income
APSCArkansas Public Service Commission (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
Baseload plantAvailabilityA power generation facility used to meet some or allThe availability factor of a given region’s continuous energy demand, producing energy at a constant rate.power plant is the percentage of the time that it is available to provide energy.
Basin ElectricBasin Electric Power Cooperative
BblBarrel
BcfBillion cubic feet
BcfeBillion cubic feet equivalent
BHCBlack Hills Corporation; the Company
BHEPBHSCBlack Hills Exploration and Production, Inc.,Service Company, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, includesCorporation (doing business as Black Hills Gas Resources, Inc. and Black Hills Plateau Production LLC, direct wholly-owned subsidiaries of Black Hills Exploration and Production, Inc.Energy)
Black Hills Colorado IPPBlack Hills Colorado IPP, LLC, a 50.1% owned subsidiary of Black Hills Electric Generation
Black Hills GasBlack Hills Gas, LLC, a subsidiary of Black Hills Gas Holdings, which was previously named SourceGas LLC.
Black Hills Gas HoldingsBlack Hills Gas Holdings, LLC, a subsidiary of Black Hills Utility Holdings, which was previously named SourceGas Holdings LLC
Black Hills Electric GenerationBlack Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, providing wholesale electric capacity and energy primarily to our affiliate utilities.
Black Hills EnergyThe name used to conduct the business of our utility companies
Black Hills Energy Arkansas GasServicesIncludes the acquired SourceGas utility Black Hills Energy Arkansas, Inc. utility operations
Black Hills Energy Colorado ElectricIncludes Colorado Electric’s utility operations
Black Hills Energy Colorado GasIncludes Black Hills Energy Colorado Gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Colorado gas operations and RMNG
Black Hills Energy Iowa GasIncludes Black Hills Energy Iowa gas utility operations
Black Hills Energy Kansas GasIncludes Black Hills Energy Kansas gas utility operations
Black Hills Energy Nebraska GasIncludes Black Hills Energy Nebraska gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Nebraska gas operations
Black Hills Energy ServicesA Company, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas commodity supply for the Choice Gas supplier acquired in the SourceGas Acquisition
Programs (doing business as Black Hills Energy South Dakota ElectricIncludes Black Hills Power’s operations in South Dakota, Wyoming and Montana
Black Hills Energy Wyoming ElectricIncludes Cheyenne Light’s electric utility operations
Black Hills Energy Wyoming GasIncludes Cheyenne Light’s natural gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Wyoming gas operations
Black Hills Gas DistributionBlack Hills Gas Distribution, LLC, a company acquired in the SourceGas Acquisition that conducts the gas distribution operations in Colorado, Nebraska and Wyoming. It was formerly named SourceGas Distribution LLC.Energy).
Black Hills Non-regulated HoldingsBlack Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation


Black Hills PowerBlack Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
BHSCBlack Hills Service Company LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Utility HoldingsBlack Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills WyomingBlack Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
BLMUnited States Bureau of Land Management
BtuBritish thermal unit
Busch Ranch IBusch Ranch Wind Farm is a 29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and AltaGas.Black Hills Electric Generation. Colorado Electric hasand Black Hills Electric Generation each have a 50% ownership interest in the wind farm.
Ceiling TestBusch Ranch IIRelated
60 MW wind farm near Pueblo, Colorado owned by Black Hills Electric Generation to our Oil and Gas subsidiary, capitalized costs, less accumulated amortization and related deferred income taxes, are subjectprovide wind energy to Colorado Electric through a ceiling test which limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties.power purchase agreement expiring in November 2044.

CAPPCustomer Appliance Protection Plan, - acquired inwhich provides appliance repair services to residential natural gas customers through on-going monthly service agreements. The consolidation of the SourceGas Acquisitionexisting 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
CG&ACawley, Gillespie & Associates, Inc., an independent consulting and engineering firm
Cheyenne LightCheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Cheyenne PrairieCheyenne Prairie Generating Station is a 132 MW natural-gas fired generating facility jointly owned by Black Hills PowerSouth Dakota Electric and Cheyenne LightWyoming Electric in Cheyenne, Wyoming. Cheyenne Prairie was placed into commercial service on October 1, 2014.
Choice Gas ProgramTheRegulator approved programs in Wyoming and Nebraska that allow certain utility customers to select their natural gas commodity supplier, providing the unbundling of the natural gascommodity service from the distribution component, which opens up the gas supply for competition allowing customers to choose from different natural gas suppliers. Black Hills Gas Distribution distributes the gas and Black Hills Energy Service is one of the Choice Gas suppliers.delivery service.
City of GilletteGillette, Wyoming
CO2
City of Cheyenne		Carbon dioxideCheyenne, Wyoming

Colorado ElectricBlack Hills Colorado Electric, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Company, LP,Holdings, providing electric service to customers in Colorado (doing business as Black Hills Energy).
Colorado GasBlack Hills Colorado Gas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Colorado (doing business as Black Hills Energy).
Colorado GasCommon Use System (CUS)Black Hills Colorado Gas Utility Company, LP, an indirect, wholly-owned subsidiaryThe 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 Black Hills Utility Holdings (doing business as Black Hills Energy)
Colorado Interstate Gas (CIG)Colorado Interstate Natural Gas Pricing Index
Colorado IPPBlack Hills Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Electric Generationsouthwestern South Dakota and northeastern Wyoming.
Consolidated Indebtedness to Capitalization RatioAny Indebtedness outstanding at such time, divided by Capitalcapital at such time. Capital being Consolidated Net-Worthconsolidated net-worth (excluding noncontrolling interest and including the aggregate outstanding amount of RSNs)interest) plus Consolidated Indebtednessconsolidated indebtedness (including letters of credit and certain guarantees issued and excluding RSNs)issued) as defined within the current Revolving Credit Agreement.Facility.
Cooling Degree 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 over a 30-year average.locations.
Cost of Service Gas Program (COSG)CorriedaleProposed Cost of Service Gas Program designedWind 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 provide long-term natural gas price stability for the Company’s utility customers, along with a reasonable expectation of customer savings over the life of theRenewable 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
DARTDays Away Restricted Transferred (number of cases with days away from work or job transfer or restrictions multiplied by 200,000 then divided by total hours worked for all employees during the year covered)
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 EnergyElectricity purchased by one utility from another utility to takePurchased energy that costs less than that produced with the place of electricity that would have cost more to produce on the utility’s own systemutilities’ owned generation.
Energy WestEIAEnergy West Wyoming, Inc., a subsidiary of Gas Natural, Inc. Energy West is an acquisition we closed on July 1, 2015.
EnsercoEnserco Energy Inc., a former wholly-owned subsidiary of Black Hills Non-regulated Holdings, which is presentedEnvironmental Improvement Adjustment -- annual adjustment mechanism that allows us to recover from customers eligible investments in, discontinued operations in this Annual Report filed on Form 10-Kand expense related to, new environmental measures.
EPAUnited States Environmental Protection Agency
EPA Region VIIIEPA Region VIII (Mountains and Plains) located in Denver serving Colorado, Montana, North Dakota, South Dakota, Utah, Wyoming and 27 Tribal Nations
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

FDICFederal DepositoryDeposit Insurance Corporation
FERCUnited States Federal Energy Regulatory Commission
FitchFitch Ratings Inc.
GAAPAccounting principles generally accepted in the United States of America
GADSGeneration Availability Data System
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 dollar figurerevenue requirement is agreed upon, but the specific adjustments used by each party to arrive at the figureamount are not specified in public rate ordersorders.
Happy JackHappy Jack Wind Farm, LLC, owned by Duke Energy Generation Services
Heating Degree 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 over a 30 year average.locations.
IEEEHomeServeInstitute of Electrical and Electronics EngineersWe offer HomeServe products to our natural gas residential customers interested in purchasing additional home repair service plans.
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
IPP TransactionThe July 11, 2008 sale of seven of our IPP plants
IRSUnited States Internal Revenue Service
KCCITCKansas Corporation CommissionInvestment 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
LOELease Operating Expense
Loveland Area ProjectPart of the Western Area Power Association transmission system
MACTMaximum Achievable Control Technology
MAPPMid-Continent Area Power Pool
MATSUtility Mercury and Air Toxics Rules under the United States EPA National Emissions Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units
MbblThousand barrels of oil
McfThousand cubic feet
McfdThousand cubic feet per day
McfeThousand cubic feet equivalent
MDUMontana DakotaMontana-Dakota Utilities Co., a regulated utility divisionsubsidiary of MDU Resources Group, Inc.
MEANMunicipal Energy Agency of Nebraska
MGPMISOManufactured Gas PlantMidcontinent Independent System Operator, Inc.
MMBtuMillion British thermal units
MMcfMillion cubic feet
MMcfeMillion cubic feet equivalent
Moody’sMoody’s Investors Service, Inc.
MSHAMine Safety and Health Administration
MTPSCMontana Public Service Commission
MWMegawatts
MWhMegawatt-hours
N/ANot Applicable
Native loadEnergy required to serve customers within our service territory
NAVNet Asset Value
Nebraska GasBlack Hills Nebraska Gas, Utility Company, LLC, a direct,an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Nebraska (doing business as Black Hills Energy).
NERCNorth American Electric Reliability Corporation
NGLNatural Gas Liquids (1 barrel equals 6 Mcfe)
NOAANational Oceanic and Atmospheric Administration
NOAA Climate Normals
This dataset is produced once every 10 years. This dataset contains daily and monthly normals of temperature, precipitation, snowfall, heating and cooling degree days, frost/freeze dates, and growing degree days calculated from observations at approximately 9,800 stations operated by NOAA’s National Weather Service.

NOx
Nitrogen oxide
NOLNet operating loss
NPDESNational Pollutant Discharge Elimination System
NPSCNebraska Public Service Commission
NWPLNorthwest Interstate Natural Gas Pricing Index
NYMEXNew York Mercantile Exchange
NYSENew York Stock Exchange
OCIOther Comprehensive Income
OPEBOther Post-Employment Benefits
OSHAOccupational Safety & Health Administration
OSMU.S.United States Department of the Interior’s Office of Surface Mining

OTC
Over-the-counter
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 View$109 million 60 MW wind generating project owned by Colorado Electric, placed in service on November 7, 2016 and adjacent to Busch Ranch Wind FarmI.
PPAPower Purchase Agreement


PRPAPlatte River Power Authority
PSAPower Sales Agreement
PPACAPSCoPatient Protection and Affordable Care ActPublic Service Company of 2010Colorado
PPBPueblo Airport GenerationParts per billion420 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.
PUDPTCProved undeveloped reservesProduction tax credit
PUHCA 2005Public Utility Holding Company Act of 2005
Quad O Regulation40 CFR 60 Subpart OOOO - Standards of performance for crude oil and natural gas production, transmission and distribution
RCRAResource Conservation and Recovery Act
RICEReciprocating Internal Combustion Engines
REPARenewable Energy Purchase Agreement
Revolving Credit FacilityOur $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which matureswas 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 2021Wyoming and western South Dakota.
RMNGRocky Mountain Natural Gas a regulatedLLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas utility acquired in the SourceGas Acquisition that provides regulated transmission and wholesale natural gas service to Black Hills Gas Distributionservices in western Colorado (doing business as Black Hills Energy).
RSNsRemarketable junior subordinated notes, issued on November 23, 2015 and retired on August 17, 2018.
SAIDISCADASystem Average Interruption Duration Index
Supervisory control and data acquisition

SDPUCSouth Dakota Public Utilities Commission
SECU. S.United States Securities and Exchange Commission
Service GuardHome appliance repair product offering for both natural gas and electric.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.
SourceGasSPPSourceGas Holdings LLCSouthwest Power Pool, Inc. which oversees the bulk electric grid and its subsidiaries, a gas utility owned by funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) that was acquired on February 12, 2016, and is now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy)
SourceGas AcquisitionThe acquisition of SourceGas Holdings, LLC by Black Hills Utility Holdingswholesale 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.
Spinning ReserveSouth Dakota ElectricGeneration capacity that is on-line but unloadedBlack Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and that can respond within 10 minutes to compensate for generation or transmission outagesWyoming (doing business as Black Hills Energy).
SSIRSystem Safety and Integrity Rider
SSTAR-TEXOKNatural gas price index tied to the Southern Star Central gas pipeline
System Peak DemandRepresents the highest point of retail customer usage for a single hour for the system in total. Our system peaks include demand loads for 100% of plants regardless of joint ownership.hour.
TCATransmission Cost Adjustment -- adjustments passed throughannual adjustment mechanism that allows us to recover from customers eligible transmission investments prior to the customer based on transmission costs that are higher or lower than the costs approved in thenext rate case.review.
TCIRTCJATotal Case Incident Rate (average numberTax Cuts and Jobs Act enacted on December 22, 2017

Tech ServicesNon-regulated product lines within Black Hills Corporation that 1) provide electrical system construction services to large industrial customers of work-related injuries incurredour electric utilities, and 2) serve gas transportation customers throughout its service territory by 100 workers during a one-year period)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
VOCVolatile Organic Compound
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)
WTIWyoming ElectricWest Texas Intermediate crude oil, an oil index benchmark priceCheyenne 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 quoted by NYMEXBlack Hills Energy).
Wyodak PlantWyoming GasWyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, owned 80% by PacifiCorp and 20% by Black Hills Energy South Dakota. Our WRDC mine supplies allWyoming Gas, LLC, an indirect, wholly-owned subsidiary of the fuel for the plant.Black Hills Utility Holdings, providing natural gas services to customers in Wyoming (doing business as Black Hills Energy).




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.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, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements in this Form 10-K, including statements contained within Item 1A - Risk Factors.Factors.


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 vertically-integrated utility company headquartered in Rapid City, South Dakota. Our predecessor company, Black Hills Power and Light Company, was incorporated and began providing electric utility 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 Wyodak Coal Mine,WRDC mine, we began producing selling and marketing various forms ofselling energy through non-regulated businesses.


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


Our Electric Utilities segment generates, transmits and distributes electricity to approximately 208,500214,000 electric utility customers in Colorado, Montana, South Dakota Wyoming, Colorado and Montana.Wyoming. Our Electric Utilities own 941939 MW of generation and 8,8068,892 miles of electric transmission and distribution lines.


Our Gas Utilities segment serves approximately 1,030,8001,066,000 natural gas utility customers in Arkansas, Colorado, Iowa, Kansas, Nebraska, Kansas and Wyoming. Our Gas Utilities own 4,585and operate approximately 4,775 miles of intrastate gas transmission pipelines and 40,04441,210 miles of gas distribution mains and service lines. On February 12, 2016, we acquired SourceGas Holdings, LLC, adding four regulatedlines, seven natural gas utilities serving approximately 431,000 customers in Arkansas, Colorado, Nebraskastorage sites, nearly 49,000 horsepower of compression and Wyoming and a 512 mile regulated intrastate natural gas transmission pipeline in Colorado. For additional information on this acquisition, see the Key Elementsover 500 miles of our Business Strategy in Item 7 and Note 2 in the Notes to Consolidated Financial Statements in Item 8.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 the coaland delivers it primarily under long-term contracts to adjacent mine-mouth electric generation facilities including our own regulated and non-regulated generating plants. Our Oil and Gas segment engages in the exploration, development and production of crude oil and natural gas, primarily in the Rocky Mountain region, with a focus on divesting non-core oil and gas assets and retaining those best suited to assist utilities with the implementation of cost of service gas programs. For additional information, see the Key Elements of our Business Strategy in Item 7.

Our segments generated the following net income (loss) available for common stock for the year ended December 31, 2016 and had the following total assets at December 31, 2016 (excluding Corporate):
 Net income (loss) available for common stock for the year ended December 31, 2016Total Assets as of December 31, 2016
 (in thousands)
Electric Utilities$85,827$2,859,559
Gas Utilities$59,624$3,307,967
Power Generation$25,930$73,445
Mining$10,053$67,347
Oil and Gas($71,054)$96,435

Segment reporting transition of Cheyenne Light’s Natural Gas distribution

Effective January 1, 2016, the natural gas operations of Cheyenne Light are reported in our Gas Utilities Segment. Through December 31, 2015, Cheyenne Light’s natural gas operations were included inowned by our Electric Utilities Segment as these natural gas operations were consolidated within Cheyenne Light since its acquisition. This change is a result of our business segment reorganization to, among other things, integrate all regulated natural gas operations, including the SourceGas Acquisition, into our Gas Utilities Segment which is led by the Group Vice President, Natural Gas Utilities. Likewise, all regulated electric utility operations including Cheyenne Light’s electric utility operations are reported in our Electric Utilities Segment, which is led by the Group Vice President, Electric Utilities. The prior periods have been reclassified to reflect this change in presentation between the Electric Utilities and Gas Utilities segments.Power Generation businesses.


Segment Financial Information

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

Utility Rebranding

All of our utilities now operate with the trade name Black Hills Energy. We expanded our regulated operations with the acquisition of SourceGas, as well as with our 2015 utility acquisitions. We rebranded our Cheyenne Light utilities, Black Hills Power utility and our SourceGas utilities to operate under the name Black Hills Energy, conforming to the name under which our other utilities operate. Within our Electric Utilities segment and our Gas Utilities segment, references made to our utilities are presented as follows according to their respective state:

Electric Utilities Segment

Black Hills Energy South Dakota Electric - includes all Black Hills Power utility operations in South Dakota, Wyoming and Montana.

Black Hills Energy Wyoming Electric - includes all Cheyenne Light electric utility operations.

Black Hills Energy Colorado Electric - includes all Colorado Electric utility operations.



Gas Utilities Segment

Black Hills Energy Arkansas Gas - includes the acquired SourceGas utility Black Hills Energy Arkansas operations.

Black Hills Energy Colorado Gas - includes Black Hills Energy Colorado Gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Colorado operations and RMNG operations.

Black Hills Energy Nebraska Gas - includes Black Hills Energy Nebraska gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Nebraska operations.

Black Hills Energy Iowa Gas - includes Black Hills Energy Iowa gas utility operations.

Black Hills Energy Kansas Gas - includes Black Hills Energy Kansas gas utility operations.

Black Hills Energy Wyoming Gas - includes Cheyenne Light’s natural gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Wyoming operations.

Black Hills Energy Services - includes the acquired SourceGas Utility Black Hills Energy Services operations.

Electric Utilities Segment


We conduct electric utility operations through our Colorado, South Dakota and Wyoming and Colorado subsidiaries. Our Electric Utilities generate, transmit and distribute electricity to approximately 208,500 customers in South Dakota, Wyoming, Colorado and Montana. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our own distribution systems. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates. We also provide non-regulated services through our Tech Services product lines. Tech Services provides electrical system construction services to large industrial customers of our electric utilities.


Capacity and Demand

Demand. System peak demandsdemand for the Electric UtilitiesUtilities’ retail customers for each of the last three years are listed below:
 System Peak Demand (in MW)
 2016 2015 2014
 SummerWinter SummerWinter Summer Winter
South Dakota Electric438389 424369 410 389
Wyoming Electric (a)
236230 212202 198 197
Colorado Electric (b)
412302 392303 384 298
Total Electric Utilities Peak Demands1,086921 1,028874 992 884
 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)Both 2016The Colorado Electric July 2019 summer and winter peaks are recordspeak load of 422 surpassed previous summer peak record load of 413 set in July and December, respectively, replacing summer andJune 2018. The October 2018 winter record peakspeak load of 313 surpassed previous winter peak load of 310 set in July and December of 2015.February 2011.
(b)NewThe Wyoming Electric July 2019 summer peak load for Colorado Electric achievedof 265 surpassed previous summer peak record load of 254 set in July 2016, replacing2018. The December 2019 winter peak load of 247 surpassed the previous all-time summerwinter peak record load of 406238 set in June 2016, and of 400 set in June 2012.December 2018.

Regulated Power Plants

Regulated Power Plants. As of December 31, 20162019, our Electric Utilities’ ownership interests in electric generationgenerating plants were as follows:

Unit
Fuel
Type
Location
Ownership
Interest %
Owned Capacity (MW)
Year
Installed
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 (a)
GasCheyenne, Wyoming58%55.02014
Wygen III (b)
CoalGillette, Wyoming52%57.22010
Cheyenne Prairie (c)
GasCheyenne, Wyoming58%55.02014
Wygen III (d)
CoalGillette, Wyoming52%57.22010
Neil Simpson IICoalGillette, Wyoming100%90.01995CoalGillette, Wyoming100%90.01995
Wyodak (c)
CoalGillette, Wyoming20%72.41978
Wyodak Plant (e)
CoalGillette, Wyoming20%72.41978
Neil Simpson CTGasGillette, Wyoming100%40.02000GasGillette, Wyoming100%40.02000
Lange CTGasRapid City, South Dakota100%40.02002GasRapid City, South Dakota100%40.02002
Ben French Diesel #1-5OilRapid City, South Dakota100%10.01965OilRapid City, South Dakota100%10.01965
Ben French CTs #1-4Gas/OilRapid City, South Dakota100%80.01977-1979Gas/OilRapid City, South Dakota100%80.01977-1979
Wyoming Electric:  
Cheyenne Prairie (a)
GasCheyenne, Wyoming42%40.02014
Cheyenne Prairie CT (a)
GasCheyenne, Wyoming100%37.02014
Cheyenne Prairie (c)
GasCheyenne, Wyoming42%40.02014
Cheyenne Prairie CT (c)
GasCheyenne, Wyoming100%37.02014
Wygen IICoalGillette, Wyoming100%95.02008CoalGillette, Wyoming100%95.02008
Colorado Electric: 
Busch Ranch Wind Farm (d)
WindPueblo, Colorado50%14.52012
Peak View Wind Farm (e)
WindPueblo, Colorado100%60.02016
Pueblo Airport GenerationGasPueblo, Colorado100%180.02011
Pueblo Airport Generation CT (f)
GasPueblo, Colorado100%40.02016
AIP DieselOilPueblo, Colorado100%10.02001
Diesel #1-5OilPueblo, Colorado100%10.01964
Diesel #1-5OilRocky Ford, Colorado100%10.01964
Total MW Capacity 941.1  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 a 132 MW natural gas-fired power generation facility was placed into commercial operation on October 1, 2014 to supportserves the utility customers of South Dakota Electric and Wyoming Electric. The facility includes one simple-cycle, 37 MW combustion turbine that is wholly-owned by Wyoming Electric and one combined-cycle, 95 MW unit that is jointly-owned by Wyoming Electric (40 MW) and South Dakota Electric (55 MW).
(b)(d)Wygen III, a 110 MW mine-mouth coal-fired power plant, is operated by South Dakota Electric. South Dakota Electric has aowns 52% ownership interest,of the power plant, MDU owns 25% and the City of Gillette owns the remaining 23% interest. Our adjacent WRDC coal mine supplies all of the fuel for the plant.
(c)(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 coal mine supplies all of the fuel for the plant.
(d)Busch Ranch Wind Farm, a 29 MW wind farm, is operated by Colorado Electric. Colorado Electric has a 50% ownership interest in the wind farm and AltaGas owns the remaining 50%. Colorado Electric has a 25-year REPA with AltaGas for their 14.5 MW of power from the wind farm.
(e)Peak View Wind Farm achieved commercial operation on November 7, 2016.
(f)Colorado Electric’s newly constructed LM 6000, which achieved commercial operation on December 29, 2016.






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 iswas as follows:
Fuel Source (dollars per MWh)201620152014201920182017
Coal$11.27
$10.89
$10.92
$11.46
$11.10
$10.95
  
Natural Gas (a)
$30.59
$51.14
$77.31
$25.92
$33.42
$34.05
  
Diesel Oil (b)(a)
$149.13
$303.16
$174.04
$209.86
$329.27
$210.11
  
Total Average Fuel Cost$12.99
$14.62
$14.82
Total Weighted Average Fuel Cost$13.86
$13.53
$12.80
  
Purchased Power - Coal, Gas and Oil$48.36
$47.81
$35.21
$43.73
$45.62
$45.63
  
Purchased Power - Renewable Sources$51.95
$50.92
$50.27
$48.61
$54.31
$53.08
______________
(a)Decrease is driven by lower 2016 natural gas costs thanIncluded in the prior year.
(b)Decrease is due to combination of lower fuel costs in 2016Price per MWh for Diesel Oil are unit start-up costs. The diesel-fueled generating units are generally used as supplemental peaking units and the efficiencies at whichcost per MWh is reflective of how often the diesel units performed compared toare started and how long the prior year.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 iswas as follows:
Power Supply201620152014201920182017
Coal33%33%34%30%32%32%
Gas, Oil and Wind7
4
4
12
10
8
Total Generated40
37
38
42
42
40
Purchased (a)
60
63
62
58
58
60
Total100%100%100%100%100%100%
______________
(a)Wind represents approximately 7%6%, 6% and 6% of our purchased power in 2016,2019, 2018, and approximately 5% of our purchased power in 2015 and 2014.2017, respectively.


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

South Dakota Electric’s PPA with PacifiCorp expiring on December 31, 2023, which provides for the purchase of 50 MW of coal-fired baseload power;

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

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

Wyoming Electric’s PPA with Black Hills Wyoming expiring on December 31, 2022, whereby Black Hills Wyoming provides 60 MW of unit-contingent capacity and energy from its Wygen I facility. The PPA includes an option for Wyoming Electric to purchase Black Hills Wyoming’s ownership interest in the Wygen I facility through 2019, subject to WPSC and FERC approval in order to obtain regulatory treatment. The purchase price related to the option is $2.6 million per MW adjusted for capital additions and reduced by depreciation over a 35-year life beginning January 1, 2009 (approximately $5 million per year);

Wyoming Electric’s 20-year PPA with Duke Energy expiring on September 3, 2028, which provides up to 29.4 MW of wind energy from the Happy Jack Wind Farm to Wyoming Electric. Under a separate inter-company agreement, Wyoming Electric sells 50% of the facility’s output to South Dakota Electric;

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

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

Power Sales Agreements.Our Electric Utilities also have various long-term power sales agreements.PSAs. Key agreements include:

MDU owns a 25% interestcontracts are disclosed in Wygen III’s net generating capacity for the lifeNote 19 of the plant. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, South Dakota Electric will provide MDU with 25 MW from its other generation facilities or from system purchases with reimbursement of costs by MDU;Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.


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

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

South Dakota Electric has an agreement to supply up to 20 MW of energy and capacity to MEAN under a contract that expires in 2023. This contract is unit-contingent based on the availability of our Neil Simpson II and Wygen III plants, with decreasing capacity purchased over the term of the agreement. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows:
201720 MW - 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II
2018-201915 MW - 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II
2020-202112 MW - 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II
2022-202310 MW - 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II

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


At December 31, 20162019, our Electric Utilities owned the electric transmission and distribution lines shown below:
UtilityState
Transmission
(in Line Miles)
Distribution
(in Line Miles)
State
Transmission
(in Line Miles)
Distribution
(in Line Miles)
Colorado ElectricColorado598
3,120
South Dakota ElectricSouth Dakota, Wyoming1,260
2,497
South Dakota, Wyoming1,219
2,557
South Dakota Electric - Jointly Owned (a)
South Dakota, Wyoming44
—
South Dakota, Wyoming43
—
Wyoming ElectricSouth Dakota, Wyoming44
1,279
Wyoming49
1,306
Colorado ElectricColorado590
3,092
 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 United States and eastern United States, respectively. This transmission tie, which is 65% owned by Basin Electric, provides transmission access to both the WECC region in the West and the MAPP region in the East. The transfer capacity of the tie is 200 MW from West to East, and 200 MW from East to West. South Dakota Electric’s electric system is located in the WECC region. This transmission tie allows us to buy and sell energy in the Eastern grid without having to isolate and physically reconnect load or generation between the two transmission grids, thus enhancing the reliability of our system. It accommodates scheduling transactions in both directions simultaneously, provides additional opportunities to sell excess generation or to make economic purchases to serve our native load and contract obligations, and enables us to take advantage of power price differentials between the two grids. 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 point-to-point transmission access to deliver up to 50 MW of power on PacifiCorp’s transmission system to wholesale customers in the WECC region through 2023.


South Dakota Electric also has firm network transmission access to deliver power on PacifiCorp’s system to Sheridan, Wyoming, to serve our power sales contract with MDU through 2017,December 31, 2023, with the right to renew pursuant to the terms of PacifiCorp’s transmission tariff.


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


◦•South Dakota Electric, the City of Gillette and MDU
Jointly Owned Facilities agreements are parties to a shared joint ownership agreement, whereby South Dakota Electric charges the City of Gillette and MDU for administrative services, plant operations and maintenance for their sharediscussed in Note 4 of the Wygen III generating facility forNotes to the life of the plant.Consolidated Financial Statements in this Annual Report on Form 10-K.

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

Operating Statistics

The following tables summarize information for our Electric Utilities:

Degree Days201620152014
 ActualVariance from Prior Year
Variance from 30-Year Average (b)
ActualVariance from Prior Year
Variance from 30-Year Average (b)
Actual
Variance from 30-Year Average (b)
Heating Degree Days:        
South Dakota Electric6,402
(2)%(10)%6,521
(12)%(8)%7,373
4%
Wyoming Electric6,363
(1)%(14)%6,404
(10)%(10)%7,100
—%
Colorado Electric4,658
(4)%(16)%4,846
(12)%(12)%5,534
—%
Combined (a)
5,595
(2)%(13)%5,729
(11)%(10)%6,473
2%
         
Cooling Degree Days:        
South Dakota Electric646
12%(4)%577
20%(14)%481
(28)%
Wyoming Electric460
13%31%407
21%16%336
(5)%
Colorado Electric1,358
7%42%1,270
38%32%919
(4)%
Combined (a)
935
9%26%861
32%16%654
(12)%
________________
(a)The combined heating degree days are calculated based on a weighted average of total customers by state.
(b)30-Year Average is from NOAA Climate Normals.

Revenue - Electric (in thousands)201620152014
Residential:   
South Dakota Electric$72,084
$72,659
$69,712
Wyoming Electric39,553
39,587
36,634
Colorado Electric97,088
97,418
94,391
Total Residential208,725
209,664
200,737
    
Commercial:   
South Dakota Electric97,579
100,511
91,882
Wyoming Electric64,042
64,207
59,758
Colorado Electric97,147
93,821
90,909
Total Commercial258,768
258,539
242,549
    
Industrial:   
South Dakota Electric33,409
33,336
28,451
Wyoming Electric (a)
45,498
36,594
29,066
Colorado Electric39,274
42,325
39,219
Total Industrial118,181
112,255
96,736
    
Municipal:   
South Dakota Electric3,705
3,626
3,409
Wyoming Electric2,122
2,179
1,930
Colorado Electric11,994
12,058
13,312
Total Municipal17,821
17,863
18,651
    
Subtotal Retail Revenue - Electric603,495
598,321
558,673
    
Contract Wholesale:   
Total Contract Wholesale - South Dakota Electric17,037
17,537
21,206
    
Off-system/Power Marketing Wholesale:   
South Dakota Electric (b)
15,431
23,241
28,002
Wyoming Electric5,471
5,215
8,179
Colorado Electric1,453
1,270
5,726
Total Off-system/Power Marketing Wholesale22,355
29,726
41,907
    
Other Revenue: (c)
   
South Dakota Electric28,387
26,954
25,826
Wyoming Electric920
2,374
2,253
Colorado Electric5,087
4,931
7,691
Total Other Revenue34,394
34,259
35,770
    
Total Revenue - Electric$677,281
$679,843
$657,556
_____________________
(a)Increase is driven primarily by load growth supporting data centers in Cheyenne, Wyoming.
(b)Decrease is due to lower commodity prices that reduced gross sales.
(c)Other revenue primarily consists of transmission revenue.

Quantities Generated and Purchased (MWh)201620152014
Generated:   
Coal-fired:   
South Dakota Electric (a)(b)
1,467,403
1,537,744
1,591,061
Wyoming Electric (c)
734,354
690,633
697,220
Total Coal - fired2,201,757
2,228,377
2,288,281
    
Natural Gas and Oil:   
South Dakota Electric (a)(d)
118,467
80,944
44,984
Wyoming Electric (a)(d)
70,997
48,644
12,534
Colorado Electric (e)
153,537
100,732
140,942
Total Natural Gas and Oil343,001
230,320
198,460
    
Wind:   
Colorado Electric (f)
80,582
41,043
48,318
Total Wind80,582
41,043
48,318
    
Total Generated:   
South Dakota Electric1,585,870
1,618,688
1,636,045
Wyoming Electric805,351
739,277
709,754
Colorado Electric234,119
141,775
189,260
Total Generated2,625,340
2,499,740
2,535,059
    
Purchased:   
South Dakota Electric1,181,445
1,422,015
1,446,630
Wyoming Electric872,070
791,351
766,475
Colorado Electric (e)
1,911,537
1,952,625
1,898,232
Total Purchased (g)
3,965,052
4,165,991
4,111,337
    
Total Generated and Purchased6,590,392
6,665,731
6,646,396
_______________
(a)Natural gas-fired generation from Cheyenne Prairie increased in 2016 primarily due to lower coal fired generation driven by 2016 outages at the coal-fired Wyodak plant.
(b)Neil Simpson I was retired on March 21, 2014.
(c)Increase in 2016 was due to a 2015 planned annual outage at Wygen II.
(d)Cheyenne Prairie was placed into commercial service on October 1, 2014.
(e)Lower commodity prices drove an increase in generation and a corresponding decrease in purchased power.
(f)Increase in 2016 is due to the addition of the Peak View Wind Project in November 2016.
(g)Includes wind power of 269,552 MWh, 227,396 MWh and 224,229 MWh in 2016, 2015 and 2014, respectively.


Quantities Sold (MWh)201620152014
Residential:   
South Dakota Electric520,798
521,828
542,008
Wyoming Electric257,593
256,964
261,038
Colorado Electric616,706
621,109
598,872
Total Residential1,395,097
1,399,901
1,401,918
    
Commercial:   
South Dakota Electric783,319
792,466
782,238
Wyoming Electric531,446
532,218
528,689
Colorado Electric752,721
706,872
685,094
Total Commercial2,067,486
2,031,556
1,996,021
    
Industrial:   
South Dakota Electric429,912
429,140
399,648
Wyoming Electric (a)
650,810
498,141
382,306
Colorado Electric434,831
472,360
432,167
Total Industrial1,515,553
1,399,641
1,214,121
    
Municipal:   
South Dakota Electric33,591
31,924
32,076
Wyoming Electric9,400
9,714
9,425
Colorado Electric119,392
117,858
122,247
Total Municipal162,383
159,496
163,748
    
Subtotal Retail Quantity Sold5,140,519
4,990,594
4,775,808
    
Contract Wholesale:   
Total Contract Wholesale - South Dakota Electric (b)
246,630
260,893
340,871
    
Off-system Wholesale:   
South Dakota Electric (c)
597,695
837,120
808,257
Wyoming Electric110,621
121,659
191,069
Colorado Electric61,527
41,306
119,315
Total Off-system Wholesale769,843
1,000,085
1,118,641
    
Total Quantity Sold:   
South Dakota Electric2,611,945
2,873,371
2,905,098
Wyoming Electric1,559,870
1,418,696
1,372,527
Colorado Electric1,985,177
1,959,505
1,957,695
Total Quantity Sold6,156,992
6,251,572
6,235,320
    
Other Uses, Losses or Generation, net (d):
   
South Dakota Electric155,370
167,332
177,577
Wyoming Electric117,551
111,932
103,702
Colorado Electric160,479
134,895
129,797
Total Other Uses, Losses and Generation, net433,400
414,159
411,076
    
Total Energy Sold6,590,392
6,665,731
6,646,396
________________________
(a)Year over year increases since 2014 are driven by new load supporting data centers in Cheyenne, Wyoming.
(b)Decrease in 2015 is primarily due to the expiration in March 2015 of a 5 MW unit contingent capacity contract with MEAN.
(c)Decrease in 2016 is driven by weaker market conditions.
(d)Includes Company uses, line losses, test energy and excess exchange production.


Customers at End of Year201620152014
Residential:   
South Dakota Electric57,712
57,178
56,511
Wyoming Electric36,748
36,438
36,253
Colorado Electric83,873
83,285
82,710
Total Residential178,333
176,901
175,474
    
Commercial:   
South Dakota Electric13,278
13,197
13,173
Wyoming Electric4,560
4,760
4,489
Colorado Electric11,248
11,215
11,156
Total Commercial29,086
29,172
28,818
    
Industrial:   
South Dakota Electric21
20
23
Wyoming Electric5
4
4
Colorado Electric62
63
66
Total Industrial88
87
93
    
Other Electric Customers:   
South Dakota Electric340
335
325
Wyoming Electric218
220
224
Colorado Electric441
469
469
Total Other Electric Customers999
1,024
1,018
    
Subtotal Retail Customers208,506
207,184
205,403
    
Contract Wholesale:   
Total Contract Wholesale - South Dakota Electric2
3
3
    
Total Customers:   
South Dakota Electric71,353
70,733
70,035
Wyoming Electric41,531
41,422
40,970
Colorado Electric95,624
95,032
94,401
Total Electric Customers at End of Year208,508
207,187
205,406




Gas Utilities Segment

We conduct natural gas utility operations through our Arkansas, Colorado, Iowa, Kansas, Wyoming and Nebraska subsidiaries. On February 12, 2016, we acquired SourceGas Holdings, LLC, adding four regulated natural gas utilities serving approximately 431,000 customers in Arkansas, Colorado, Nebraska and Wyoming and a 512 mile regulated intrastate natural gas transmission pipeline in Colorado. Our Gas Utilities distribute and transport natural gas through our distribution network to approximately 1,030,800 customers. Additionally, we sell temporarily-available, contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates.

We also provide non-regulated services through Black Hills Energy Services. Black Hills Energy Services has approximately 55,000 retail distribution customers in Nebraska and Wyoming providing unbundled natural gas commodity offerings under the regulatory-approved Choice Gas Program. We also sell, install and service air, heating and water-heating equipment, and provide associated repair service and appliance protection plans under various trade names. Service Guard and CAPP primarily provide appliance repair services to approximately 61,000, and 33,000 residential customers, respectively, through Company technicians and third-party service providers, typically through on-going monthly service agreements. Tech Services primarily serves gas transportation customers throughout our service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.

Our Gas Utilities own regulated underground gas storage facilities in several states primarily to supplement the supply of natural gas to our customers in periods of peak demand. The following table summarizes certain information regarding our regulated underground gas storage facilities as of December 31, 2016:

 StateWorking Capacity (Mcf)
Cushion Gas (Mcf) (a)
Total Capacity (Mcf)Maximum Daily Withdrawal Capability (Mcfd)
 
 Arkansas8,442,700
12,950,000
21,392,700
196,000
 Colorado2,168,721
6,063,249
8,231,970
30,000
 Wyoming6,813,400
17,270,200
24,083,600
32,950
 Total17,424,821
36,283,449
53,708,270
258,950
________________
(a)Cushion gas represents the volume of gas that must be retained in a facility to maintain reservoir pressure.

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

System Infrastructure (in line miles) as of
Intrastate Gas
Transmission Pipelines
Gas Distribution
Mains
Gas Distribution
Service Lines
December 31, 2016
Arkansas886
4,572
906
Colorado678
6,481
2,323
Nebraska1,249
8,330
3,319
Iowa180
2,740
2,639
Kansas293
2,826
1,328
Wyoming1,299
3,372
1,208
Total4,585
28,321
11,723



Degree Days

 2016 2015 2014
 ActualVariance From Prior Year
Variance From
30-Year Average (d)
 ActualVariance From Prior Year
Variance From
30-Year Average (d)
 Actual
Variance From
30-Year Average (d)
Heating Degree Days:          
Arkansas (a)
2,397
—%(10)% —
—%—% —
—%
Colorado5,762
4%(9)% 5,527
(10)%(12)% 6,108
(3)%
Nebraska5,457
2%(12)% 5,350
(14)%(12)% 6,193
2%
Iowa5,997
(10)%(12)% 6,629
(16)%(2)% 7,875
16%
Kansas (b)
4,307
(3)%(12)% 4,432
(13)%(9)% 5,099
4%
Wyoming6,750
5%(8)% 6,404
(10)%(10)% 7,100
—%
Combined (c)
5,823
(1)%(10)% 5,890
(13)%(8)% 6,805
6%
________________
(a)Arkansas has a weather normalization mechanism in effect during the months of November through April for those customers with residential and business rate schedules. The weather normalization mechanism in Arkansas only uses one location to calculate the weather, minimizing, but not eliminating weather impact.
(b)Kansas Gas has an approved weather normalization mechanism within its rate structure, which minimizes weather impact on gross margins, using multiple locations.
(c)The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to its weather normalization mechanism.
(d)30-Year Average is from NOAA climate normals.



Operating Statistics
Gas Utilities Revenue (in thousands)201620152014
Residential:   
Arkansas$59,675
$—
$—
Colorado102,468
55,216
58,439
Nebraska98,300
111,090
135,052
Iowa80,480
90,865
124,145
Kansas56,284
61,420
74,128
Wyoming35,899
23,554
24,426
Total Residential433,106
342,145
416,190
    
Commercial:   
Arkansas29,460
—
—
Colorado36,431
10,744
12,233
Nebraska27,742
32,798
39,947
Iowa33,119
39,314
60,640
Kansas18,241
21,802
24,966
Wyoming17,554
12,916
11,279
Total Commercial162,547
117,574
149,065
    
Industrial:   
Arkansas4,904
—
—
Colorado1,837
1,433
1,909
Nebraska458
1,339
830
Iowa1,777
2,633
4,386
Kansas8,892
12,887
16,963
Wyoming3,377
4,106
2,945
Total Industrial21,245
22,398
27,033
    
Other:   
Arkansas2,644
—
—
Colorado1,006
464
118
Nebraska3,479
2,271
2,440
Iowa506
580
724
Kansas4,177
4,475
2,836
Wyoming882
275
267
Total Other12,694
8,065
6,385
    
Distribution Revenue:   
Arkansas96,683
—
—
Colorado141,742
67,857
72,699
Nebraska129,979
147,498
178,269
Iowa115,882
133,392
189,895
Kansas87,594
100,584
118,893
Wyoming57,712
40,851
38,917
Total Distribution Revenue629,592
490,182
598,673
    
Transportation:   
Arkansas8,348
—
—
Colorado3,752
1,037
968
Nebraska (a)
66,241
13,427
14,272
Iowa4,844
4,762
4,934
Kansas6,611
7,280
7,448
Wyoming (a)
21,962
3,310
838
Total Transportation111,758
29,816
28,460



Transmission:   
Arkansas1,339
—
—
Colorado21,713
—
—
Wyoming4,680
—
—
Total Transmission27,732
—
—
    
Total Regulated Revenue769,082
519,998
627,133
    
Non-regulated Services69,261
31,302
30,390
    
Total Revenue$838,343
$551,300
$657,523

Gas Utilities Gross Margin (in thousands)201620152014
Residential:   
Arkansas$39,324
$—
$—
Colorado42,853
18,153
18,100
Nebraska51,953
51,168
54,996
Iowa42,030
41,638
44,134
Kansas30,794
31,789
32,809
Wyoming21,558
13,011
11,615
Total Residential228,512
155,759
161,654
    
Commercial:   
Arkansas16,119
—
—
Colorado13,128
2,921
3,048
Nebraska10,942
10,822
11,708
Iowa11,620
11,662
13,206
Kansas7,419
8,409
8,115
Wyoming8,147
4,678
3,582
Total Commercial67,375
38,492
39,659
    
Industrial:   
Arkansas1,776
—
—
Colorado670
395
464
Nebraska194
393
239
Iowa215
253
294
Kansas2,020
2,529
2,336
Wyoming726
733
525
Total Industrial5,601
4,303
3,858
    
Other:   
Arkansas2,644
—
—
Colorado1,006
464
118
Nebraska3,479
2,271
2,441
Iowa506
580
724
Kansas4,177
4,405
1,990
Wyoming882
275
266
Total Other12,694
7,995
5,539
    
Distribution Gross Margin:   
Arkansas59,863
—
—
Colorado57,657
21,933
21,730
Nebraska66,568
64,654
69,384
Iowa54,371
54,133
58,358
Kansas44,410
47,132
45,250
Wyoming31,313
18,697
15,988
Total Distribution Gross Margin314,182
206,549
210,710
    


Transportation:   
Arkansas8,348
—
—
Colorado3,752
1,037
968
Nebraska (a)
66,241
13,427
14,272
Iowa4,844
4,762
4,934
Kansas6,611
7,280
7,448
Wyoming (a)
21,962
3,310
838
Total Transportation111,758
29,816
28,460
    
Transmission:   
Arkansas1,339
—
—
Colorado21,504
—
—
Wyoming4,681
—
—
Total Transmission27,524
—
—
    
Total Regulated Gross Margin:   
Arkansas69,550
—
—
Colorado82,913
22,970
22,698
Nebraska132,809
78,081
83,656
Iowa59,215
58,895
63,292
Kansas51,021
54,412
52,698
Wyoming57,956
22,007
16,826
Total Regulated Gross Margin453,464
236,365
239,170
    
Non-regulated Services32,714
15,290
14,572
    
Total Gross Margin$486,178
$251,655
$253,742

Gas Utilities Quantities Sold and Transported (in Dth)201620152014
Residential:   
Arkansas6,052,792
—
—
Colorado12,634,407
6,575,261
6,718,508
Nebraska10,676,153
10,751,376
13,068,132
Iowa9,567,386
9,648,973
12,172,281
Kansas5,866,246
6,091,041
7,313,273
Wyoming4,593,467
2,583,049
2,515,243
Total Residential49,390,451
35,649,700
41,787,437
    
Commercial:   
Arkansas4,111,136
—
—
Colorado4,676,332
1,404,624
1,537,704
Nebraska3,986,531
4,026,689
4,644,645
Iowa5,425,789
5,492,230
7,182,173
Kansas2,564,759
2,768,486
3,043,685
Wyoming3,273,314
2,073,213
1,482,904
Total Commercial24,037,861
15,765,242
17,891,111
    
Industrial:   
Arkansas983,881
—
—
Colorado440,174
288,212
354,630
Nebraska86,905
246,184
122,662
Iowa398,871
481,760
630,912
Kansas2,914,538
3,346,525
3,384,797
Wyoming913,061
845,774
539,848
Total Industrial5,737,430
5,208,455
5,032,849
    
    


Wholesale and Other:   
Kansas—
14,902
150,014
Total Wholesale and Other—
14,902
150,014
    
Distribution Quantities Sold:   
Arkansas11,147,809
—
—
Colorado17,750,913
8,268,097
8,610,842
Nebraska14,749,589
15,024,249
17,835,439
Iowa15,392,046
15,622,963
19,985,366
Kansas11,345,543
12,220,954
13,891,769
Wyoming8,779,842
5,502,036
4,537,995
Total Distribution Quantities Sold79,165,742
56,638,299
64,861,411
    
Transportation:   
Arkansas7,292,299
—
—
Colorado2,552,756
1,019,933
950,819
Nebraska (a)
53,046,432
28,968,737
30,669,764
Iowa19,991,944
19,867,265
19,959,462
Kansas15,117,771
15,865,783
15,883,098
Wyoming (a)
19,870,602
11,672,057
9,970,123
Total Transportation117,871,804
77,393,775
77,433,266
    
Transmission:   
Arkansas737,330
—
—
Colorado (b)
3,353,222
—
—
Wyoming4,965,209
—
—
Total Transmission9,055,761
—
—
    
Total Quantities Sold and Transportation:   
Arkansas19,177,438
—
—
Colorado23,656,891
9,288,030
9,561,661
Nebraska67,796,021
43,992,986
48,505,203
Iowa35,383,990
35,490,228
39,944,828
Kansas26,463,314
28,086,737
29,774,867
Wyoming33,615,653
17,174,093
14,508,118
Total Quantities Sold and Transportation206,093,307
134,032,074
142,294,677
________________________
(a)Increased transportation in Nebraska and parts of Wyoming is due to Choice Gas Program customers acquired in the SourceGas Acquisition.
(b)Intercompany volumes from RMNG’s transmission system to Black Hills Gas Distribution are not included.



Customers at End of Year201620152014
Residential:   
Arkansas148,513
—
—
Colorado160,153
74,345
72,360
Nebraska184,794
180,897
180,014
Iowa140,007
139,205
138,503
Kansas99,748
99,013
99,359
Wyoming67,765
39,953
32,962
Total Residential800,980
533,413
523,198
    
Commercial:   
Arkansas17,638
—
—
Colorado16,777
3,825
3,788
Nebraska16,147
15,948
15,900
Iowa15,435
15,433
15,303
Kansas10,747
10,813
10,547
Wyoming7,305
4,156
3,052
Total Commercial84,049
50,175
48,590
    
Industrial:   
Arkansas213
—
—
Colorado275
224
205
Nebraska126
145
147
Iowa94
98
90
Kansas1,324
1,377
1,277
Wyoming18
15
7
Total Industrial2,050
1,859
1,726
    
Transportation:   
Arkansas148
—
—
Colorado189
40
34
Nebraska (a)
88,586
4,271
4,151
Iowa478
460
418
Kansas1,138
1,161
1,145
Wyoming (a)
53,134
30
12
Total Transportation143,673
5,962
5,760
    
Wholesale:   
Kansas (b)
—
—
8
Total Wholesale—
—
8
    
Total Customers:   
Arkansas166,512
—
—
Colorado177,394
78,434
76,387
Nebraska289,653
201,261
200,212
Iowa156,014
155,196
154,314
Kansas112,957
112,364
112,336
Wyoming128,222
44,154
36,033
Total Customers at End of Year1,030,752
591,409
579,282
________________________
(a)Increased transportation in Nebraska and parts of Wyoming is due to Choice Gas Program customers acquired in the SourceGas Acquisition.
(b)Change in customers is due to classification change to Commercial billing in 2015 based on customer’s business type.


Electric Utilities and Gas Utilities Business Characteristics

Seasonal Variations of Business

Business. Our Electric Utilities and Gas Utilities are seasonal businesses and weather patterns may impact their operating performance. Demand for electricity and natural gas 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. Because our Electric Utilities have a diverse customer and revenue base, and we have historically optimized the utilization of our electric power supply resources, the impact on our operations may not be as significant when weather conditions are warmer in the winter and cooler in the summer. Conversely, for our Gas Utilities, 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.


Competition

Competition. We generally have limited competition for the retail generation and distribution of electricity and natural gas 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. 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. 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

Current Rates

Regulation. Our utilitiesElectric Utilities are subject to the jurisdiction of the public utilities commissions in the states where they operate. Theoperate 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, the rates of other utilities, general economic conditions and the political environment. Certain commissions also have jurisdiction over the issuance of debt or securities and the creation of liens on property located in their states to secure bonds or other securities.

The following table illustratesprovides regulatory information about certain enacted regulatory provisions with respect to the states in which thefor each of our Electric Utilities operate:Utilities:

SubsidiaryJurisdic-tionAuthorized Rate of Return on EquityAuthorized Return on Rate BaseAuthorized Capital Structure Debt/EquityAuthorized Rate Base (in millions)Effective DateTariff and Rate MattersPercentage of Power Marketing Profit Shared with CustomersJurisdic-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
Electric Utilities: 
 
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%WY9.9%8.13%46.7%/53.3%$46.810/2014ECA65%
SDGlobal Settlement7.76%Global Settlement$543.910/2014ECA, TCA, Energy Efficiency Cost Recovery/DSM, Vegetation Management70%
SD 7.76% 6/2011Environmental Improvement Cost Recovery Adjustment TariffN/A
MT15.0%11.73%47%/53% 1983ECAN/ASDGlobal Settlement7.76%Global Settlement$543.910/2014ECA, Energy Efficiency Cost Recovery/DSM, TFA, EIA70%
FERC10.8%9.10%43%/57% 2/2009FERC Transmission TariffN/AFERC10.8%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/AWY9.9%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/AFERC10.6%8.51%46%/54%$31.55/2014FERC Transmission TariffN/A
Colorado ElectricCO9.37%7.43%47.6%/52.4%$539.61/2017ECA, TCA, PCCA, Energy Efficiency Cost Recovery/DSM, Renewable Energy Standard Adjustment90%
CO9.37%6.02%67.3%/32.7%$57.91/2017Clean Air Clean Jobs Act Adjustment RiderN/A

__________
(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.

We produce and/or distribute electricity in four states: Colorado, South Dakota, Wyoming and Montana. 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 case. Somereview. In addition, some states allow for recovery of new capital investment placed in which our utilities operate alsoservice between base rate reviews through approved rider tariffs. These tariffs allow the utility operating in that state to automatically adjust rates periodically for the cost of new transmission or environmental improvements and, in some instances, the utility has the opportunity to earn its authorizeda return on new capital investment immediately.the investment.



A summary of mechanisms we have in place are shown in the table below:
Electric Utility JurisdictionCost Recovery Mechanisms
Environmental CostEnergy EfficiencyTransmission ExpenseFuel CostTransmission CapitalPurchased Power
Colorado Electricþþþþþ
South Dakota Electric (SD)þþþþþþ
South Dakota Electric (WY)þþþþ
South Dakota Electric (FERC)þ
Wyoming Electricþþþþ

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 and state:utility:


In South Dakota, South Dakota Electric has:

An annual adjustment clause which provides for the direct recovery of increased fuel and purchased power cost incurred to serve South Dakota customers. Additionally, the ECA contains an off-system sales sharing mechanism in which South Dakota customers will receive a credit equal to 70% of off-system power marketing operating income. 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 vegetation management recovery mechanism that allows for recovery of and a return on prudently-incurred vegetation management costs.

An approved annual Environmental Improvement Cost Recovery Adjustment tariff which recovers costs associated with generation plant environmental improvements.

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


In Wyoming, Wyoming Electric has:

An annual cost adjustment mechanism that allows us to pass the prudently-incurred costs of fuel and purchased power through to electric customers. As of October 1, 2014, the annual cost adjustment allows for recovery of 85% of coal and coal-related costs, and recovery of 95% of purchased power costs, transmission, and natural gas costs.

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

In Colorado, Colorado Electric has:


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


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


TheA Clean Air Clean Jobs Act Adjustment rider rate that collects the authorized revenue requirement for the LM6000 generating unit40 MW combustion turbine placed in service on December 31, 2016 with rates effective January 1, 2017.


TheA 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 Peak View Wind Project.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.


Wyoming Electric Utilities Rateshas:

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 Rate Activitycoal-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 table summarizes recent activity of certain state and federal rate reviews, riders and surcharges (dollars in millions):tables summarize information for our Electric Utilities:

 Type of ServiceDate RequestedEffective DateRevenue Amount RequestedRevenue Amount Approved
Colorado Electric (a)
Electric5/20161/2017$8.9
$1.2
 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)On December 19, 2016,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
    

  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, received approval fromSouth Dakota Electric and Wyoming Electric, respectively.
(c)
Due to the CPUCchanges in our segment disclosures discussed in Note 5 of the Notes to increase its annual revenues by $1.2 million to recover investmentsthe Consolidated Financial Statements in a $63 million, 40 MW natural gas-fired combustion turbinethis Annual Report on Form 10-K, cost of fuel and normal increases in operating expenses. This increase is in addition to approximately $5.9 million in annualized revenue being recovered under the Clean Air Clean Jobs Act construction financing rider. This turbinepurchased power was completed in the fourth quarter of 2016, achieving commercial operation on December 29, 2016. The approval allowed a return on rate base of 6.02% for this turbine, with a 9.37% return on equity and a capital structure of 67.34% debt and 32.66% equity. Whereas, an authorized return on rate base of 7.4% was receivedrevised for the remaining system investments, with a returnyears 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 equityconsolidated financial results.
(d)
For further information on Gross Margin, see “Non-GAAP Financial Measure” within Management’s Discussion and Analysis of 9.37%Financial Condition and an approved capital structureResults of 47.6% debt and 52.4% equity.Operations in Item 7 of this Annual Report on Form 10-K.


On January 9, 2017, we filed an application with the CPUC for rehearing, reargument or reconsideration of the Commission’s December 19, 2016 decision which reduced our proposed $8.9 million annual revenue increase to $1.2 million. Concurrent with this application, we filed a motion for Commissioner Koncilja to recuse herself from continuing to participate in any further proceedings in the rate review.
 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.


 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 believeconduct 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 CPUC made errorsChoice 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



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 December decision by demonstrating bias, making decisions not supported by evidence, making findings inconsistent with cost-recovery provisions of the Colorado Clean Air-Clean Jobs Act and the Commission’s own prior decisions, and treating Colorado Electric differently thanstates to secure bonds or other regulated utilities in Colorado have been treated in similar situations.securities.

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 cost recovery mechanisms, such as regulatory riders, which vary by utility, but allow us to recover certain costs or earn a return on capital investments, such as those related to energy efficiency plansplan costs and system safety and integrity investments.  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 DateTariff and Rate MattersJurisdic-tionAuthorized Rate of Return on EquityAuthorized Return on Rate BaseAuthorized Capital Structure Debt/EquityAuthorized Rate Base (in millions)Effective DateAdditional Tariffed Mechanisms
Gas Utilities:Gas Utilities: Gas Utilities: 
Arkansas Gas (a)
AR9.4%
6.47% (b)
52%/48%
$299.4 (c)
2/2016
Gas Cost Adjustment, Main Replacement Program, At-Risk Meter Replacement Program, Legislative/Regulatory Mandate and Relocations Rider, Energy Efficiency, Weather Normalization Adjustment, Billing Determinant Adjustment

AR9.61%
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%$64.012/2012GCA, Energy Efficiency Cost Recovery/DSMCO9.6%8.41%50%/50%$57.512/2012GCA, Energy Efficiency Cost Recovery/DSM
Colorado Gas Dist.(a)
CO10.0%8.02%49.52%/ 50.48%$127.112/2010
Gas Cost Adjustment, DSM

CO10.0%8.02%49.52%/ 50.48%$127.112/2010
GCA, Energy Efficiency Cost Recovery/DSM

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

CO9.9%6.71%53.37%/ 46.63%$118.76/2018System Safety Integrity Rider, Liquids/Off-system/Market Center Services Revenue Sharing
Iowa GasIAGlobal Settlement$109.22/2011GCA, Energy Efficiency Cost Recovery/DSM/Capital Infrastructure Automatic Adjustment MechanismIAGlobal Settlement$109.22/2011GCA, Energy Efficiency Cost Recovery, Capital Infrastructure Automatic Adjustment Mechanism, Farm Tap Tracker Adjustment, Gas Supply Optimization revenue sharing
Kansas GasKSGlobal Settlement$127.41/2015GCA, Weather Normalization Tariff, Gas System Reliability Surcharge, Ad Valorem Tax Surcharge, Cost of Bad Debt Collected through GCA, Pension Levelized AdjustmentKSGlobal 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%$161.39/2010GCA, Cost of Bad Debt Collected through GCA, Infrastructure System Replacement Cost Recovery SurchargeNE10.1%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. (a)
NE9.6%7.67%
48.84%/
51.16%
$87.6/$69.8 (d)
6/2012
Choice Gas Program, System Safety and Integrity Rider, Bad Debt expense recovered through Choice supplier fee

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 GasWY9.9%7.98%46%/54%$59.610/2014GCA, Energy Efficiency Cost Recovery/DSM, Rate Base Recovery on Acquisition AdjustmentWY9.4%6.9849.77%/50.23%$354.43/2020GCA, Energy Efficiency Cost Recovery, Rate Base Recovery on Acquisition Adjustment, Wyoming Integrity Rider, Choice Gas Program
Wyoming Gas Dist. (a)
WY9.92%7.98%
49.66%/
50.34%
$100.51/2011
Choice Gas Program, Purchased Gas Cost Adjustment, Usage Per Customer Adjustment

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



We distribute natural gas in six states: Arkansas, Colorado, Iowa, Nebraska, Kansas and Wyoming. All of our Gas Utilities, except where the Choice Gas Program is the only option, have GCAs that allow us to pass the prudently-incurred cost of gas and certain services through to the customer between rate reviews. Some of the mechanisms we have in place include the following:

Gas Utility JurisdictionCost Recovery Mechanisms
DSM/Energy EfficiencyIntegrity AdditionsBad DebtWeather NormalPension RecoveryFuelGas CostRevenue DecouplingBilling Determinant Adjustment
Arkansas Gasþþ þ þþ
Colorado Gasþ    þ 
Colorado Gas Dist.Distributionþ    þ 
Rocky Mountain Natural GasRMNGN/AþN/AN/AN/AN/AN/A
Iowa Gasþþ   þ 
Kansas Gas þþþþþ 
Nebraska Gas þþ  þ 
Nebraska Gas Dist.Distribution þþ  þ 
Wyoming Gas(a)
þþ   þ 
Wyoming Gas Dist.þþ

Gas Utilities Rates and Rate Activity

The following table summarizes recent activity of certain state and federal rate reviews, riders and surcharges (dollars in millions):
 Type of ServiceDate RequestedEffective DateRevenue Amount RequestedRevenue Amount Approved
Arkansas Gas (a)
Gas4/20152/2016$12.6
$8.0
Arkansas Stockton Storage (b)
Gas - storage11/20161/2017$2.6
$2.6
Arkansas MRP/ARMRP (c)
Gas1/20171/2017$1.7
$1.7
RMNG (d)
Gas - transmission and storage11/20161/2017$2.9
$2.9
Nebraska Gas Dist. (e)
Gas10/20162/2017$6.5
$6.5
______________________________
(a)In February 2016, ArkansasThe Wyoming Gas implemented new base rates resulting in a revenue increase of $8.0 million. The APSC modified a stipulation reached between the APSC Staff and all intervenors except the Attorney General and Arkansas Gas in its order issued on January 28, 2016. The modified stipulation revised the capital structure to 52% debt and 48% equity and also limited recovery of portions of cost related to incentive compensation.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



  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
________________
(b)(a)On November 15, 2016, Arkansas Gas filed for recovery
For further information on Gross Margin, see “Non-GAAP Financial Measure” within Management’s Discussion and Analysis of Stockton Storage revenue requirement through the Stockton Storage Acquisition Rates regulatory mechanism, approvedFinancial Condition and Results of Operations in Item 7 of this Annual Report on October 15, 2015, with rates effective January 1, 2017.
(c)On January 3, 2017 Arkansas Gas filed for recovery of $1.5 million related to projects for the replacement of eligible mains (MRP) and the recovery of $0.2 million related to projects for the relocation of certain at risk meters (ARMRP). Pursuant to the Arkansas Gas Tariff, the filed rates go into effect on the date of the filing.
(d)On November 3, 2016, RMNG filed with the CPUC requesting recovery of $2.9 million, which includes $1.2 million of new revenue related to system safety and integrity expenditures on projects for the period of 2014 through 2017. This SSIR request was approved by the CPUC in December 2016, and went into effect on January 1, 2017.
(e)On October 3, 2016, Nebraska Gas Dist. filed with the NPSC requesting recovery of $6.5 million, which includes $1.7 million of new revenue related to system safety and integrity expenditures on projects for the period of 2012 through 2017. This SSIR tariff was approved by the NPSC in January 2017, and will go into effect on February 1, 2017.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


Cost of Service Gas Program FilingsUtility Regulation Characteristics


On September 30, 2015, Black Hills Corp.’s utility subsidiaries submitted applications with respective state utility regulators seeking approval for a Cost of Service Gas Program in Iowa, Kansas, Nebraska, South Dakota and Wyoming. An application was submitted in Colorado on November 2, 2015. The Cost of Service Gas Program is designed to provide long-term natural gas price stability for the Company’s utility customers, along with a reasonable expectation of customer savings over the life of the program. As originally proposed, our non-utility affiliate would acquire natural gas reserves and/or drill wells to produce natural gas for the program for up to 50% of weather normalized annual firm demand for our utilities. The Cost of Service Gas Program model had a capital structure of 60% equity and 40% debt, and sought a utility-like return.

During the third quarter of 2016, the Company withdrew its Cost of Service Gas applications in Wyoming, Iowa, Kansas and South Dakota. In consideration of the July 19, 2016 denial of the application from the NPSC and the April 2016 dismissal of its application from the CPUC, the Company is re-evaluating its Cost of Service Gas regulatory approval strategy.

The Company’s initial applications submitted in late 2015 were based on a two-phase approach, the first of which would establish the regulatory framework for how the program would work, and the second would seek approval for a specific gas reserve property. The orders in Colorado and Nebraska indicated the initial phase filings contained insufficient information and data to support customer benefits. Based on the findings and outcomes of the initial unsuccessful filings, the Company is considering filing new applications for approval of specific gas reserve properties.

Other 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, 20162019, 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.
Colorado. Colorado adopted a renewable energy standard that has two components: (i) electric resource standards and (ii) a 2% retail rate impact for compliance with the electric resource standards. The electric resource standards require our Colorado Electric subsidiary to generate, or cause to be generated, electricity from renewable energy sources equaling: (i) 20% of retail sales from 2015 to 2019; and (ii) 30% of retail sales by 2020. Of these amounts, 3% must be generated from distributed generation sources with one-half of these resources being located at customer facilities. The net annual incremental retail rate impact from these renewable resource acquisitions (as compared to non-renewable resources) is limited to 2%. The standard encourages the CPUC to consider earlier and timely cost recovery for utility investment in renewable resources, including the use of a forward rider mechanism. We are currently in compliance with these standards.

Colorado Electric received a settlement agreement of its electric resource plan filed June 3, 2016, to meet requirements under the Colorado Renewable Energy Standard. The settlement, effective February 6, 2017, includes the addition of 60 megawatts of renewable energy to be in service by 2019 and provides for additional small solar and community solar gardens as part of the compliance plan. Colorado Electric plans to issue a request for proposal in the first half of 2017.


On November 7, 2016,26, 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 took ownership of Peak View, a $109 million, 60 MW Wind Project located near Colorado Electric's Busch Ranch Wind Farm. Peak View achieved commercial operation on November 7, 2016 and was purchased via progress payments throughout 2016 under a commission approved third-party build transfer and settlement agreement.25-year PPA, which expires in November 2044. This renewable energy project was originally submitted in responsewill enable Colorado Electric to Colorado Electric’s all-source generation request on May 5, 2014. The Commission’s settlement agreement provides for recovery of the costs of the project through Colorado Electric’s Electric Cost Adjustments andcomply with Colorado's Renewable Energy Standard Surcharge for 10 years and recovery through the Transmission Cost Adjustment, after which Colorado Electric can propose base rate recovery. Colorado Electric will be required to make an annual comparison of the cost of the renewable energy generated by the facility against the bid cost of a PPA from the same facility.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.
Montana. In 2005, Montana established a renewable portfolio standard that requires public utilities to obtain a percentage of their retail electricity sales from eligible renewable resources. In March 2013, South Dakota Electric filed a petition with the MTPSC requesting a waiver of the renewable portfolio standards primarily due to exceeding the applicable “cost cap” included in the standards. In March 2013, the Montana Legislature adopted legislation that had the effect of excluding South Dakota Electric from all renewable portfolio standard requirements under State Senate Bill 164, primarily due to the very low number of customers we have in Montana and the relatively high cost of meeting the renewable requirements.
•
Wyoming. Wyoming currently has no renewable energy portfolio standard.

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

Wyoming. Wyoming currently has no renewable energy portfolio standard.


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


Federal Regulation


Energy Policy Act. Black Hills CorporationBHC is a holding company whose assets consist primarily of investments in our subsidiaries, including subsidiaries that are public utilities and a holding companiescompany 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 UtilityUtilities’ subsidiaries provide FERC-jurisdictional services subject to FERC’s oversight.

Our Electric Utilities Black Hills Colorado IPP and Black Hills WyomingPower 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. South DakotaOur Electric ownsUtilities own and operatesoperate FERC-jurisdictional interstate transmission facilities and providesprovide open access transmission service under tariffs on file with FERC. Our Electric Utilities are subject to routine audit by FERC with respect to their compliance with FERC’s regulations.


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


PUHCA 2005. PUHCA 2005 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 subsidiaries,subsidiary, BHSC, and Black Hills Utility Holdings, we are subject to FERC’s authority under PUHCA 2005.



Environmental Matters

We are subjectto numerous federal, state and local laws and regulations relating to the protection of the environment and the safety and health of personnel and the public. These laws and regulations affect a broad range of our utility activities and generally regulate: (i) the protection of air and water quality; (ii) the identification, generation, storage, handling, transportation, disposal, record-keeping, labeling, reporting of and emergency response in connection with hazardous and toxic materials and wastes, including asbestos; and (iii) the protection of plant and animal species and minimization of noise emissions.

Based on current regulations, technology and plans, the following table contains our current estimates of capital expenditures expected to be incurred over the next three years to comply with current environmental laws and regulations as described below, including regulations that cover water, air, soil and other pollutants, but excluding plant closures and the cost of new generation. The ultimate cost could be significantly different from the amounts estimated. The results of the 2016 U.S. elections add uncertainty as to the final disposition of recently enacted and proposed EPA regulations.

Environmental Expenditure Estimates
Total
(in thousands)
2017$1,209
20183,867
20191,773
Total$6,849

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 NPDES and storm water permits. All of our facilities that are required to have such permits have those permits in place and are in compliance with discharge limitations and plan implementation requirements. The EPA proposed effluent limitation guidelines and standards on June 7, 2013 and published the final rule on November 3, 2015. This rule will have an impact on the Wyodak Plant, requiring conversion to a dry method of handling coal ash and further restrictions of constituent concentrations in any off-site discharges. Our share of those costs is estimated at $1.8 million. The terms of this new regulation become effective at the next permit renewal, which will be in 2020. Additionally, the EPA regulates surface water oil pollution through its oil pollution prevention regulations. All of our facilities subject to these regulations have compliant prevention plans in place.

Clean Air Act

Title IV of the Clean Air Act created an SO2 allowance trading regime as part of the federal acid rain program. Each allowance gives the owner the right to emit one ton of SO2.Certain facilities are allocated allowances based on their historical operating data. At the end of each year, each emitting unit must possess allowances sufficient to cover its emissions for the preceding year. Allowances may be traded, so affected units that expect to emit more SO2 than their allocated allowances may purchase allowances on the open market.

Title IV applies to several of our generation facilities, including the Neil Simpson II, Neil Simpson CT, Lange CT, Wygen II, Wygen III, Pueblo Airport Generating Station, Cheyenne Prairie and Wyodak plants. Without purchasing additional allowances, we currently hold sufficient allowances to satisfy Title IV at all such plants through 2046. We expect to integrate the cost of obtaining the required number of allowances needed for future projects into our overall financial analysis of such new projects.

Title V of the Clean Air Act requires that all of our generating facilities obtain operating permits. All of our existing facilities have received Title V permits, with the exception of Wygen III, Pueblo Airport Generating Station and Cheyenne Prairie Generating Station. Wygen III, Pueblo Airport Generating Station and Cheyenne Prairie Generating Station are allowed to operate under their construction permit until the Title V permit is issued by the state. The Title V application for Wygen III was submitted in January 2011, with the permit expected in 2017. The Pueblo Airport Generating Station Title V application was filed in September 2012, with the permit expected in 2017. The Cheyenne Prairie Generating Station Title V application was submitted in 2015, with the permit expected in 2017. All applications were filed in accordance with regulatory requirements.


On February 16, 2012, the EPA published in the Federal Register the National Emission Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units (MATS), with an effective date of April 16, 2012. This rule imposes requirements for mercury, acid gases, metals and other pollutants. As of April 16, 2016, all plants are in compliance.

In August 2012, the EPA proposed revisions to the Electric Utility New Source Performance Standards for stationary combustion turbines. This rule is expected to be finalized in 2017 and, as proposed, will be applicable to the Pueblo Airport Generating Station, Cheyenne Prairie and eventually all the combustion turbines in our fleet. Among other things, the rule seeks to eliminate startup exemptions and clearly define overhauls for impact on the EPA’s New Source Review regulations, with the intention of eventually bringing all units under the applicability of this rule. The primary impact is expected to be on our older existing units, which will eventually be required to meet tighter NOx emission limitations.

The EPA published a more stringent ozone ambient standard on October 26, 2015. This regulation lowered the ozone standard from 75 to 70 ppb which will result in a continuation of the Denver, Colorado and Colorado North Front Range non-attainment status. Wyoming monitoring data from the Gillette and Cheyenne, Wyoming regions indicate compliance with the new limit. The primary impact on Black Hills operations could potentially be tighter NOx emission limits on new power generation units.

Regional Haze

The Regional Haze Program is an EPA rule to improve visibility in our National Parks and Wilderness Areas. The state of Wyoming is currently developing its 2017 initial progress report under the EPA’s Regional Haze Program. Neil Simpson II is not currently a discussion item in that draft report, but could be in the future.

The Wyodak Power Plant is included in EPA’s January 30, 2014 Regional Haze Federal Implementation Plan, which includes significant additional NOx controls by March 1, 2019. Our share of those costs is estimated at $20 million. The State of Wyoming and PacifiCorp filed requests for reconsideration and Administrative Stay with EPA and the United States Court of Appeals for the 10th Circuit. On September 9, 2014, the 10th Circuit stayed EPA’s NOx requirement for Wyodak pending outcome of the appeal, which is anticipated to be settled by the summer of 2017.

Greenhouse Gas Regulations

We utilize a diversified energy portfolio of power generation assets that include a fuel mix of coal, natural gas and wind sources, and minimal quantities of both solar and hydroelectric power. Of these generation resources, coal-fired power plants are the most significant sources of CO2 emissions.

We report GHG emissions for all power generation facilities, gas distribution systems, transmission and compression systems, and oil and gas exploration and production systems.  All data is reported through and available on the U.S. Department of Energy’s (DOE) Energy Information Administration’s and EPA’s GHG reporting website.  For all gas distribution systems, we include U.S. DOT Pipeline and Hazardous Materials Safety Administration (PHMSA) leak surveys of all underground and aboveground facilities including Forward Looking Infrared Camera reviews of 20% of our sites on a rotating annual basis.

The GHG Tailoring Rule, effective June 2010, will impact us in the event of a major modification at an existing facility or in the event of a new major source as defined by EPA regulations. Upon renewal of operating permits for existing facilities, monitoring and reporting requirements will be implemented. New projects or major modifications to existing projects will result in a Best Available Control Technology review that could impose more stringent emissions control practices and technologies. The EPA’s GHG New Source Performance Standard for new steam electric generating units, published October 2015, effectively prohibits new coal-fired units until carbon capture and sequestration becomes technically and economically feasible.

The portion of this rule-making that applies to existing power generation sources is known as the Clean Power Plan (CPP). The portion of this rule-making that applies to new generating units effectively prohibits new coal-fired power plants from being constructed until carbon capture and sequestration becomes technically and economically feasible. The objective of the CPP regulation is to decrease existing coal-fired generation, increase the utilization of existing gas-fired combined cycle generation, increase renewable energy and increase use of demand side management. The U.S. Supreme Court entered an order staying the CPP in February 2016, pending appeal. The effect of the order is to delay the CPP’s compliance deadlines until challenges to the CPP have been fully litigated and the U.S. Supreme Court has ruled. If the CPP is implemented in its current form, we cannot predict the terms of state plans and any limits on CO2 emissions at our existing plants could have a material impact on our customer rates, financial position, results of operations and/or cash flows. In 2015 and again in 2016, we met with staff of state air programs and public utility commissions on several occasions. We will continue to work closely with state regulatory staff as these plans develop.

Wyoming passed GHG legislation in 2012 and 2013, enabling the state to implement the EPA’s GHG program. Wyoming adopted and submitted a GHG regulatory program to the EPA, which the EPA approved and published in 2013. Wyoming has full jurisdiction over the GHG permitting program which includes the transfer of the Cheyenne Prairie EPA GHG air permit, to the state of Wyoming. This eliminates the increased time, expense and considerable risk of obtaining a permit from the EPA.

In 2016, we reported 2015 GHG emissions from our Power Generation and Gas Utilities in order to comply with the EPA’s GHG Annual Inventory regulation. Climate change issues are the subject of a number of lawsuits, the outcome of which could impact the utility industry. We will continue to review GHG impacts as legislation or regulation develops and litigation is resolved.

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 and the closure of certain generating facilities. 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 customers and other purchasers of the power generated by our non-regulated power plants, including utility affiliates. Any unrecovered costs could have a material impact on our results of operations, financial position and/or cash flows. 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. The results of the 2016 U.S. elections add uncertainty as to the final disposition of recently enacted and proposed EPA regulations, including the CPP. We will continue to monitor new developments for potential impacts to our operations.

Solid Waste Disposal

Various materials used at our facilities are subject to disposal regulations. Under state permits, we dispose of all solid wastes collected as a result of burning coal at our power plants in approved ash disposal sites. Ash and waste from flue gas, sulfur and mercury removal from the Wyodak, Neil Simpson II, Wygen II and Wygen III plants are deposited in mined areas at the WRDC coal mine. These disposal areas are currently located below some shallow water aquifers in the mine. In 2009, the State of Wyoming confirmed its past approval of this practice and as part of the five year mine permit renewal process completed in 2016, the state has confirmed approval of this practice. None of the solid waste from the burning of coal is currently classified as hazardous material, but the waste does contain minute traces of metals that could be perceived as polluting if such metals leached into underground water. We conducted investigations which concluded that the wastes are relatively insoluble and will not measurably affect the post-mining ground water quality.

We permanently retired the Osage power plant on March 21, 2014. This plant had an on-site ash impoundment and a small industrial rubble landfill. Site closure work was completed and the state issued an approval of closure activities on October 21, 2014. Post-closure monitoring activities of the ash impoundment and small industrial rubble landfill will continue for 30 years from that date. As of August 31, 2012, we suspended operations at Ben French and the plant was permanently retired on March 21, 2014. The Ben French temporary ash holding area was closed in accordance with state guidelines, with the state issuing a closure certification on March 14, 2014.

Our W.N. Clark plant, which suspended operations on December 31, 2012 and was retired on December 31, 2013, sent coal ash to a permitted, privately-owned landfill. While we do not believe that any substances from our solid waste disposal activities will pollute underground water, we can provide no assurance that pollution will not occur over time. In this event, we could incur material costs to mitigate any resulting damages.

For our Pueblo Airport Generating Station in Pueblo, Colorado, we posted a bond with the State of Colorado to cover the costs of remediation for a waste water containment pond permitted to provide wastewater storage and processing for this zero discharge facility.

Agreements are in place that require PacifiCorp and MEAN to be responsible for any costs related to the solid waste from their ownership interest in the Wyodak plant and Wygen I plant, respectively. As operator of Wygen III, Black Hills Energy South Dakota has a similar agreement in place for any such costs related to solid waste from Wygen III. Under their separate but related operating agreements, Black Hills Energy South Dakota, MDU and the City of Gillette each share the costs for solid waste from Wygen III according to their respective ownership interests.


Additional unexpected material costs could also result in the future if any regulatory agency determines that solid waste from the burning of coal contains a hazardous material that requires special treatment, including previously disposed solid waste. In that event, the regulatory authority could hold entities that dispose of such waste responsible for remedial treatment. On December 19, 2014, the EPA Administrator signed coal ash regulations designating coal ash as a solid waste. These regulations are not applicable to our operations as all of our coal ash is used as mine backfill. However, it is expected that the U.S. Office of Surface Mining will develop similar regulations, anticipated to be proposed in 2017. The 2016 presidential election results add uncertainty as to what the U.S. Office of Surface Mining will propose. We will continue to monitor new developments for potential impacts to our operations.

Manufactured Gas Processing

Some 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.

As a result of the Aquila Transaction, we acquired whole and partial liabilities for several former manufactured gas processing sites in Nebraska and Iowa which were previously used to convert coal to natural gas. The acquisition provided for a $1.0 million insurance recovery, now valued at approximately $1.5 million, which will be used to help offset remediation costs. The remediation cost estimate could change materially due to results of further investigations, actions of environmental agencies or the financial viability of other responsible parties.

In March 2011, Nebraska Gas executed an Allocation, Indemnification and Access Agreement with the successor to the former operator of the Nebraska MGPs. Under this agreement, Nebraska Gas received $1.9 million from the successor to the operator of Nebraska Gas to remediate two sites in Nebraska (Blair and Plattsmouth). These sites were remediated through the state voluntary cleanup program. Site remediation was completed in 2012 and ground water monitoring ended in 2015. We assembled our final removal action completion reports to formally close the site, and submitted reports to the Nebraska Department of Environmental Quality in December 2015. In 2016, we received state approval for “no further action” at both sites. The successor is also responsible for remediation activity at the two remaining sites in Nebraska (Columbus and Norfolk). While the successor has performed remediation work at Columbus and Norfolk, due to disagreements between the state of Nebraska and the successor over management of remaining groundwater contamination, the EPA in 2016 placed the Norfolk site on the National Priority List. We are not a named financially responsible party to this action. We cannot be assured of the financial impact to us as property owner until the process has run its course.

As of December 31, 2016, we estimate a range of approximately $2.6 million to $6.1 million to remediate the MGP site in Council Bluffs, Iowa, of which we could be responsible for up to 25% of the costs. In 2014, we began the process of evaluating legal and corporate successorship avenues for cost recovery from other potential responsible parties. At this time, no parties have been formally named nor have we determined the degree to which they are responsible. There are currently no regulatory requirements or deadlines for cleanup. In 2016, as part of a nationwide assessment of such sites, the EPA performed sampling to determine current contamination levels. Results confirmed previously known levels of contamination. While there are no regulatory actions to date requiring remediation, we are assessing the situation to determine a path forward.

Prior to Black Hills Corporation’s ownership, Aquila received rate orders that approved recovery of environmental cleanup costs in certain jurisdictions. We anticipate recovery of current and future remediation costs would be allowed. Additionally, we may pursue recovery or agreements with other potentially responsible parties when and where permitted.

As a result of the SourceGas Transaction, we acquired potential liability for at least one former MGP site in McCook, Nebraska. The Nebraska Department of Environmental Quality conducted a limited assessment in 2012 which documented soil and groundwater impacts. However, there has been no directive from the state to pursue either remediation or further assessment. We are currently evaluating the potential for other Potential Responsible Parties and future comprehensive analyses to fully determine and delineate the extent of contamination. The assigned liability for this site cannot be determined at this time. However, based on the state’s assessment, we anticipate costs will be less than $1.0 million.



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, 2016,2019, we held varying interests in independent power plants operating in Wyoming and Colorado with a total net ownership of approximately 269423 MW.

Portfolio Management


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 substantial majority of our non-regulated generating capacity under contracts having terms greater than one year.


As of December 31, 2016,2019, the power plant ownership interests held by our Power Generation segment included:include:
Power PlantsFuel TypeLocation
Ownership
Interest
Owned Capacity (MW)In Service DateFuel TypeLocation
Ownership
Interest
Owned Capacity (MW)In Service Date
Wygen I(a)CoalGillette, Wyoming76.5%68.9
2003CoalGillette, Wyoming76.5%68.9
2003
Pueblo Airport Generation (a)
GasPueblo, Colorado50.1%200.0
2012GasPueblo, 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
 268.9
  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 Colorado IPP owns and operates this facility.Electric Generation purchased a 50% ownership interest in Busch Ranch I. This facility provides capacityoriginally 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 to Colorado Electricgenerated in the MISO market.
(e)This facility qualifies for PTCs at $25/MWh under a 20-year PPA with Colorado Electric. This PPA is accounted for as a capital leaseIRC 45 during the 10-year period beginning on the accompanying Consolidated Financial Statements.date the facility was originally placed in service.


Black Hills Wyoming - Wygen I. The Wygen I generation facility is a mine-mouth, coal-firedPower Sales Agreements. Our Power Generation facilities have various long-term power plant with a total capacity of 90 MW located at our Gillette, Wyoming energy complex. We own 76.5%sales agreements. See Note 19 of the plant and MEAN owns the remaining 23.5%. We sell 60 MW of unit-contingent capacity and energy from this plant to Wyoming Electric under a PPA that expires on December 31, 2022. The PPA includes an option for Wyoming Electric to purchase Black Hills Wyoming’s ownership interest in the Wygen I facility through 2019. The purchase price in the contract relatedNotes to the option is $2.6 million per MW adjustedConsolidated Financial Statements in this Annual Report on Form 10-K for capital additions and reduced by depreciation over 35 years starting January 1, 2009 (approximately $5 million per year). The net book value of Wygen I at December 31, 2016 was $73 million and if Wyoming Electric had exercised the purchase option at year-end 2016, the estimated purchase price would have been approximately $139 million and would be subject to WPSC and FERC approval in order to obtain regulatory treatment. Wyoming Electric has delayed consideration of exercising the purchase option pending the state of Wyoming finalizing their State Implementation Plans to comply with the EPA’s CPP. Wyoming originally had until September 30, 2016 to submit their final plans to the EPA. However a two-year extension has been allowed under the rule, which Wyoming has applied for and received. The U.S. Supreme Court's stay of the CPP and the results of the 2016 U.S elections add uncertainty as to the final disposition of recently enacted and proposed EPA regulations, including the CPP. We sell excess power from our generating capacity into the wholesale power markets when it is available and economical.further information.


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

Sale ofThird Party Noncontrolling Interest in Subsidiary

On April 14,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. FERC approvalSee Note 12 of the sale was receivedNotes to the Consolidated Financial Statements in this Annual Report on March 29, 2016. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric. Proceeds from the sale were used to pay down short-term debt andForm 10-K for other general corporate purposes. The operating results for Black Hills Colorado IPP remain consolidated with Black Hills Electric Generation, as Black Hills Colorado IPP has been determined to be a variable interest entity (VIE) in which the Company has a variable interest.additional information.




The following table summarizes MWh for our Power Generation segment:
For the year ended December 31,
Quantities Sold, Generated and Purchased (MWh) (a)
201620152014201920182017
Sold  
Black Hills Colorado IPP1,223,949
1,133,190
1,178,464
935,997
1,000,577
943,618
Black Hills Wyoming (b)
644,564
663,052
581,696
629,788
582,938
645,810
Black Hills Electric Generation (c)
167,296
5,873
—
Total Sold1,868,513
1,796,242
1,760,160
1,733,081
1,589,388
1,589,428

 
Generated  
Black Hills Colorado IPP1,223,949
1,133,190
1,178,464
935,997
1,000,577
943,618
Black Hills Wyoming543,546
561,930
543,796
Black Hills Wyoming (b)
557,119
501,945
577,124
Black Hills Electric Generation (c)
167,296
5,873
—
Total Generated1,767,495
1,695,120
1,722,260
1,660,412
1,508,395
1,520,742
  
Purchased  
Black Hills Wyoming (b)
85,993
68,744
38,237
74,199
83,213
69,377
Total Purchased85,993
68,744
38,237
74,199
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, effective September 2014, 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:

Economy Energy PPA and other ancillary agreements


◦•
Black Hills Wyoming sold its CTII 40 MW natural gas-fired generating unit to the City of Gillette, Wyoming on September 3, 2014. Under the terms of the sale, Black Hills Wyoming entered into ancillary agreements to operate CTII, and provide use of shared facilities including a ground lease and dispatch generation services. In addition, the agreement includes a 20-yearWyoming’s economy energy PPA that contains a sharing arrangementand other ancillary agreements are discussed in whichNote 19 of the parties shareNotes to the savings of wholesale power purchases made when market power prices are less than the cost of operating the generating unit.Consolidated Financial Statements in this Annual Report on Form 10-K.


Operating and Maintenance Services Agreement


◦In conjunction with the sale of thea noncontrolling interest on April 14,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 is in effect frombecame 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. 


Shared Services Agreements


◦South Dakota Electric, Wyoming Electric and Black Hills Wyoming are parties to a shared facilities agreement, whereby each entity chargesis 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 ElectricElectric’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 Generating Station.Prairie.


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



Jointly Owned Facilities


◦•Black Hills Wyoming and MEAN
Jointly owned facilities agreements are parties to a shared joint ownership agreement, whereby Black Hills Wyoming charges MEAN for administrative services, plant operations and maintenance on their sharediscussed in Note 4 of the Wygen I generating facility overNotes to the life of the plant.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 operating experienceoperations 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 twofive EWGs: Wygen I, and 200 MW (two 100 MW combined-cycle gas-fired units) at the Pueblo Airport Generating Station.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.


Environmental Regulation. Many of the environmental laws and regulations applicable to our regulated Electric Utilities, to include the EPA’s CPP, also apply to our Power Generation operations. See the discussion above under the “Environmental” and “Regulation” captions for the Electric and Gas Utilities for additional information on certain laws and regulations.

Clean Air Act. The Clean Air Act impacts our Power Generation business in a manner similar to the impact disclosed for our Electric Utilities. Our Wygen I and Pueblo Airport Generating facilities are subject to Titles IV and V of the Clean Air Act and have the required permits in place or have applications submitted in accordance with regulatory time lines. As a result of SO2 allowances credited to us from the installation of sulfur removal equipment at our jointly owned Wyodak plant, we hold sufficient allowances for our Wygen I plant through 2046, without purchasing additional allowances. The EPA’s MACT rule described in the Electric and Gas Utilities section also applies to Wygen I.

Clean Water Act. The Clean Water Act impacts our Power Generation business in a manner similar to the impact described above for our Electric Utilities. Each of our facilities that is required to have NPDES permits have those permits and are in compliance with discharge limitations. The EPA also regulates surface water oil pollution prevention through its oil pollution prevention regulations. Each of our facilities regulated under this program have the requisite pollution prevention plans in place.

Solid Waste Disposal. We dispose of all Wygen I coal ash and scrubber wastes in mined areas at our WRDC coal mine under the terms and conditions of a state permit. The factors discussed under this caption for the Electric and Gas Utilities also impact our Power Generation segment in a similar manner.

Greenhouse Gas Regulations.The EPA’s GHG Tailoring Rule described in the Electric and Gas Utilities section will apply to the Wygen I and the Pueblo Airport Generating units upon a major modification, upon operating permit renewal or in the case of Pueblo Airport Generating Station, upon initial issuance of the Title V operating permit.


Mining Segment


Our Mining segment operates through our WRDC subsidiary. We surface mine, process and sell primarily low-sulfur sub-bituminous coal at our coal mine near Gillette, Wyoming. The WRDC coal mine, which we acquired in 1956 from Homestake Gold Mining Company, is located in the Powder River Basin. The Powder River Basin contains one of the largest coal reserves in the United States.eastern Wyoming. We produced approximately 3.83.7 million tons of coal in 2016.2019.


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 re-establishreestablish vegetation and plant life in accordance with our approved Post Mining Topographypost-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, 20162019 was 2.07,2.30 which increased from the prior year as we continued mining in areas with higher overburden. We expect our stripping ratio to decrease tobe approximately 1.92.18 by the end of 20172020 as we mine back intoin areas with lowercomparable overburden.


Mining rights to the coalreserves are based on fourthree federal leases and one state lease. The federal leases expire between April 30, 2019March 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, 2016,2019, we estimated our recoverable coal reserves to be approximately 200185 million tons, based on a life-of-mine engineering study utilizing currently available drilling data and geological information prepared by internal engineering studies. The recoverable coal reserve life is equal to approximately 5250 years at the current production levels. Our recoverable coal reserve estimates are periodically updated to reflect past coal production and other geological and mining data. Changes in mining methods or the utilization of new technologies may increase or decrease the recovery basis for a coal seam. Our recoverable coal reserves include reserves that can be economically and legally extracted at the time of their determination. We use various assumptions in preparing our estimate of recoverable coal reserves. See Risk Factors under Mining for further details.


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


South Dakota Electric for use at the 90 MW Neil Simpson II plant.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.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 362 MW Wyodak power plant owned 80% by PacifiCorp and 20% by South Dakota Electric. PacifiCorp is obligated to purchase a minimum of 1.5 million tons of coal each year of the contract term, subject to adjustments for planned outages. South Dakota Electric is also obligated to purchase a minimum of 0.375 million tons of coal per year for its 20% share of the power plant. This contract expires at the end of December 2022;


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


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


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


Our Mining segment sells coal to South Dakota Electric and Wyoming Electric for all of their requirements under cost-based agreements that regulate earnings from these affiliate coal sales to a specified return on our coal mine’s cost-depreciated investment base. The return calculated annually is 400 basis points above A-rated utility bondsMoody’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 plantPlant is determined by the coal supply agreement described above. The agreement included a price adjustment in 2014, and an additional price adjustment in 2019. The price adjustmentsadjustment essentially allowallowed us to retain the full economic advantage of the mine’s location adjacent to the plant. The price adjustments areadjustment was based on the market price of coal plus considerations for the avoided costs of rail transportation and a coalan unloading facility, which PacifiCorp would have to incur if it purchased coal from another mine. In addition, the agreement also providesprovided for the monthly escalation of coal 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 10-Year CorporateUtility Bond Index plus 400 basis points with the base price being adjusted on a 5-year interval. The agreement stipulates that WRDC will supply coal to the 90 MW Wygen I plant through June 30, 2038.


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


Additionally, coal competes with other energy sources, such as natural gas, wind, solar and hydropower. Costs and other factors relating to these alternative fuels, such as safety, environmental considerations and availability affect the overall demand for coal as a fuel.


Environmental Regulation. The construction and operation of coal minesMatters. We are subject to environmental protection and land use regulation in the United States. These laws and regulations often require a lengthy and complex process of obtaining licenses, permits and approvals from federal, state and local agencies. Many of the environmental issueslaws and regulations discussed under the Electric Utilities also apply to our Mining segment. Specifically, the EPA is examining plans to reduce methane emissions from coal mines as partproviding for air, water and solid waste pollution control; state facility-siting regulations; zoning and planning regulations of former President Obama’s Climate Action Plan.certain state and local authorities; federal health and safety regulations; and state hazard communication standards. See Environmental Matters section for further information.


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

Ash is the inorganic residue remaining after the combustion of coal. Ash from our Wyoming power plants, as well as PacifiCorp’s Wyodak power plant, is disposed of in the mine and is utilized for backfill to meet permitted post-mining contour requirements. On December 19, 2014, the EPA signed national disposal regulations regulating coal ash as a solid waste. While these regulations do not address mine backfill, it is expected the U.S. Office of Surface Mining (OSM) will collaborate with the EPA and propose mine backfill regulations in 2017. These regulations may increase the cost of ash disposal for the power plants and/or increase backfill costs for the coal mine.

Results of the 2016 U.S elections may have an impact on newly issued and proposed regulations and we will continue to monitor these developments.

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 planplans that providesprovide for orderly mining, reclamation and restoration of the WRDC mine. We have approved mining permits and are in compliance with other permitting programs administered by various regulatory agencies. The WRDC coal mine is permitted to operate under a five yearfive-year mining permit issued by the State of Wyoming. In 2016, that five yearfive-year permit was re-issued. Based on extensive reclamation studies, we have accrued approximately $12$14 million for reclamation costs as of December 31, 2016. Mining regulatory requirements continue to increase, which impose2019. See additional cost on the mining process.


Oil and Gas Segment

Our Oil and Gas segment, which conducts business through BHEP and its subsidiaries, acquires, explores for, develops and produces natural gas and crude oilinformation in the United States primarily in the Rocky Mountain region. Our Oil and Gas business is focused on supporting the implementationNote 8 of a planned utility Cost of Service Gas Program in partnership with our own and other utilities, while maintaining the upside value of our Piceance Basin and other assets. We are divesting non-core assets while retaining only those best suited for a Cost of Service Gas Program. In previous years, we successfully focused our efforts on proving up the potential of the Mancos formation for our Piceance Basin asset, while improving our drilling and completion practices for the Mancos. Due to sustained low oil and natural gas prices throughout 2016, Piceance Basin daily gas production was limited to meet minimum contractual gas processing obligations. We are currently assessing the Piceance Basin assets to determine their potential fit for a Cost of Service Gas Program.

As of December 31, 2016, the principal assets of our Oil and Gas segment included: (i) operating interests in crude oil and natural gas properties, including properties in the San Juan Basin (with holdings primarily on the tribal lands of the Jicarilla Apache Nation in New Mexico and Southern Ute Nation in Colorado), the Powder River Basin (Wyoming) and the Piceance Basin (Colorado); (ii) non-operated interests in crude oil and natural gas properties, including wells located in various producing basins in several states; and (iii) a 44.7% ownership interest in the Newcastle gas processing plant and associated gathering system located in Weston County, Wyoming. The plant, operated by Western Gas Partners, LP, is adjacent to our producing properties in that area and BHEP’s production accounts for more than 47% of the facility’s throughput. We also own natural gas gathering, compression and treating facilities, and water collection and delivery systems serving the operated San Juan and Piceance Basin properties and working interests in similar facilities serving our Wyoming properties.

At December 31, 2016, we had total reserves of approximately 78 Bcfe, of which natural gas comprised 70%, crude oil comprised 17% and NGLs comprised 13%. The majority of our reserves are located in select crude oil and natural gas producing basins in the Rocky Mountain region. Approximately 10% of our reserves are located in the San Juan Basin of northwestern New Mexico, primarily in the East Blanco Field of Rio Arriba County; 31% are located in the Powder River Basin of Wyoming, primarily in the Finn-Shurley Field of Weston and Niobrara counties; and 56% are located in the Piceance Basin of western Colorado, primarily in Mesa county.

Summary Oil and Gas Reserve Data

The summary information presented for our estimated proved developed and undeveloped crude oil, natural gas, and NGL reserves and the 10% discounted present value of estimated future net revenues is based on reports prepared by Cawley Gillespie & Associates (CG&A), an independent consulting and engineering firm located in Fort Worth, Texas. Reserves were determined consistent with SEC requirements using a 12-month average product price calculated using the first-day-of-the-month price for each of the 12 months in the reporting period held constant for the life of the properties. Estimates of economically recoverable reserves and future net revenues are based on a number of variables, which may differ from actual results. Reserves for crude oil, natural gas, and NGLs are reported separately and then combined for a total MMcfe (where oil and NGLs in Mbbl are converted to an MMcfe basis by multiplying Mbbl by six).

The SEC definition of “reliable technology” allows the use of any reliable technology to establish reserve volumes in addition to those established by production and flow test data. This definition allows, but does not require us, to book PUD locations that are more than one location away from a producing well. We normally only include PUDs that are one location away from a producing well in our volume reserve estimate. However, we have no PUDs as of December 31, 2016, therefore we have not included any PUDs in our reserves estimates as of December 31, 2016. Companies are allowed, but not required, to disclose probable and possible reserves. We have elected not to report these additional reserve categories. Additional information on our oil and gas reserves, related financial data and the SEC requirements can be found in Note 21 in 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 maintain adequate and effective internal controls over the reserve estimation process as well as the underlying data upon which reserve estimates are based. The primary inputs to the reserve estimation process are comprised of technical information, financial data, ownership interest and production data. All field and reservoir technical information, which is updated annually, is assessed for validity when the reservoir engineers hold technical meetings with geoscientists, operations and land personnel to discuss field performance and to validate future development plans. Our internal engineers and our independent reserve engineering firm, CG&A, work independently and concurrentlyplan to develop reserve volume estimates. Current revenue and expense information is obtained from our accounting records, whicha 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 external quarterly reviews, annual auditsa variety of state and internal controls over financial reporting.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 current financial dataof 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 commodity prices, lease operating expenses, production taxesmechanical malfunctions. State and field commodity price differentialsfederal regulatory agencies typically excuse short-term emissions exceedances if they are updatedreported 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.


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 reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. Our current ownership in mineral interests and well production data are also subject to the aforementioned internal controls over financial reporting and they are incorporated in the reserve database and verified to ensure their accuracy and completeness. Once the reserve database has been entirely updatedWyodak Plant, of which South Dakota Electric owns 20%. The EPA did not agree with current information and all relevant technical support materials have been assembled, CG&A meets with our technical personnel to review field performance and future development plans to further verify their validity. Following these reviews, the reserve database, including updated cost, price and ownership data, is furnished to CG&A so they can prepare their independent reserve estimates and final report. Access to our reserve database is restricted to specific members of the engineering department.

CG&A is a Texas Registered Engineering Firm. Our primary contact at CG&A is Mr. Zane Meekins. Mr. Meekins has been practicing consulting petroleum engineering since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas,Wyoming’s determination and overruled it in a memberFederal 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 Societylegal action, settled with the EPA. In lieu of Petroleum Evaluation Engineers (SPEE),going to court, PacifiCorp entered into mediation with the EPA and has over 29 years of practical experience in petroleum engineering and over 27 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 withconservation groups. PacifiCorp submitted a Bachelor of Science in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining“Request for Reconsideration” on October 24, 2019 to the EstimatingEPA and Auditingprovided a copy to the court. The purpose of Oilthe 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 Reserves Information promulgated byPlants (FMGP). Federal and state laws authorize the Society of Petroleum Engineers and he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SECEPA and other industry reserves definitions and guidelines.

BHEP’s Engineering Manager isagencies 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 technical person primarily responsible for overseeing our third party reserve estimates. He has 30 years of experience as a petroleum engineer. He has over 23 years of experience working closelyenvironment. We are currently in discussions with internal and third party qualified reserve estimators in major and mid-sized oil and gas companies. He graduated from the University of Wyoming in 1986 with a Bachelor of Science degree in Petroleum Engineering.

Minor differences in amounts may result in the following tables relating to oil and gas reserves due to rounding.

The following tables set forth summary information concerning our estimated proved developed and undeveloped reserves, by basin, as of December 31, 2016, 2015 and 2014:
Proved ReservesDecember 31, 2016
 TotalPiceanceSan JuanWillistonPowder RiverOther
Developed Producing -      
Natural Gas (MMcf)54,489
40,877
7,476
—
4,544
1,592
Oil (Mbbl)2,229
16
9
—
2,189
15
NGLs (Mbbl)1,710
419
—
—
1,092
199
Total Developed Producing (MMcfe)78,123
43,487
7,530
—
24,230
2,876
       
Developed Non-Producing -      
Natural Gas (MMcf)81
64
10
—
7
—
Oil (Mbbl)13
—
—
—
13
—
NGLs (Mbbl)2
—
—
—
2
—
Total Developed Non-Producing (MMcfe)171
64
10
—
97
—
       
Undeveloped -      
Total Undeveloped (MMcfe)—
—
—
—
—
—
       
Total MMcfe78,294
43,551
7,540
—
24,327
2,876

Proved ReservesDecember 31, 2015
 TotalPiceanceSan JuanWillistonPowder RiverOther
Developed Producing -      
Natural Gas (MMcf)69,049
43,527
18,927
726
3,473
2,395
Oil (Mbbl)3,415
36
5
375
2,986
13
NGLs (Mbbl)1,619
679
—
26
863
51
Total Developed Producing (MMcfe)99,255
47,819
18,958
3,135
26,566
2,777
       
Developed Non-Producing -      
Natural Gas (MMcf)4,341
4,010
324
4
3
—
Oil (Mbbl)19
6
—
2
11
—
NGLs (Mbbl)134
133
—
—
1
—
Total Developed Non-Producing (MMcfe)5,263
4,846
324
18
75
—
       
Undeveloped -      
Natural Gas (MMcf)22
—
—
22
—
—
Oil (Mbbl)14
—
—
14
—
—
NGLs (Mbbl)—
—
—
—
—
—
Total Undeveloped (MMcfe)106
—
—
106
—
—
       
Total MMcfe104,624
52,665
19,282
3,259
26,641
2,777


Proved ReservesDecember 31, 2014
 TotalPiceanceSan JuanWillistonPowder RiverOther
Developed Producing -      
Natural Gas (MMcf)51,718
16,802
24,349
650
4,231
5,679
Oil (Mbbl)3,779
54
11
494
3,191
28
  NGLs (Mbbl)1,472
344
—
25
1,007
96
Total Developed Producing (MMcfe)83,222
19,190
24,415
3,764
29,419
6,423
       
Developed Non-Producing -      
Natural Gas (MMcf)5,709
4,920
183
—
—
630
Oil (Mbbl)—
—
—
—
—
—
  NGLs (Mbbl)58
58
—
—
—
—
Total Developed Non-Producing (MMcfe)6,056
5,268
183
—
—
630
       
Undeveloped -      
Natural Gas (MMcf)8,013
7,833
—
180
—
—
Oil (Mbbl)496
6
—
159
331
—
  NGLs (Mbbl)191
191
—
—
—
—
Total Undeveloped (MMcfe)12,134
9,015
—
1,134
1,986
—
       
Total MMcfe101,416
33,465
24,596
4,898
31,405
7,053

Change in Proved Reserves

The following tables summarize the change in quantities of proved developed and undeveloped reserves by basin, estimated using SEC-defined product prices, as of December 31, 2016, 2015 and 2014:
Crude OilDecember 31, 2016
(in Mbbl)TotalPiceanceSan JuanWillistonPowder RiverOther
Balance at beginning of year3,450
42
5
392
2,998
13
Production(319)(10)(2)(103)(201)(3)
Additions - acquisitions (sales)(570)(15)—
(289)(265)(1)
Additions - extensions and discoveries3
—
—
—
3
—
Revisions to previous estimates(322)(1)6
—
(333)6
Balance at end of year2,242
16
9
—
2,202
15

Natural GasDecember 31, 2016
(in MMcf)TotalPiceanceSan JuanWillistonPowder RiverOther
Balance at beginning of year73,412
47,541
19,252
751
3,475
2,393
Production(9,430)(5,768)(2,736)(177)(220)(529)
Additions - acquisitions (sales)(1,291)(68)—
(574)(15)(634)
Additions - extensions and discoveries52
52
—
—
—
—
Revisions to previous estimates (a)
(8,173)(817)(9,029)—
1,311
362
Balance at end of year54,570
40,940
7,487
—
4,551
1,592



Natural Gas LiquidsDecember 31, 2016
(in Mbbl)TotalPiceanceSan JuanWillistonPowder RiverOther
Balance at beginning of year1,752
812
—
26
863
51
Production(133)(66)—
(9)(49)(9)
Additions - acquisitions (sales)(17)—
—
(17)—
—
Additions - extensions and discoveries—
—
—
—
—
—
Revisions to previous estimates110
(327)—
—
280
157
Balance at end of year1,712
419
—
—
1,094
199


 December 31, 2016
Total MMcfeTotalPiceanceSan JuanWillistonPowder RiverOther
Balance at beginning of year104,624
52,665
19,282
3,259
26,641
2,777
Production(12,142)(6,224)(2,748)(849)(1,720)(601)
Additions - acquisitions (sales)(4,813)(158)—
(2,410)(1,605)(640)
Additions - extensions and discoveries70
52
—
—
18
—
Revisions to previous estimates (a)
(9,445)(2,785)(8,993)—
993
1,340
Balance at end of year78,294
43,550
7,541
—
24,327
2,876
__________
(a)Revisions to prior year estimates is primarily due to the impact of lower prices on the economics of the San Juan reserves.

Crude OilDecember 31, 2015
(in Mbbl)TotalPiceanceSan JuanWillistonPowder RiverOther
Balance at beginning of year4,276
59
12
652
3,522
31
Production(371)(10)(2)(90)(263)(6)
Additions - acquisitions (sales)(11)—
—
—
—
(11)
Additions - extensions and discoveries199
7
—
2
189
1
Revisions to previous estimates(643)(14)(5)(172)(450)(2)
Balance at end of year3,450
42
5
392
2,998
13


Natural GasDecember 31, 2015
(in MMcf)TotalPiceanceSan JuanWillistonPowder RiverOther
Balance at beginning of year65,440
29,565
24,533
842
4,216
6,284
Production(10,058)(5,715)(3,176)(142)(255)(770)
Additions - acquisitions (sales)(828)—
—
(1)—
(827)
Additions - extensions and discoveries (a)
24,462
24,427
—
4
21
10
Revisions to previous estimates (b)
(5,604)(736)(2,105)48
(507)(2,304)
Balance at end of year73,412
47,541
19,252
751
3,475
2,393



Natural Gas LiquidsDecember 31, 2015
(in Mbbl)TotalPiceanceSan JuanWillistonPowder RiverOther
Balance at beginning of year1,720
592
—
25
1,007
96
Production(102)(33)—
(8)(61)—
Additions - acquisitions (sales)—
—
—
—
—
—
Additions - extensions and discoveries232
232
—
—
—
—
Revisions to previous estimates(98)21
—
9
(83)(45)
Balance at end of year1,752
812
—
26
863
51


 December 31, 2015
Total MMcfeTotalPiceanceSan JuanWillistonPowder RiverOther
Balance at beginning of year101,416
33,465
24,596
4,898
31,404
7,053
Production(12,896)(5,973)(3,188)(730)(2,199)(806)
Additions - acquisitions (sales)(894)—
—
(1)—
(893)
Additions - extensions and discoveries (a)
27,048
25,861
—
16
1,155
16
Revisions to previous estimates (b)
(10,050)(688)(2,126)(924)(3,719)(2,593)
Balance at end of year104,624
52,665
19,282
3,259
26,641
2,777
__________
(a)Nine Mancos wells were completed and placed on production in 2015.
(b)Revisions to previous estimates were primarily driven by low commodity prices.

Crude OilDecember 31, 2014
(in Mbbl)TotalPiceanceSan JuanWillistonPowder RiverOther
Balance at beginning of year3,921
70
7
697
3,115
32
Production(337)(12)(1)(132)(189)(3)
Additions - acquisitions (sales)(40)—
—
(40)—
—
Additions - extensions and discoveries733
51
—
72
610
—
Revisions to previous estimates(1)(50)6
55
(14)2
Balance at end of year4,276
59
12
652
3,522
31


Natural GasDecember 31, 2014
(in MMcf)TotalPiceanceSan JuanWillistonPowder RiverOther
Balance at beginning of year63,190
21,265
26,903
1,067
7,299
6,656
Production(7,156)(2,273)(3,589)(180)(370)(744)
Additions - acquisitions (sales)(61)—
—
(61)—
—
Additions - extensions and discoveries11,003
10,911
—
83
1
8
Revisions to previous estimates(1,536)(338)1,219
(67)(2,714)364
Balance at end of year65,440
29,565
24,533
842
4,216
6,284



Natural Gas LiquidsDecember 31, 2014
(in Mbbl)TotalPiceanceSan JuanWillistonPowder RiverOther
Balance at beginning of year—
—
—
—
—
—
Production(135)(56)—
(5)(65)(9)
Additions - acquisitions (sales)—
—
—
—
—
—
Additions - extensions and discoveries182
178
—
4
—
—
Revisions to previous estimates1,673
470
—
26
1,072
105
Balance at end of year1,720
592
—
25
1,007
96


 December 31, 2014
Total MMcfeTotalPiceanceSan JuanWillistonPowder RiverOther
Balance at beginning of year86,713
21,677
26,938
5,242
26,001
6,855
Production(9,984)(2,681)(3,595)(997)(1,895)(816)
Additions - acquisitions (sales)(299)—
—
(299)—
—
Additions - extensions and discoveries16,495
12,286
—
536
3,664
9
Revisions to previous estimates (a)
8,491
2,183
1,253
416
3,634
1,005
Balance at end of year101,416
33,465
24,596
4,898
31,404
7,053
__________
(a)Revisions to prior year were primarily driven by commodity prices.

Production Volumes
  Year ended December 31, 2016
Location (Basin)FieldOil (in Bbl)Natural Gas (Mcfe)NGLs (in Bbl)Total (Mcfe)
San JuanEast Blanco2,126
2,289,930
—
2,302,686
San JuanAll others—
445,879
—
445,879
PiceancePiceance9,720
5,768,302
66,050
6,222,922
Powder RiverFinn Shurley111,789
192,030
46,659
1,142,718
Powder RiverAll others89,478
27,990
2,526
580,014
WillistonBakken103,098
176,822
8,956
849,146
All other propertiesVarious2,402
529,335
9,113
598,425
Total Volume 318,613
9,430,288
133,304
12,141,790


  Year ended December 31, 2015
Location (Basin)FieldOil (in Bbl)Natural Gas (Mcfe)NGLs (in Bbl)Total (Mcfe)
San JuanEast Blanco1,753
2,698,548
—
2,709,066
San JuanAll others—
477,710
—
477,710
PiceancePiceance9,977
5,713,509
32,935
5,970,981
Powder RiverFinn Shurley172,235
255,482
60,671
1,652,918
Powder RiverAll others91,402
—
—
548,412
Williston 
Bakken90,469
142,091
7,903
732,323
All other propertiesVarious5,657
770,038
175
805,030
Total Volume 371,493
10,057,378
101,684
12,896,440



  Year ended December 31, 2014
Location (Basin)FieldOil (in Bbl)Natural Gas (Mcfe)NGLs (in Bbl)Total (Mcfe)
San JuanEast Blanco1,793
2,389,973
—
2,400,731
San JuanAll others—
1,191,239
—
1,191,239
PiceancePiceance3,393
2,219,224
56,244
2,577,043
Powder RiverFinn Shurley153,632
263,491
60,142
1,546,136
Powder RiverAll others49,602
—
—
297,612
WillistonBakken115,980
116,170
4,359
838,204
All other propertiesVarious12,796
974,979
13,810
1,134,625
Total Volume 337,196
7,155,076
134,555
9,985,590

Other Information
 As of December 31, 2016As of December 31, 2015
Proved developed reserves as a percentage of total proved reserves on an MMcfe basis100%100%
   
Proved undeveloped reserves as a percentage of total proved reserves on an MMcfe basis—%—%
   
Present value of estimated future net revenues, before tax, discounted at 10% (in thousands)$40,611
$85,711

The following table reflects average wellhead pricing used in the determination of the reserves:
 December 31, 2016
 TotalPiceanceSan JuanWillistonPowder RiverOther
Gas per Mcf(a)
$2.25
$2.32
$2.34
$—
$1.30
$2.58
       
Oil per Bbl$37.35
$33.80
$27.26
$—
$37.41
$38.61
       
NGL per Bbl$11.92
$15.08
$—
$—
$9.83
$16.72

 December 31, 2015
 TotalPiceanceSan JuanWillistonPowder RiverOther
Gas per Mcf$1.27
$1.14
$1.49
$1.82
$1.35
$1.82
       
Oil per Bbl$44.72
$43.86
$43.15
$44.01
$44.81
$48.00
       
NGL per Bbl$18.96
$22.58
$—
$22.24
$15.15
$23.92


 December 31, 2014
 TotalPiceanceSan JuanWillistonPowder RiverOther
Gas per Mcf$3.33
$3.16
$3.41
$4.81
$2.65
$4.01
       
Oil per Bbl$85.80
$83.88
$82.84
$83.72
$86.26
$82.03
       
NGL per Bbl$34.81
$44.21
$—
$43.56
$28.04
$45.59
__________
(a)For reserves purposes, costs to gather gas previously netted from the gas price were reclassified into operating expenses in 2016, with approximate rates of $1.54/Mcf for Piceance, $0.92/Mcf for San Juan and $0.53/Mcf for all others. For accounting purposes, consistent with prior years, the sales price for natural gas is adjusted for transportation costs and other related deductions when applicable, as further described in Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.


Drilling Activity

In 2016, we participated in drilling 17 gross (0.10 net) and completing 22 gross (0.44 net) development wells that were sold effective July 1, 2016, and therefore, have not been included in the drilling statistics table below. A development well is a well drilled within a proved area of a reservoir known to be productive. An exploratory well is a well drilled to findEPA, state regulators, and/or produce oil or gas in an unproved area,other third-parties to find a new reservoir in a previously productive field ordetermine the ultimate resolution to extend a known reservoir. Gross wells represent the total wells we participated in, regardless of our ownership interest, while net wells represent the sum of our fractional ownership interests within those wells.these sites. As of December 31, 2016,2019, 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 4 wells in the Piceance Basin that have been drilled but not completed. The well completions have been deferred indefinitely.

The following tables reflect wells completed through our drilling activitiescontacted by a third-party who intends to manage and pay for the last three years that were included inclean-up at this site. The third-party is conducting site assessments and working with the annual reserves.State of Nebraska on a clean-up plan.

Year ended December 31,201620152014
Net Development WellsProductiveDryProductiveDryProductiveDry
Williston—
—
0.09
—
0.26
—
Powder River—
—
1.00
—
—
—
Total net development wells—
—
1.09
—
0.26
—

Year ended December 31,201620152014
Net Exploratory WellsProductiveDryProductiveDryProductiveDry
Piceance—
—
7.03
—
1.17
—
Powder River—
—
0.60
2.00
3.00
—
Total net exploratory wells—
—
7.63
2.00
4.17
—

Recompletion Activity

Recompletion activities forAffordable Clean Energy Rule. The EPA was directed to repeal, revise, and replace the years ended DecemberClean Power Plan rule. On August 31, 2016, 20152018, 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 2014 were insignificantapplies only to our overall oil and gas operations.


Productive Wells

The following table summarizes our gross and net productive wells at December 31, 2016, 2015 and 2014:
  December 31, 2016
 TotalPiceanceSan JuanWillistonPowder River
Other (a)
Gross Productive:      
Crude Oil398
1
1
—
391
5
Natural Gas315
59
142
—
8
106
Total713
60
143
—
399
111
       
Net Productive:      
Crude Oil282.87
—
0.96
—
281.26
0.65
Natural Gas191.79
47.44
129.13
—
0.16
15.06
Total474.66
47.44
130.09
—
281.42
15.71
___________________
(a)The majority of these wells are non-operated wells.

  December 31, 2015
 TotalPiceanceSan JuanWillistonPowder River
Other (a)
Gross Productive:      
Crude Oil532
2
1
102
422
5
Natural Gas474
60
150
—
9
255
Total1,006
62
151
102
431
260
       
Net Productive:      
Crude Oil299.13
0.15
0.96
3.29
294.09
0.64
Natural Gas208.92
49.81
136.92
—
0.21
21.98
Total508.05
49.96
137.88
3.29
294.30
22.62
___________________
(a)The majority of these wells are non-operated wells.

  December 31, 2014
 TotalPiceanceSan JuanWillistonPowder River
Other (a)
Gross Productive:      
Crude Oil515
1
3
101
401
9
Natural Gas690
75
155
—
9
451
Total1,205
76
158
101
410
460
       
Net Productive:      
Crude Oil302.38
0.17
2.91
3.32
294.47
1.51
Natural Gas270.27
62.37
145.15
—
0.23
62.52
Total572.65
62.54
148.06
3.32
294.70
64.03
___________________
(a)The majority of these wells are non-operated wells.


Acreage

The following table summarizes our undeveloped, developed and total acreage by location as of December 31, 2016:
 UndevelopedDevelopedTotal
 Gross
Net (a)
GrossNetGrossNet
Piceance32,997
22,177
68,151
55,906
101,148
78,083
San Juan27,027
27,138
24,936
23,672
51,963
50,810
Powder River101,750
75,449
22,600
14,715
124,350
90,164
Montana160
20
480
60
640
80
Other14,766
3,135
25,226
4,689
39,992
7,824
Total176,700
127,919
141,393
99,042
318,093
226,961
_________________
(a)Approximately 3% (14,081 gross and 3,406 net acres), 3% (22,834 gross and 4,405 net acres) and 7% (56,265 gross and 9,211 net acres) of our undeveloped acreage could expire in 2017, 2018 and 2019, respectively, if production is not established on the leases or further action is not taken to extend the associated lease terms. Decisions on extending leases are based on expected exploration or development potential under the prevailing economic conditions.

Competition. The oil and gas industry is highly competitive. We compete with a substantial number of companies ranging from those thatcoal-fired plants. These plants have greater financial resources, personnel, facilities and in some cases technical expertise, to a multitude of smaller, aggressive new start-up companies. Many of these companies explore, produce and market crude oil and natural gas. The primary areas in which we encounter considerable competition are in recruiting and maintaining high quality staff, locating and acquiring leasehold acreage, acquiring producing oil and gas properties, and obtaining sufficient drilling rig and contractor services, acquiring economical costs for drilling and other oil and gas services and marketing our production of oil, gas, and NGLs.

Seasonality of Business. Weather conditions affect the demand for, and prices of, natural gas and can also temporarily inhibit production and delay drilling activities, which in turn impacts our overall business plan. The demand for natural gas is typically higher in the fourth and first quarters of our fiscal year, which sometimes results in higher natural gas prices. Due to these seasonal fluctuations, results of operations on a quarterly basis may not reflect results which may be realized on an annual basis.

Delivery Commitments. In 2012, we entered into a ten-year gas gathering and processing contract for natural gas production from our properties in the Piceance Basin in Colorado, under which we pay a gathering fee per Mcf. This take or pay contract requires us to pay the fee on a minimum of 20,000 Mcf per day, regardless of the volume delivered. The ten-year term of the agreement became effective in first quarter of 2014 upon completion of the processing infrastructure capable of handling the committed volumes. In 2014, our delivery of production did not meet the minimum requirement, and in 2015, we did not meet the minimum requirements of this contract until mid-February. We have excess production capacity from wells completed in 2015, and we have four additional wells which have not yet been completed, therefore do not foresee any challenges in our ability to meet this commitment.

Operating Regulation. Crude oil and natural gas development and production activities are subject to various laws and regulations governing a wide variety of matters. Regulations often require multiple permits and bonds to drill, complete or operate wells, establish rules regarding the location of wells, well construction, surface use and restoration of properties on which wells are drilled, timing of when drilling and construction activities can be conducted relative to various wildlife and plant stipulations and plugging and abandoning of wells. We are also subject to various mineral conservation laws and regulations, including the regulation of the size of drilling and spacing/proration units, the density of wells that may be drilled in a given field and the unitization or pooling of crude oil and natural gas properties. Some states allow the forced pooling or integration of tracts to facilitate exploration, when voluntary pooling of lands and leases cannot be accomplished. The effect of these regulations may limit the number of wells or the locations where we can drill.


Various federal agencies within the United States Department of the Interior, particularly the BLM, the Office of Natural Resources Revenue and the Bureau of Indian Affairs, along with each Native American tribe, promulgate and enforce regulations pertaining to crude oil and natural gas operations and administration of royalties on federal onshore and tribal lands. These regulations include such matters as lease provisions, drilling and production requirements, environmental standards and royalty considerations. Each Native American tribe is a sovereign nation possessing the power to enforce laws and regulations independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees and other conditions that apply to lessees, operators and contractors conducting operations on tribal lands. One or more of these factors may increase our cost of doing business on tribal lands and impact the expansion and viability of our gas, oil and gathering operations on such lands.

In addition to being subject to federal and tribal regulations, we must also comply with state and county regulations, which have been going through significant change over the last several years. New regulations have increased costs and added uncertainty with respect to the timing and receipt of permits. We expect additional changes of this nature to occur in the future.

Environmental Regulations. Our operations are subject to various federal, state and local laws and regulations relating to the discharge of materials into, and the protection of, the environment. We must account for the cost of complying with environmental regulations in planning, designing, drilling, operating and abandoning wells. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production waste products, water and air pollution control procedures (such as spill prevention, control and countermeasure plans, storm water pollution prevention plans, groundwater monitoring, state air quality permits and underground injection control disposal permits), chemical storage or use, the remediation of petroleum-product contamination, identifying cultural resources and investigating threatened and endangered species. Certain states, such as Colorado, impose storm water requirements more stringent than the EPA’s and are actively implementing and enforcing these requirements. We take a proactive role in working with these agencies to ensure compliance.

Under state, federal and tribal laws, we could also be required to remove or remediate previously disposed waste, including waste disposed of or released by us, or prior owners or operators, in accordance with current laws, or to otherwise suspend or cease operations in contaminated areas, or to perform remedial well plugging operations or clean-up activities to prevent future contamination. We generate waste that is already subject to the RCRA and comparable state statutes. The EPA and various state agencies limit the disposal options for those wastes. It is possible that certain oil and gas wastes which are currently exempt from regulation, such as RCRA wastes, may in the future be designated as wastes under RCRA or other applicable statutes.

Hydraulic fracturing is an essential and common practice, which has been used extensively for decades in the oil and gas industry to enhance the production of natural gas and/or oil from dense subsurface rock formations. We routinely apply hydraulic fracturing techniques on our crude oil and natural gas properties. Our hydraulic fracturing mixture is approximately 90% water, 9.5% sand and 0.5% of certain chemical additives to fracture the hydrocarbon-bearing rock formation to enhance flow of hydrocarbons into the well-bore. Chemicals used in the fracturing process are publicly posted as required by state regulations. The process is regulated by state oil and natural gas commissions. However, the EPA does assert federal regulatory authority over certain hydraulic fracturing activities when diesel comprises part of the fracturing fluid. In addition, several agencies of the federal government including the EPA and the BLM are conducting studies of the fracture stimulation process, which may result in additional regulations. In the event federal, state, local or municipal legal restrictions are adopted in areas where we are conducting,implemented or plan to conduct operations, we may incur additional costs to comply with such regulations, experience delays or curtailmentimplement a majority of the efficiency requirements listed in the pursuitrule.

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 exploration, development or production activities and perhaps even be precludedcoal ash impoundments. WRDC is exempt from utilizing fracture stimulation which may effectively preclude the drilling of wells. In May 2013, the U.S. DepartmentEPA CCR because ash is used for backfill reclamation in areas previously mined. The current administration has not pursued further modification of the Interior’s BLM re-proposed rules regulatingCCR.

Environmental risk changes constantly with the useimplementation of hydraulic fracturingnew 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 Federalenvironmental matters, see Item 1A and Indian Lands. BLM issued the final rule March 20, 2015. Subsequently on September 30, 2015, the U.S. District Court for the District of Wyoming issued a preliminary injunction preventing the BLM from enforcing the final rule on federal and Indian lands. RegardlessNote 19 of the rule status, we already employ these practices in our hydraulic fracturing operations as described below, and if this rule should be re-issued, it will have minimal impact on our operations. All of these new or proposed regulations are expected to result in additional costs to our operations.

In 2011 and 2012, the EPA issued several air quality regulations that impact our operations. These include emission standards for reciprocating internal combustion engines (RICE requirements), new source performance standards for VOCs and SO2 and hazardous air pollutant standards for oil and natural gas production, as well as natural gas transmission and storage (Quad O requirements). Since 2011, we have been in compliance with these new requirements and have been meeting the Quad O green completion requirements (directing flowback gas from natural gas wells to sales) effective January 2015.


In 2013, we participated in the State of Colorado’s stakeholder process to incorporate EPA Quad O requirements into state regulation. Colorado regulations were finalized in early 2014. New Mexico incorporated Quad O regulations, effective December 19, 2013. Wyoming incorporated Quad O regulations effective January 3, 2014.

Our policy is to meet or exceed all applicable local, state, tribal and federal regulatory requirements when drilling, casing, cementing, completing and producing wells that we operate. We follow industry best practices for each project to ensure safety and minimize environmental impacts. Effective wellbore construction and casing design, in accordance with established recommended practices and engineering designs, is important to ensure mechanical integrity and isolation from ground water aquifers throughout drilling, hydraulic fracturing and production operations. We place priority on drilling practices that ensure well control throughout the construction and completion phases.

We conduct groundwater sampling before and after our drilling and completion operations. While this is a requirement in Colorado and Wyoming, we conduct this sampling in all states in which we act as the operator for these activities.

Our wells are constructed using one or more layers of steel casing and cement to form a continuous barrier between fluids in the well and the subsurface strata. The only subsurface strata connectedNotes to the inside of the wellbore are the intervals that we perforate for the purpose of producing oil and gas. We isolate potential sources of ground water by cementing our surface and/or protection casing back to surface. In areas where additional protection may be necessary or required by regulations, we will cement the intermediate and or production casing string(s) back to surface. The casing is pressure-tested to ensure integrity. We typically also run a cement bond log to determine the quality of the bond between the cement and the casing and the cement and the subsurface strata. Surface and/or protection casing string pressures are monitored when a well is stimulated. We also conduct a combination of tests during the life of the well to verify wellbore integrity. Our wells are designed to prevent natural gas and other produced fluids from migrating or leaking for the life of the well. We employ qualified companies to monitor the pressure response to ensure that rate and pressure of fracturing treatment proceeds as planned. Unexpected changesConsolidated Financial Statements in the rate or pressure are immediately evaluated and necessary action taken. We use the most effective and efficient water management options available. The handling, storage and disposal of produced water meets or exceeds all applicable state, local, tribal and federal regulatory standards and requirements.this Annual Report on Form 10-K.

Greenhouse Gas Regulations. The EPA promulgated an amendment to its GHG reporting requirements in November 2010, adding Petroleum and Natural Gas Systems to the mandatory annual reporting requirements. Initial data gathering commenced on January 1, 2011, with the first annual report submitted to the EPA in 2012. The EPA added additional reporting requirements in 2011. On October 22, 2015, the EPA expanded coverage to gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines. The first annual reports of emissions calculated using these new requirements are due to the EPA by March 31, 2017 to cover 2016 emissions. We are currently expanding our inventory system to accommodate these new requirements. This is a permanent program, with GHG emission reports now due to the EPA on an annual basis. The Oil and Gas segment is also impacted by GHG regulation in the state of New Mexico. Other states may implement their own such programs in the future.

On January 14, 2015, the Obama Administration announced a goal to reduce methane emissions from the oil and gas sector by 40-45% from 2012 levels, by 2025. Accordingly, on September 18, 2015, the EPA proposed standards for methane and VOC emissions from new and modified oil and gas production sources and natural gas processing and transmission sources. The rule was finalized May 12, 2016 and includes provisions for clarifying permitting requirements for determination of major/minor source status. Future site developments may incur permitting delays if required aggregation of adjacent operations results in a major source air permit requirement. Additionally, EPA plans to work with industry and states to reduce methane from existing oil and gas operations and is exploring regulatory opportunities for applying remote sensing technologies to further improve the identification and quantification of methane and VOC emissions. In 2016 the EPA sent out Information Collection Requests to owners of oil and gas operations to support this rule development. We have received these requests and are in the process of submitting the required data.

On November 18, 2016, the Department of Interior’s BLM finalized their Venting and Flaring Rule (Methane Rule), targeting reduction or elimination of venting, flaring and leaks of natural gas at new and existing oil and gas wells on public lands. This rule will result in additional monitoring costs at our Colorado, New Mexico and Wyoming operations. On November 18, 2016, the Wyoming and Montana Attorneys General filed a petition for review of this rule with the United States District Court for the District of Wyoming. The District Court did not issue a stay pending litigation outcome and this rule went into effect January 17, 2017.


Ozone Regulations. In 2015, the EPA developed guidelines for states to use in reducing ozone-forming pollutants from existing oil and gas systems in areas that do not meet the ozone health standard. The new ozone standards, finalized October 26, 2015 are not expected to impact our current operations. However, the new regulations are very close to background levels, the ozone concentration level that the average person is exposed to, and may have an impact on future development.


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 own an eight-story, 66,000 square foot office building where our corporate headquarters is located, an office building consisting of approximately 36,000 square feet, and a service center, warehouse building and shop with approximately 65,000 square feet.


In Rapid City, South Dakota, we have a new 220,000 square foot corporate headquarters building, under construction. Construction is expected to beHorizon Point, which was completed in the fourth quarter of 2017.

In Pueblo, Colorado, we own a building of approximately 46,600 square feet used for a service center and approximately 25,700 square feet used for a warehouse.

In Cheyenne, Wyoming, we own an operations center with approximately 25,000 square feet, and in Casper Wyoming, we own an 18,000 square foot distribution center.

In Papillion, Nebraska, we own an office building consisting of approximately 36,600 square feet; in Albion, Nebraska, we own an operations center with approximately 26,000 square feet; and in Kearney, Nebraska, we own an operations center with approximately 21,000 square feet.

In Fayetteville, Arkansas, we own an operations center with approximately 36,000 square feet.


In Arkansas, Nebraska,Colorado, Iowa, Colorado, Kansas, Nebraska, and Wyoming we own various office, service center, storage, shop and warehouse space totaling over 666,0001,030,000 square feet utilized by our Gas Utilities.


In Colorado, South Dakota, Wyoming, Colorado and MontanaWyoming we own various office, service center, storage, shop and warehouse space totaling approximately 117,000305,000 square feet utilized by our Electric Utilities and Mining segments.

In addition to our owned properties, we lease the following properties:

Approximately 8,800 square feet for an operations and customer call center and 9,10092,527 square feet of office space in Rapid City, South Dakota;

Approximately 37,600 square feet for a customer call and operations center in Lincoln, Nebraska, and approximately 12,000 square feet for an operations center in Norfolk, Nebraska;

Approximately 47,400 square feet of office space in Denver, Colorado, of which we sublease approximately 10,100 square feet to a third party, and approximately 27,000 square feet of office space in Golden, Colorado, which is the former SourceGas Corporate headquarters;

Approximately 35,000 square feet for office space and customer call center in Fayetteville, Arkansas;

Approximately 204,000 square feet of various office, service center and warehouse space leased by the Gas Utilities; and

Other offices and warehouse facilities locatedproperties 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, 20162019, we had 2,834 full-time2,944 employees. Approximately 27%25% of our employees are represented by a collective bargaining agreement.union. We have not experienced any labor stoppages in recent years. At December 31, 20162019, approximately 27%22% of our total employees and 25% of our Electric Utilities 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:employees included in continuing operations:
 Number of Employees
Corporate496At December 31, 2019
Corporate and Shared Services
1,273
Electric Utilities and Gas Utilities2,2131,609

Mining, Power Generation and Oil and GasMining12562

Total2,8342,944



At December 31, 20162019, certain of our 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 Electric
102
IBEW Local 667April 15, 2023
South Dakota Electric(a)132135

IBEW Local 1250March 31, 20172024
Wyoming Electric4823

IBEW Local 111June 30, 2019
Colorado Electric107
IBEW Local 667April 15, 20182024
Iowa Gas111113

IBEW Local 204July 31, 2020
Kansas Gas1918

Communications Workers of America, AFL-CIO Local 6407December 31, 20192024
Nebraska Gas(b)
10999

IBEW Local 244March 13, 20172022
Nebraska Gas (c)(a)
144146

CWA Local 7476October 30, 2019
Wyoming Gas (c)(a)
83101

CWA Local 7476October 30, 2019
Total753737

  
__________
(a)On January 26, 2017, South Dakota Electric’s contract was ratified with an expiration date of March 31, 2022.
(b)Negotiations for Nebraska Gas started in January 2017, with an expected ratification in March 2017. We do not anticipate any issues with the ratification.
(c)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. The followingRisks 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. These important factors and other matters discussed herein could cause our actual results or outcomes to differ materially.

OPERATING RISKS


Our current or future development, expansioncontinued success is dependent on execution of our strategic business plans and acquisition activities may not be successful, which could impairgrowth strategy.

Our results of operations depend, in significant part, on our ability to execute our strategic business plans and growth strategy.

Execution of Technology advancements, disruptive forces and innovations in the marketplace and changing business or regulatory conditions may negatively impact our future growth plan is dependent on successful ongoingcurrent plans and future development, expansion and acquisition activities. We can provide no assurance that we will be able to complete development projects or acquisitions we undertake or continue to develop attractive opportunities for growth. Factors that could cause our development, expansion and acquisition activities to be unsuccessful include:

Our inability to obtain required governmental permits and approvals or the imposition of adverse conditions upon the approval of any acquisition;

Our inability to secure adequate utility rates through regulatory proceedings;

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

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

Ourstrategies. An inability to successfully integrate any businesses we acquire;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.


Our inabilityWe may be subject to attractunfavorable federal and retain management or other key personnel;state regulatory outcomes.


Our inabilityregulated Electric and Gas Utilities are subject to negotiate acceptable acquisition, construction, fuel supply, power sales or other material agreements;

Reduced growth in the demand forcost-of-service regulation and earnings oversight from federal and eight state utility services in the markets we serve;

Changes in federal, state, local or tribal laws and regulations, particularly those which would make it more difficult or costlycommissions. This regulatory treatment does not provide any assurance as to fully develop our coal reserves, our oilachievement of desired earnings levels. Our retail electric and gas reservesutility 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 our power generation capacity;

Fuel prices or fuel supply constraints;

Pipeline capacity and transmission constraints;

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

Changes in tax rates and policies.

The SourceGas Transaction may not achieve its intended results, including anticipated operating efficienciesmatch our related costs and cost savings, which may adversely affect our business, financial condition or resultsallowed return on invested capital at any given time. While rate regulation is premised on the full recovery of operations.

While management expects that the SourceGas Transaction will result in various benefits, includingprudently incurred costs and a significant amountreasonable rate of operating efficiencies and other financial and operational benefits,return on invested capital, there can be no assurance regarding whenthat 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 to which we will beare able to realize thesepass 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 efficienciesresults including earnings, cash flow and liquidity.

We may be subject to future laws, regulations, or other benefits. Events outsideactions 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 control, including but not limitedexisting or future transmission, distribution, generation and storage facilities or coal mine. Further, these rules could create the need to regulatory changespurchase or developments,build clean-energy fuel sources to fulfill obligations to our customers. These actions could also result in increased operating costs which could adversely affectimpact customers and our ability to realize the anticipated benefits from the transaction.financial operating results including earnings, cash flow and liquidity.



Our financial performance depends on the successful operationmanagement of our facilities. If the risks involved in ourfacilities operations, are not appropriately managed or mitigated, our operations may not be successfulincluding ongoing operation, construction, expansion, and this could adversely affect our resultsrefurbishment.

Operation, construction, expansion and refurbishment of operations.

Operating electric generating facilities, oil and gas properties, the coal mine and electric and natural gas transmission and distribution systems, involvesnatural gas storage facilities, and a coal mine involve risks including:that could result in fires, explosions, property damage and personal injury, including death. These risks include:


Operational limitations imposed by environmentalInherent 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 regulatory requirements;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;


Interruptions to supplyOperating 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 fuelrecruiting and other commodities used in generation and distribution. Our utilities purchase fuel fromretaining skilled technical labor or the unavailability of such resources could have a number of suppliers. Our results of operations could be negatively impacted by disruptions in the delivery of fuel due to various factors, including but not limited to, transportation delays, labor relations, weather and environmental regulations, which could limitnegative impact on our utilities’ ability to operate their facilities;

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

operations. Our ability to transition and replace our retirement-eligible utility employees. Atemployees is a risk; at December 31, 2016,2019, approximately 27%25% of our Electric Utilities and Gas Utilities employees were eligible for regular or early retirement;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.


Inability to recruitEquipment and retain skilled technical labor;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;


Operating hazards such as leaks, mechanical problemsNatural gas supply for generation and accidents, including explosions, affecting ourdistribution. Our utilities purchase natural gas from a number of suppliers for our generating facilities and for distribution systemto 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 public safety, reliabilityour results of operations;

Governmental permits. The inability to obtain required governmental permits and customer confidence;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;


Electricity is dangerous for employees and the general public should they come in contact with power lines or electrical service facilities and equipment. Natural conditionsOperational limitations. Operational limitations imposed by environmental and other disasters such as wind, lightningregulatory requirements and winter storms can cause wildfires, pole failurescontractual agreements, including those that restrict the timing of generation plant scheduled outages, could negatively impact our results of operations;

Increased costs. Increased capital and associated property damageoperating costs to comply with increasingly stringent environmental and outages;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 areis 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; andfunctions.

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

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

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

The inability to obtain required governmental permits and approvals along with the cost of complying with or satisfying conditions imposed upon such approvals;

Contractual restrictions upon the timing of scheduled outages;

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

The unavailability or increased cost of equipment;

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

Supply interruptions, work stoppages and labor disputes;



Increased capital and operating costs to comply with increasingly stringent environmental laws and regulations;

Opposition by members of public or special-interest groups;

Weather interferences;

Availability and cost of fuel supplies;

Unexpected engineering, environmental and geological problems; and

Unanticipated cost overruns.

The ongoing operation of our facilitiesbusiness involves many of the risks described above, in addition to risks relatingassociated with threats to the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants may employ recently developed and technologically complex equipment, including newer environmental emission control technology.our overall business model, such as electrification initiatives. Any of these risks could cause us to experience negative financial results and damage to our reputation and public confidence. These risks could cause us to incur significant costs or be unable to deliver energy and/or operate below expected capacity levels, which in turn could reduce revenues increase expenses or cause us to incur higher operating and maintenance costs and penalties. While we maintain insurance 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.

Operating results can be adversely affected by variations from normal weather conditions.


Our utilityenergy 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 seasonal businessesa variety of hazards and weather patterns canoperating 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 impact on our operating performance. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating. 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 seasons. 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. Unusually mild summers and winters therefore could have an adverse effect on our financial operating results of operations, financial conditionincluding earnings, cash flow and cash flows.liquidity.

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

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

While our planned activity related to our Oil and Gas segment is limited, weather conditions can also limit or temporarily halt our drilling, completion and producing activities at our crude oil and natural gas operations. Primarily in the winter and spring, our operations can be curtailed because of cold, snow and wet conditions, and severe weather could exacerbate these operational issues. In addition, weather conditions and other events could temporarily impair our ability to transport our crude oil and natural gas production.



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

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

The success of our crude oil and natural gas operations is affected by the prevailing market prices of crude oil and natural gas. Crude oil and natural gas prices and markets historically have been, and are likely to continue to be, unpredictable. A decrease in crude oil or natural gas prices not only reduces revenues and profits, but also reduces the quantity and value of reserves that are commercially recoverable and may result in charges to earnings for impairment of the net capitalized cost of these assets. Crude oil and natural gas prices are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for crude oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control.

The proliferation of domestic crude oil and natural gas shale plays in recent years has provided the market with an abundant new supply of crude oil and natural gas, which has driven prices down in recent years. There is also risk that increased domestic resources could drive both crude oil and natural gas prices lower.

Our mining operation requires reliable supplies of replacement parts, explosives, fuel, tires and steel-related products. If the cost of these increase significantly, or if sources of supplies and mining equipment become unavailable to meet our replacement demands, our productivity and profitability could be lower than our current expectations.

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


Our revenues,financial operating results of operations and financial condition are impacted by demand in our service territories. Customer growth and usage may be impacted by a number of factors, including:including the voluntary reduction of consumption of electricity and natural gas by our customers in response to increases in prices and demand-side managementenergy efficiency programs, economic conditions impacting decreases in customers’ disposable income and the use of distributed generation resources or other emerging technologies. Continued technological improvements may make customer and third-party distributed generation and energy storage systems, including fuel cells, micro-turbines, wind turbines, solar cells and batteries, more cost effective and feasible for our customers. If more customers utilize their own generation, demand for energy from us would decline. Such developments could affect the price of energy and delivery of energy, require further improvements to our distribution systems to address changing load demands and could make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives.  Each of these factors could materially affect our financial operating results of operations, financial positionincluding earnings, cash flow and cash flows.liquidity.


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

Our Electric Utilities, Gas Utilities and Power Generation segment rely on pipeline companies and other owners of gas storage facilities to deliver natural gas to ratepayers, to supply our natural gas-fired power plants and to hedge commodity costs. If storage capacity is inadequate or transportation is disrupted, our ability to satisfy our obligations may be hindered. As a result, we may be responsible for damages incurred by our counterparties, such as the additional cost of acquiring alternative supply at then-current market rates, or for penalties imposed by state regulatory authorities.

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

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



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

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

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

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

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

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

To effectively operate our business, we rely upon a potential liability.

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


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

Risks associated with deployment of capital may impact our information technology systems wereability to failexecute 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 breachedaffected by, a cyber attack or a computer virus and be unable to recovervariety 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 a timely way, we would be unable to fulfill critical business functions and sensitive confidentialcommodity and other data could be compromised which couldprices, 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 not only on our financial results, but on our public reputation as well.



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

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. Agencies that historically sought voluntary compliance, or issued non-monetary sanctions, nowMany 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 operations and/or our financial results.operating results including earnings, cash flow and liquidity.


Certain Federal laws including the Migratory Bird Act and the Endangered Species Act, 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 or drilling projects, could be restricted or delayed, or we could be required to implement expensive mitigation measures.

Utilities

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

Our regulated electric and gas utility operations are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our retail electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the state public utility commissions will judge all of our costs, including our direct and allocated borrowing and debt service costs, to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that produce a full recovery of our costs and the return on invested capital allowed by the applicable state public utility commission.

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

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

We had approximately $1.3 billion of goodwill on our consolidated balance sheets as of December 31, 2016. A substantial portion of the goodwill is related to the SourceGas Acquisition and the Aquila Transaction. If we make changes in our business strategy or if market or other conditions adversely affect operations in any of our businesses, we may be forced to record a non-cash impairment charge, which would reduce our reported assets, net income and shareholders’ equity. Goodwill is tested for impairment annually or whenever events or changes in circumstances indicate impairment may have occurred. If the testing performed indicates that impairment has occurred, we are required to record an impairment charge for the difference between the carrying value of the goodwill and the implied fair value of the goodwill in the period the determination is made. The testing of goodwill for impairment requires us to make significant estimates about our future performance and cash flows, as well as other assumptions. These estimates can be affected by numerous factors, including: future business operating performance, changes in economic conditions and interest rates, regulatory, industry or market conditions, changes in business operations, changes in competition or changes in technologies. Any changes in key assumptions, or actual performance compared with key assumptions, about our business and its future prospects could affect the fair value of one or more business segments, which may result in an impairment charge.




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

Mining

If We also cannot quantify the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, our costs could be significantly greater than anticipated or be incurred sooner than anticipated.

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

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

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

Oil and Gas

Our inability to successfully include our Oil and Gas segment core assets in utility Cost of Service Gas Programs may result in additional material impairments of our Oil and Gas assets.

In our oil and gas business, we are actively divesting non-core assets while retaining those assets best suited for a Cost of Service Gas Program for our utilities and third-party utilities, and have refocused our professional staff on assisting with the implementation of a Cost of Service Gas Program. The implementation of Cost of Service Gas Programs will provide a long-term physical hedge for a portion of a utility’s gas supply, enhancing the quality of the overall gas supply portfolio. In addition to providing utility customers the potential benefits associated with more predictable and lower long-term natural gas prices, it also provides utilities an opportunity to increase earnings through investment in gas reserves. Cost of Service Gas Programs require regulatory approval from state commissions that regulate utility participants in these programs. Failure to obtain these approvals may result in additional impairments of our Oil and Gas assets, and could adversely affect the market perceptionremainder of our business operating results and stock price.



Estimates of the quantity and value of our proved oil and gas reserves may change materially due to numerous uncertainties inherent in estimating oil and natural gas reserves. Significant inaccuracies in interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.

The process of estimating crude oil and natural gas reserves requires interpretation of available technical data and various assumptions, including assumptions relating to economic factors. Significant variances in interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. Actual prices, production, development expenditures, operating expenses and quantities of recoverable crude oil and natural gas reserves may vary significantly from those assumed in our estimates. Any significant variance from the assumptions used could cause the actual quantity of our reserves and future net cash flow to be materially different from our estimates. In addition, results of drilling, testing and production, changes in future capital expenditures and fluctuations in crude oil and natural gas prices after the date of the estimate may result in substantial upward or downward revisions that could adversely affect our results of operations.


The potential adoption of federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in restrictions which could increase costs and cause delays to the completion of certain oil and gas wells and potentially preclude the economic drilling and completion of wells in certain reservoirs.

Hydraulic fracturing is an essential and common practice in the oil and gas industry used extensively for decades to stimulate production of natural gas and/or oil from dense subsurface rock formations. We routinely apply hydraulic fracturing techniques on our crude oil and natural gas properties. Hydraulic fracturing involves using mostly water, sand and a small amount of certain chemicals to fracture the hydrocarbon-bearing rock formation to enhance flow of hydrocarbons into the well-bore. The process is typically regulated by state crude oil and natural gas commissions. However, the EPA does assert federal regulatory authority over certain hydraulic fracturing activities when diesel comprises part of the fracturing fluid. In addition several agencies of the federal government including the EPA and the BLM are conducting studies of the fracturing stimulation process which may result in additional regulations. In addition, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide the federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process.

In the event federal, state, local or municipal legal restrictions on the hydraulic fracturing are adopted in areas where we are conducting or in the future plan to conduct operations, we may incur additional costs to comply with such regulations that may be significant, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from utilizing fracture stimulation and effectively preclude the drilling of wells.

Exploratory and development drilling are speculative activities that may not result in commercially productive reserves. Lack of drilling success could result in uneconomical investments.

While our planned activity related to our Oil and Gas segment is limited, drilling activities are subject to many risks, including the risk that no commercially productive oil or gas reservoirs will be encountered. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, many of which are beyond our control, including economic conditions, mechanical problems, pressure or irregularities in formations, title problems, weather conditions, compliance with governmental rules and regulations and shortages in or delays in the delivery of equipment and services. Such equipment shortages and delays are caused by the high demand for rigs and other needed equipment by a large number of companies in active drilling basins. Lack of drilling success could have a material adverse effect on our financial condition and results of operations.

We could incur additional write-downs of the carrying value of our natural gas and oil properties, which would cause a decrease in our assets and stockholders' equity and could adversely impact our results of operations.

We review the carrying value of our natural gas and oil properties under the full cost accounting rules of the SEC on a quarterly basis, which is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. Two primary factors in the ceiling test are natural gas and crude oil reserve quantities, which are impacted by current commodity prices, and SEC-defined crude oil and gas prices, both of which impact the present value of estimated future net revenues. We recorded non-cash impairment charges in 2016 and 2015 due to the full cost ceiling limitations. See Note 13 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.



FINANCING RISKS


OurA sub-investment grade credit ratings could be lowered below investment grade in the future. If this were to occur, itrating could impact our ability to access to capital our cost of capital and our other operating costs.markets.


Our issuer credit rating is Baa2 (Stable outlook) by Moody’s; BBBBBB+ (Stable outlook) by S&P; and BBB+ (Negative(Stable outlook) by Fitch. Reduction of our credit ratings could impair our ability to refinance or repay our existing debt and to complete new financings on reasonable terms, orif at all. A credit rating downgrade, particularly to a sub-investment grade, could also result in counterparties requiring us to post additional collateral under existing or new contracts or trades.contracts. In addition, a ratings downgrade would increase our interest expense under some of our existing debt obligations, including borrowings under our credit facilities.facilities, potentially significantly increasing our cost of capital and other associated operating costs.


Derivatives regulations included in current financial reform legislation 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 crude oil and natural gas derivative instruments for our hedging activities for our oilGas and gas production activities and our gas utilityElectric Utilities’ operations. We may also use interest rate derivative instruments to minimize the impact of interest rate fluctuations. As a result of Dodd-Frank regulations promulgated by the CFTC, we may be required to post collateral to clearing entities for certain swap transactions we enter into. In addition, our exchange-traded futures contracts are subject to futures margin posting requirements, which could have a significant impact on our business by reducing our ability to execute derivative transactions to reduce commodity price and interest rate uncertainty and to protect cash flows. Requirements to post collateral may cause significant liquidity issues by reducing our ability to use cash for investment or other corporate purposes, or may require us to increase our level of debt. In addition, a requirement for our counterparties to post collateral could result in additional costs being passed on to us, thereby decreasing our profitability.


Our hedging activities that are designed to protect against commodity price and financial market risks may cause fluctuations in reported financial results due to mark-to-market accounting requirements associated with such activities.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 or assets being hedged. The difference in accounting can result in volatility in reportedFluctuating commodity prices could have a negative effect on our liquidity, financial condition, and results even though the expected profit margin may be essentially unchanged from the dates the transactions were consummated.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 otherkey valuation assumptions could require us to make significant unplanned contributions to our pension plans and other postretirement benefit plans. Increasing costs associated with our defined benefit retirement plans may adversely affect our results of operations, financial position or liquidity.


As discussed in Note 18 of the Consolidated Financial Statements in this Annual Report on Form 10-K, we have one defined benefit pension plan and several defined post-retirement healthcare plans and non-qualified retirement plans that cover certain eligible employees. Assumptions related to future costs,interest rates, expected return on investments, interest ratesmortality and other key actuarial assumptions have a significant impact on our funding requirements and the expense recognized related to these plans. These estimatesAn 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 assumptions may change based on actual return on plan assets, changes in interest rates and any changes in governmental regulations.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 conditionscondition and are subject to declaration by the Board of Directors. Our operating subsidiaries have certain restrictions on their ability to transfer funds in the form of dividends or loans to us. See “Liquidity“Liquidity and Capital Resources”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.


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


A future recession, 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 affectedimpacted 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, risks associated with our oil and gas exploration and production activities, distribution property losses, cyber-security risks and dangers that exist in the gathering and transportation of gas in pipelines.


While we maintain insurance coverage for our operated wells and we participate in insurance coverage maintained by the operators of our wells, there can be no assurances that such coverage will be sufficient to prevent a material adverse effect to us if any of the foregoing events occur.

Increasing costsCosts associated with our health carehealthcare plans and other benefits may adversely affect our results of operations, financial position or liquidity.could increase significantly.


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

processes. Our electric and 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.


Prior to the Acquisition, SourceGas was a private company, exempt from reporting and control requirements under Section 404 of the Sarbanes-Oxley Act of 2002. As permitted by the guidance set forth by the Securities and Exchange Commission, the acquired SourceGas businesses are not included in management’s assessment of internal control over financial reporting for the year ended December 31, 2016.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. While we expect our control system to adequately integrate the SourceGas processes, we cannot be certain that our current design for internal control over financial reporting, or any additional changes to be made, will be sufficient to enable management to determine that our internal controls are effective for any period, or on an ongoing basis. 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


FederalDevelopments in federal and state laws concerning greenhouse gasGHG regulations and air emissions mayrelating to climate could materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain.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.


We own and operate regulated and non-regulated fossil-fuel generating plants in Colorado, South Dakota Wyoming and Colorado. Recent developmentsWyoming. 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 caption “Environmental Matters.section “Environmental Matters”.


The GHG Tailoring Rule, effective June 2010, will impact usThere is uncertainty surrounding current climate regulation due to legal challenges, new federal climate legislation anticipated in the event of a major modification at an existing facilityfuture, or in the event of a new major source as defined by EPA regulations. Upon renewal of operating permits for existing facilities, monitoringstate climate legislation and reporting requirements will be implemented. New projects or major modifications to existing projects will result in a Best Available Control Technology review that could impose more stringent emissions control practices and technologies. The EPA’s GHG New Source Performance Standard for new steam electric generating units, published October 2015, effectively prohibits new coal-fired units until carbon capture and sequestration becomes technically and economically feasible.

On October 23, 2015, the EPA finalized the CPP to cut carbon emissions from existing electric generating units. The design of the CPP is to decrease existing coal-fired generation, increase the utilization of existing gas generation, increase renewable energy and demand side management. The rule, which does not propose to regulate individual emission sources, calls for each state to develop plans to meet the EPA-assigned statewide average emission rate target for that state by 2030. The rule also allows states to formulate a regional approach whereby they would join with other states and be assigned a new single target for the group. The U.S. Supreme Court entered an order staying the CPP in February 2016, pending appeal. The effect of the order is to delay the CPP’s compliance deadlines until challenges to the CPP have been fully litigated and the U.S. Supreme Court has ruled. In 2015 and again in 2016, we met with the staff of state air programs and public utility commissions on several occasions.regulation. We will continue to work closely with state regulatory staff as these plans develop.

Due to uncertainty as to the final outcome of federal climate change legislation, legal challenges, state clean power plan developments or regulatory changes under the Clean Air Act, we cannot definitively estimate the effect of GHG legislation or regulation on our results of operations, financial position or cash flows or financial position.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 generatingcoal-fired power generation facilities and potential increased load of our combined cycle natural gas firedgas-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.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, and anyor failure to do so,comply, could adversely affect our results of operations, financial position or liquidity.increase significantly.


Our business issegments are subject to extensive energy,numerous environmental and other laws and regulations affecting many aspects of federal, state, tribalpresent and local authorities. Wefuture 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 mustrequire the business segments to obtain and comply with a wide variety of regulations,environmental licenses, permits, inspections and other approvals in order to operate, which can require significant capital expenditure and operating costs. If we fail to complyapprovals. Compliance with these requirements, we could be subject to civil or criminal liability and the imposition of penalties, liens or fines, claims for property damage or personal injury, or environmental clean-up costs. In addition, existing regulations may be revised or reinterpreted and new 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 adoptedsuccessful 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 become applicableregulations 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 us or our facilities, which could require additional unexpected expenditures or cause us to reevaluate the feasibility of continued operations at certain sites andcomply with current environmental regulations will have a detrimentalmaterial adverse effect on our business.



In connection with certain acquisitions, we assumed liabilities associated with the environmental condition of certain properties, regardless of when such liabilities arose, whether known or unknown, and in some cases agreed to indemnify the former owners of those properties for environmental liabilities. Future steps to bring our facilities into compliance or to address contamination from legacy operations, if necessary, could be expensive and could adversely affect ourbusiness segments’ financial position, results of operations and financial condition. Environmentalor cash flows, future environmental compliance expenditurescosts could be substantial in the future if the trend towards stricter standards, greater regulation, more extensive permitting requirements and an increase in the number of assets we operate continues.have a significant negative impact.


The characteristics of coal may make it difficult for coal users to comply with various environmental standards related to coal combustion or utilization and the use of alternative energy sources for power generation as mandated by states could reduce coal consumption.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. Reductions in mercury emissions required by EPA’s MATS rule described earlier, will likely require some power plants to install new equipment, at substantial cost, or discourage the use of certain coals containing higher levels of mercury. The EPA’s October 23, 2015 CPP described earlier, which has been stayed pending appeal, is designed to reduce carbon emissions from existing electric generating units. The basis of the CPP is to decrease existing coal-fired generation, increase the utilization of existing gas fired combined cycle generation, increase renewable energy and demand side management. This rule could have a significant impact on our coal and natural gas generating fleet. The rule calls for states to develop plans to meet their assigned emission rate targets by 2030. The rule also allows states to formulate a regional approach whereby they would join with other states and be assigned a new single target for the group.


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 regulationrule. At this time, it is expected tonot known what effect this will have an adverse effect 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 operationsfinancial operating results including earnings, cash flow and financial resultsliquidity could be adversely impacted.


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.



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.


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, 20162019, we had 3,8603,586 common shareholders of record and approximately 28,00032,285 beneficial owners, representing all 50 states, the District of Columbia and 86 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 25, 201729, 2020 meeting, our Board of Directors declared a quarterly dividend of $0.445$0.535 per share, equivalent to an annual dividend rate of $1.78$2.14 per share, marking 2017 as the 47thshare. This equivalent rate, if declared and paid in 2020, will represent 50 consecutive years of annual dividend increase for the Company.increases.


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

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

Year ended December 31, 2016First QuarterSecond QuarterThird QuarterFourth Quarter
Dividends paid per share$0.420
$0.420
$0.420
$0.420
Common stock prices


 
High$61.13
$63.53
$64.58
$62.83
Low$44.65
$56.16
$56.86
$54.76

Year ended December 31, 2015First QuarterSecond QuarterThird QuarterFourth Quarter
Dividends paid per share$0.405
$0.405
$0.405
$0.405
Common stock prices    
High$53.37
$52.96
$47.27
$47.51
Low$47.88
$43.48
$36.81
$40.00


UNREGISTERED SECURITIES ISSUED


There were no unregistered securities sold during 2016.2019.


ISSUER PURCHASES OF EQUITY SECURITIES
There were no equity securities acquired for the threetwelve months ended December 31, 2016.2019.



ITEM 6.SELECTED FINANCIAL DATA


(Minor differences may result due to rounding)
Years Ended December 31,2016 2015 2014 2013 2012 2019 2018 2017 
2016 (a)
 2015 
(dollars in thousands, except per share amounts)(dollars in thousands, except per share amounts)         (dollars in thousands, except per share amounts)         
                    
Total Assets
$6,515,444
 $4,626,643
 $4,222,301
 $3,820,877
 $3,677,019
 $7,558,457
 $6,963,327
 $6,658,902
 $6,541,773
 $4,626,643
 
                    
Property, Plant and Equipment
                    
Total property, plant and equipment$6,412,223
 $4,976,778
 $4,563,400
 $4,259,445
 $3,930,772
 
Property, plant and equipment$6,784,679
 $6,000,015
 $5,567,518
 $5,315,296
 $3,849,309
 
Accumulated depreciation and depletion(1,943,234) (1,717,684) (1,357,929) (1,306,390) (1,229,159) (1,281,493) (1,145,136) (1,026,088) (929,119) (794,695) 
Total property, plant and equipment, net$4,468,989
 $3,259,094
 $3,205,471
 $2,953,055
 $2,701,613
 $5,503,186
 $4,854,879
 $4,541,430
 $4,386,177
 $3,054,614
 
                    
Capital Expenditures$467,119
 $458,821
 $391,267
 $379,534
 $347,980
           
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
 $—
 $275,000
 $—
 $103,973
 $5,743
 $5,743
 $5,743
 $5,743
 $—
 
Notes payable96,600
 76,800
 75,000
 82,500
 277,000
 349,500
 185,620
 211,300
 96,600
 76,800
 
Long-term debt, net of current maturities and deferred financing costs3,211,189
(a)1,853,682
(a)1,255,953
 1,383,714
 927,561
 
Common stock equity1,614,639
(b)1,465,867
(b)1,353,884
 1,283,500
 1,205,800
 
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$4,928,171
 $3,396,349
 $2,959,837
 $2,749,714
 $2,514,334
 $5,857,462
 $5,323,786
 $5,035,417
 $4,928,171
 $3,396,349
 
          
Capitalization Ratios          
Short-term debt, including current maturities2% 2% 12% 3% 15% 
Long-term debt, net of current maturities65%(a)55% 42% 50% 37% 
Common stock equity33% 43% 46% 47% 48% 
Total100% 100% 100% 100% 100% 
                    
Total Operating Revenues$1,572,974
 $1,304,605
 $1,393,570
 $1,275,852
 $1,173,884
 $1,734,900
 $1,754,268
 $1,680,266
 $1,538,916
 $1,261,322
 
                    
Net Income Available for Common Stock Net Income Available for Common Stock          Net Income Available for Common Stock         
Electric Utilities$85,827
 $77,579
(g)$57,270
(g)$49,003
(g)$52,123
(g)
Gas Utilities59,624
 39,306
(g)44,151
(g)35,838
(g)27,465
(g)
Power Generation25,930
(c)32,650
 28,516
 16,288
(c)21,328
 
Mining10,053
 11,870
 10,452
 6,327
 5,626
 
Oil and Gas(71,054)(b)(179,958)(b)(8,525) (1,751) 18,683
(b)
Corporate and intersegment eliminations(37,410)(d)(13,558)(d, g)(975) 12,602
(d)(15,808)(d)
Net Income (loss) available for common stock before discontinued operations72,970
 (32,111) 130,889
 118,307
 109,417
 
Income (loss) from discontinued operations, net of tax (e)
—
 —
 —
 (884) (6,977) 
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$72,970
 $(32,111) $130,889
 $117,423
 $102,440
 $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
 



SELECTED FINANCIAL DATA continued


Years Ended December 31,2016 2015 2014 2013 2012 
(dollars in thousands, except per share amounts)         
           
Dividends Paid on Common Stock$87,570
 $72,604
 $69,636
 $67,587
 $65,262
 
           
Common Stock Data(f) (in thousands)
          
Shares outstanding, average basic51,922
 45,288
 44,394
 44,163
 43,820
 
Shares outstanding, average diluted53,271
 45,288
 44,598
 44,419
 44,073
 
Shares outstanding, end of year53,382
 51,192
 44,672
 44,499
 44,206
 
           
Earnings (Loss) Per Share of Common Stock (in dollars)
        
Basic earnings (loss) per average share -          
Continuing operations$1.59
 $(0.71) $2.95
 $2.68
 $2.50
 
Discontinued operations (e)
—
 —
 —
 (0.02) (0.16) 
Non-controlling interest(0.19) —
 —
 —
 —
 
Total$1.41
 $(0.71) $2.95
 $2.66
 $2.34
 
Diluted earnings (loss) per average share -         
Continuing operations$1.55
 $(0.71) $2.93
 $2.66
 $2.48
 
Discontinued operations—
 —
 —
 (0.02) (0.16) 
Non-controlling interest(0.18) —
 —
 —
 —
 
Total$1.37
 $(0.71) $2.93
 $2.64
 $2.32
 
           
Dividends Declared per Share$1.68
 $1.62
 $1.56
 $1.52
 $1.48
 
           
Book Value Per Share, End of Year$30.25
 $28.63
 $30.31
 $28.84
 $27.28
 
           
Return on Average Common Stock Equity (full year)
4.7% (2.3)% 9.9% 9.4% 8.7% 




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
 
Years ended December 31,2016 2015 2014 2013 2012
Operating Statistics:         
Generating capacity (MW):         
Electric Utilities (owned generation)941
 841
 841
 790
 859
Electric Utilities (purchased capacity)110
 210
 210
 150
 150
Power Generation (owned generation)269
 269
 269
 309
 309
Total generating capacity1,320
 1,320
 1,320
 1,249
 1,318
          
Electric Utilities:         
MWh sold:         
Retail electric5,140,519
 4,990,594
 4,775,808
 4,642,254
 4,598,080
Contracted wholesale246,630
 260,893
 340,871
 357,193
 340,036
Wholesale off-system769,843
 1,000,085
 1,118,641
 1,456,762
 1,652,949
Total MWh sold6,156,992
 6,251,572
 6,235,320
 6,456,209
 6,591,065
          
Gas Utilities: 
         
Gas sold (Dth)79,165,742
 56,638,299
 64,861,411
 64,131,850
 51,620,293
Transport volumes (Dth)126,927,565
 77,393,775
 77,433,266
 73,730,017
 71,092,286
          
Power Generation Segment:         
MWh Sold1,868,513
 1,796,242
 1,760,160
 1,564,789
 1,304,637
MWh Purchased85,993
 68,744
 38,237
 5,481
 8,011
          
Oil and Gas Segment:         
Oil and gas production sold (MMcfe)12,142
 12,896
 9,986
 9,529
 12,544
Oil and gas reserves (MMcfe) (b)
78,294
 104,624
 101,416
 86,713
 80,683
          
Mining Segment:         
Tons of coal sold (thousands of tons)3,817
 4,140
 4,317
 4,285
 4,246
Coal reserves (thousands of tons)199,905
 203,849
 208,231
 212,595
 232,265

(a)Effective February 12, 2016, includes the debt associated withwe completed the SourceGas acquisition (see Note 6Transaction. Total cash consideration paid, net of debt assumed and working capital adjustment received, was $1.124 billion, funded with a combination of the Notes toissuance 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 Consolidated Financial Statements in this Annual Reportissuance of senior unsecured notes on Form 10-K).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 our crude oil and natural gas properties of $67 million. 2015 includes non-cash after-tax ceiling test impairment charges to our crude oil and natural gas properties of $158 million and a non-cash after-tax equity investment impairment charge of $2.9 million (see Note 13 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K). 2012 includes a non-cash after-tax ceiling test impairment charge to our crude oil and natural gas properties of $32 million offset by an after-tax gain on sale of $49 million related to our Williston Basin assets.million.
(c)
On April 14, 2016, BHEGBlack 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. 2013 includes $6.6 million after-tax expense relating to the settlement of interest rate swaps and write-off of deferred financing costs in conjunction with the prepayment of Black Hills Wyoming’s project financing.
(d)2017, 2016 and 2015 include incremental SourceGas AcquisitionTransaction costs, after-tax of $2.8 million, $30 million and $6.7 million, respectively. 2016 and 2015 also include after-tax internal labor costs attributable to the SourceGas Acquisition of $9.1 million and $3.0 million that otherwise would have been charged to other segments. 2013 and 2012 include $20 million and $1.2 million non-cash after-tax unrealized mark-to-market gains, respectively, related to certain interest rate swaps; 2013 also includes $7.6 million after-tax expense for a make-whole premium, write-off of deferred financing costs relating to the early redemption of our $250 million notes and interest expense on new debt, while 2012 includes an after-tax make-whole provision of $4.6 million for early redemption of our $225 million notes.
(e)Discontinued operations in 2013 and 2012 include post-closing adjustments and operations relating to Enserco, sold in 2012.
(f)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. In November 2015, we issued 6.3
(f)
The increase in 2018 included a $73 million sharestax benefit resulting from legal entity restructuring. See Note 15 of common stock, par value $1.00 per share at a price of $40.25.the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.
(g)Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported
2019 includes a non-cash after-tax impairment of $15 million in our Gas Utilities segment. Cheyenne Light’sinvestment in equity securities of a privately held oil and gas utility results have been reclassified fromcompany. See Note 1 of the Electric Utilities segmentNotes to the Gas Utilities segmentConsolidated Financial Statements in the amounts of $1.7 million, $2.3 million, $3.1 million and $0.5 millionthis Annual Report on Form 10-K for the years ending December 31, 2015, 2014, 2013 and 2012 respectively. Due to this reclassification, there also exists an intersegment elimination of $0.2 million that has been moved to “Corporate and intersegment eliminations” for the period ended December 31, 2015.more information.



For additional information on our business segments see Item 7.7. 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.

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

ITEMS Items 7 &MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
and 7A Index
Executive Summary
42
Prospective Information
46
Results of Operations - Consolidated Summary and 7A.Overview of Business Segments
OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
47
Non-GAAP Measure
50
Electric Utilities
51
Gas Utilities
52
Power Generation
54
Mining
55
Corporate
56
Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax Benefit (Expense)
56
Liquidity and Capital Resources
57
Debt, Equity and Liquidity
59
Cash Flow Activities
62
Capital Expenditures
64
Credit Ratings
64
Contractual Obligations and Off-Balance Sheet Items
66
Critical Accounting Estimates
67
Market Risk Disclosures
70
New Accounting Pronouncements
71
RISK


Executive Summary

We are a customer-focused, growth-oriented vertically-integrated utility company operating in the United States. We report our operationselectric and results in the following financial segments.

Electric Utilities: Our Electric Utilities segment generates, transmits and distributes electricity to approximately 208,500 customers in South Dakota, Wyoming, Colorado and Montana. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our own distribution systems. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates.

Gas Utilities: Our Gas Utilities conduct natural gas utility operationscompany 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 ourits Electric and Gas Utilities to 1.3 million customers in 824 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, WyomingMontana, Nebraska, South Dakota and Nebraska subsidiaries. Our Gas Utilities distribute and transport natural gas through our network to approximately 1,030,800 natural gas customers. Additionally, we sell temporarily-available, contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates.

We also provide non-regulated services throughWyoming. The Company conducts its utility operations under the name Black Hills Energy Services. Black Hills Energy Services provides approximately 55,000 retail distribution customerspredominantly in Nebraskarural areas of the Rocky Mountains and Wyoming with unbundled natural gas commodity offerings under the regulatory-approved Choice Gas Program. We also sell, installMidwestern states. The Company’s Electric Utilities are supported by our Power Generation and service air, heating and water-heating equipment, and provide associated repair service and protection plans under various trade names. Service Guard and CAPP primarily provide appliance repair services to approximately 61,000 and 33,000 residential customers, respectively, through Company technicians and third-party service providers, typically through on-going monthly service agreements. Tech Services primarily serves gas transportation customers throughout our service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.

Power Generation: OurMining segments. The Power Generation segment produces electric power from its five generating plantsfacilities and sells most of the electric capacity and energy principally to our utilitiesElectric Utilities under long-term contracts.

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


OilThe Company has provided energy and Gas: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 Oilstrategic focus has not changed in over a century - serving customers with affordable, reliable and Gas segment engagessafe 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 production of crude oilutility industry; 2) transform the customer experience; 3) grow our electric and natural gas primarily incustomer load; 4) pursue operating efficiencies; and 5) modernize utility infrastructure. This strategic focus will present the Rocky Mountain region. We are divesting non-core oilcompany with significant investment needs as we modernize our infrastructure systems and gas assetsmeet customer growth. It will also allow us to better understand our customer and community needs while retaining those best suited for a cost of service gas program,providing more intuitive and we have refocused our professional staff on assisting utilities with the implementation of cost of service gas programs.cost-effective interactions.


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. Prior to March 31, 2016, our segments were reported within two business groups, our Utilities Group, containing the Electric Utilities and Gas Utilities segments, and our Non-regulated Energy Group, containing the Power Generation, Mining and Oil and Gas segments. We have continued to report our operations consistently through our reportable segments. However, we will no longer separate the segments by business group. We are a customer-focused, growth-oriented, vertically-integrated utility company. All of our non-utility business segments support our utilities, with the exception of our Oil and Gas segment.

Segment reporting transition of Cheyenne Light’s Natural Gas distribution

Effective January 1, 2016, the natural gas operations of Cheyenne Light are reported in our Gas Utilities Segment. Through December 31, 2015, Cheyenne Light’s natural gas operations were included in our Electric Utilities Segment as these natural gas operations were consolidated within Cheyenne Light since its acquisition. This change is a result of our business segment reorganization to, among other things, integrate all regulated natural gas operations, including the SourceGas Acquisition, into our Gas Utilities Segment which is led by the Group Vice President, Natural Gas Utilities. Likewise, all regulated electric utility operations including Cheyenne Light’s electric utility operations are reported in our Electric Utilities Segment, which is led by the Group Vice President, Electric Utilities. The prior periods have been reclassified to reflect this change in presentation between the Electric Utilities and Gas Utilities segments. The reclassifications moving Cheyenne Light’s natural gas results from the Electric Utilities segment to the Gas Utilities segment consisted of increasing Gas Utilities and decreasing Electric Utilities Revenue, Gross Margin and Net Income (loss) by $44 million, $22 million and $1.7 million, and $40 million, $17 million and $2.3 million for the Years ended December 31, 2015 and December 31, 2014, respectively.


Overview: Our customer focus provides opportunities to expand our business by constructing additional rate base assets to serve our utility customers and expanding our non-regulated energy products and services to our wholesale customers.

The diversity of our energy operations reduces reliance on any single business segment to achieve our strategic objectives. Our emphasis on our utility business with diverse geography and fuel mix, combined with a conservative approach to our non-regulated energy operations, mitigates our overall corporate risk and enhances our ability to earn stronger returns for shareholders over the long-term. Our long-term strategy focuses on growing both our utility and utility supporting non-regulated energy businesses, primarily by increasing our customer base and providing superior service.

SourceGas Acquisition

On February 12, 2016, Black Hills Utility Holdings acquired SourceGas Holdings, LLC from investment funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co., pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in debt at closing. The acquisition is in alignment with our strategy to invest in utilities and to expand utility operations consistent with our regional focus and strategic advantages as further discussed below in our business strategies. See additional information below under Prospective Information and in Note 2 of the Notes to Consolidated Financial Statements in Item 8 of this Annual Report on Form 10-K.

Our Objective

Our objective is to be best-in-class relative to certain operational performance metrics, such as safety, power plant availability, electric and gas system reliability, efficiency, customer service and cost management. Our notable operational performance metrics for 2016 include:

•
Our three electric utilities achieved 1st quartile reliability ranking with 64 customer minutes of outage time (SAIDI) in 2016 compared to industry averages (IEEE 2016 1st quartile is less than 81 minutes);

Our JD Power Customer Satisfaction Survey indicated our Electric and Gas Utilities were favorable to our peers in the Midwest;

•
Our power generation fleet achieved a forced outage factor of 3.27% for coal fired plants, 0.76% for natural gas plants, and 0.00% for diesel plants in 2016, compared to an industry average* of 4.61%, 4.41%, and 2.18%, respectively (*NERC GADS 2015 Data);

•
Our power generation fleet availability was 94.41% for coal fired plants, 96.56% for natural gas fired plants, 98.92% for diesel fired plants, and 99.20% for wind generation in 2016 while the industry averages** were 85.29%, 89.65%, 94.59% respectively (**NERC GADS 2015 data was used for coal, natural gas and diesel; data is not currently kept for wind);

•
Our safety TCIR of 1.7 compares well to an industry average of 2.2+ and our DART rate of 0.6 compares to an industry average of 1.2+ (+ Bureau of Labor Statistics (BLS)-all utilities of all sizes - most recent industry averages are 2015);

Our OSHA TCIR rate during construction of our generating facilities is also significantly better than industry average with a TCIR rate of 3.1 during the 2016 construction of the Pueblo LM 6000 compared to an industry average of 4.4 for natural-gas fired plants.

Our mine completed five years with favorable MSHA safety results compared to other mines located in the Powder River Basin and received an award from the State of Wyoming for seven years without a lost time accident.  The mine also received the State Mine Inspector’s Award for the third year in a row for operating as the safest small mine and received the Mine Safety and Health Administration’s Certificate of Achievement for No Lost Time Incidents.


The electric utility industry is facing requirements to upgrade aging infrastructure, deploy smart grid technology and comply with new state and federal environmental regulations and renewable portfolio standards. Increased energy efficiency and smart grid technologies suppress demand in many areas of the United States. These competing considerations present challenges to energy companies’ approach to balancing capital spending and obtaining satisfactory rate recovery on investments.

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

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

The proliferation of domestic crude oil and natural gas production from shale plays in recent years has provided the domestic market an abundant new supply of both commodities, which has decreased the dependence on foreign resources for these commodities. The increased worldwide supply of crude oil and natural gas caused prices to continue to decline throughout 2016, making drilling and exploration activities uneconomical in many producing basins. We continued to focus our oil and gas expertise to support cost of service gas programs for our own utilities and third-party utilities.

Currently, approximately 30% of electricity generated in the United States is from coal-fired power plants. It will take significant time and expense before this generation can be replaced with alternative technologies. As a result, coal-fired resources will remain a necessary component of the nation’s electric supply for the foreseeable future. The regulatory climate in recent years, combined with the EPA’s proposed and expected GHG regulations, have limited construction of new conventional coal-fired power plants, but, if technologies such as carbon capture and sequestration become more proven and less expensive, they could provide for the long-term economic use of coal. We have investigated and will continue to investigate the possible deployment of these technologies at our mine site in Wyoming.

We have expertise in permitting, constructing and operating power generation facilities. These skills, combined with our understanding of electric resource planning and regulatory procedures, provide a significant opportunity for us to add long-term shareholder value. We intend to grow our non-regulated power generation business by continuing to focus on long-term contractual relationships with our affiliates and other load-serving utilities.

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

Provide stable long-term rates for customers
 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 increase earnings by efficiently planning, constructing and operating rate-baseoperate rate base power generation facilities needed to serve our electric utilities. Our Company began asElectric Utilities. We believe that we best serve customers and communities with a vertically-integrated electric utility.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 transmit and distributecost-effectively supply electricity to our customers. We strive to provide power at reasonable rates to our customers and earn competitive returns for our investors.


We believe we have a competitiveOur power production strategy focusedfocuses on low costlow-cost construction and efficient operation of our generating facilities. Access to our own coal and third-party natural gas reserves allows us to be competitive as aOur low power generator. Low production costs can result from a variety of factors including low fuel costs, efficiency in converting fuel into energy, low per unit operationoperating and maintenance costs and high levels of power plant availability. WeFor our coal-fired power plants, we leverage our mine-mouth coal-fired generating capacity which strengthens our position as a low-cost producer by eliminating fuellocation advantage to eliminate coal transportation costs whichthat often represent the largest component of the delivered cost of coal for many other utilities. In addition,Additionally, we typically operate our plants with high levels of availability as compared to industry benchmarks.

We aggressively manage eachcontinue to believe that ownership of these factors with the goal of achieving low production costs.


Rate-basepower generation facilities by our Electric Utilities best serves customers. Rate-based generation assets offer several advantages for customers and shareholders, including:


Since theWhen 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, than if therun; especially when compared to power wasotherwise purchased from the open market through wholesale contracts that are periodically re-priced over time;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; andinvestment.


The lower risk profile of rate based generation assets may enhance credit ratings which, in turn, can benefit both consumers and investors by lowering our cost of capital.

Our actions to provide power at reasonable rates to our customers were exemplified in our successful requests to secure the construction financing riders in both Wyoming and South Dakota during the 2013-2014 construction of Cheyenne Prairie, and in Colorado with the 2016 completion of a 40 MW natural gas-fired combustion turbine and Peak View Wind Project. These riders reduce the total cost of the plant ultimately passed along to our customers while we construct these plants to accommodate growth and replace plants that were closed prematurely due to environmental regulations.

Proactively integrate alternative and renewable energy into our utility energy supply while mitigating and remaining mindful of customer rate impacts. TheSome 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 utility industries face uncertainty, and also potential investment opportunities, relatedlegislators to the potential impact of legislation and regulation intended to reduce GHG emissions and 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.


To date, many states have enacted, and others are considering, some form of mandatory renewable energy standard,standards, requiring utilities to meet certain thresholds of renewable energy generation. SomeIn 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 is also under consideration.
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 producedrive the need for significant investment opportunities, either forin our electric utilities or for our power generation business.Electric Utilities and Gas Utilities segments. These mandates will also most likely increase prices for electricity and/or natural gas for our utility customers. As a regulated utility we are responsible for providing safe, reasonably pricedreliable and reliableaffordable sources of energy to our customers. As a result,Accordingly, we employ a customer‑centeredcustomer-focused strategy for complying with renewable energy standards and GHG emission 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.
Colorado legislative mandates apply to our electric utilities segment regarding the use of renewable energy. Therefore, we pursue cost‑effective initiatives that allow us to meet our renewable energy requirements. Where permitted, we seek to construct renewable generation resources as rate base assets, which helps mitigate the long-term customer rate impact of adding renewable energy supplies. For example, the Busch Ranch Wind Farm, a 29 MW wind farm project, was completed in the fourth quarter of 2012, as part of our plan to meet Colorado’s Renewable Energy Standard. We had also previously submitted requests for additional renewable energy supplies in 2014 for our Colorado Electric utility to help meet the renewable mandate. On October 21, 2015, we received approval from the Colorado Public Utilities Commission to purchase the $109 million, 60 MW Peak View Wind Project, under the terms of a build/transfer agreement with a third party developer. This wind project commenced commercial operation in November 2016;
In states such as South Dakota and Wyoming that currently have no legislative mandate on the use of renewable energy, we have proactively integrated cost-effective renewable energy into our generation supply based upon our expectation that there will be mandatory renewable energy standards in the future or other standards, such as those established by the CPP. For example, under two 20-year power purchase agreements, we purchase a total of 60 MW of energy from wind farms located near Cheyenne, Wyoming, for use at our South Dakota Electric and Wyoming Electric subsidiaries; and
In all states in which we conduct electric utility operations, we are exploring other cost-effective potential biomass, solar and wind energy projects, particularly wind generation sites located near our utility service territories.

Maintain a safe and reliable gas distribution system.We are in compliance with all applicable federal, state and local regulations as well as many industry best practices.  Any leaks discovered, whatever the cause, are repaired as soon as possible while ensuring the safety of the public and our employees.  We construct and renew our piping systems with state of the art materials and products to safely and efficiently deliver natural gas to our customers.  Maintaining our product within our piping systems is of utmost importance to ensure the safety of the public and our employees and to protect the environment.  To that end, we monitor the integrity of our piping systems and renew as appropriate to accomplish the stated goals of safe, efficient energy delivery.  We have removed all cast and wrought iron from our system.  With respect to unprotected steel, our distribution system contains less than 2.57% bare steel and 0.07% coated steel, while our transmission system consists of less than 0.63% bare steel.  Many of our Gas Utilities are authorized to use system safety, integrity and replacement cost recovery mechanisms that allow them to adjust their rates to reflect all the costs prudently incurred in replacing piping systems.

Expand utility operations through selective acquisitions of electric and gas utilities consistent with our regional focus and strategic advantages. For more than 130 years, we have provided reliable utility services, delivering quality and value to our customers. Utility operations contribute substantially to the stability of our long-term cash flows, earnings and dividend policy. Our tradition of accomplishment supports efforts to expand our utility operations into other markets, most likely in areas that permit us to take advantage of our intrinsic competitive advantages, such as baseload power generation, system reliability, superior customer service, community involvement and a relationship-based approach to regulatory matters. Utility operations also enhance other important business development opportunities, including gas transmission pipelines and storage infrastructure, which could promote other non-regulated energy operations.

We have and will continue to pursue the purchase of not only large utility properties, such as SourceGas, but also smaller, private or municipal utility systems, which can be easily integrated into our operations. We purchased several small natural gas distribution systems in Kansas, Iowa and Wyoming in the past several years. We have a scalable platform of systems and processes, which simplifies the integration of our utility acquisitions. Merger and acquisition activity has continued in the utility industry and we will consider such opportunities if they advance our long-term strategy and add shareholder value.

Provide stable long-term gas costs for customers and increase earnings by efficiently planning and implementing a Cost of Service Gas Program to serve our electric and natural gas utilities. To further enhance our vertically-integrated utility business model, we are considering implementing a Cost of Service Gas Program. The Cost of Service Gas Program is designed to provide utility customers with long-term natural gas price stability, along with a reasonable expectation of savings over the life of the program, while providing increased earnings opportunities for our shareholders. We will need to apply for and receive regulatory approval from our state utility commissions for the program. Several utilities have cost of service gas programs in place in various states, including in both Wyoming and Montana.

We believe we have a competitive advantage related to a Cost of Service Gas Program in that our existing non-regulated oil and gas subsidiary could assist in drilling/acquiring and operating the gas reserves required to meet the needs of our electric and gas utilities. We could also provide this service to other utilities.

Focus our oil and gas business to support cost of service gas initiatives. Our oil and gas business is focused on supporting the implementation of a planned utility Cost of Service Gas Program in partnership with our own and other utilities, while maintaining the upside value of our Piceance Basin and other assets. We are divesting non-core assets while retaining those assets best suited for a Cost of Service Gas Program. In previous years, we successfully focused our efforts on proving up the large shale gas resource potential of our southern Piceance Basin asset, while improving our drilling and completion practices for the Mancos. We drilled 17 wells and completed 13, with production meeting or exceeding our expectations on the completed wells. We are currently assessing the Piceance Basin assets to determine their potential fit for a Cost of Service Gas Program.

Oil and Gas will rationalize its asset base. In the current price environment, we have reduced future capital expenditures and staffing to improve financial performance.

Build and maintain strong relationships with wholesale power customers of our utilities and non-regulatedour power generation business. We strive to build strong relationships with other utilities, municipalities and wholesale customers. We believe we will continue to be a primaryan important provider of electricity to wholesale utility customers, who will continue to need products such as capacity in orderand 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 termlong-term than we couldwould 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.III, reducing risk and providing steady revenues.



Selectively growVertically integrate businesses that are supportive of our non-regulatedElectric 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 business in targeted regional markets by developingand mining assets that are vertically integrated into and selling most of the capacity and energy production through mid- and long-term contracts primarily to load-serving utilities. While muchsupportive of our recentElectric 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 plant developmentfacilities, four of which are contracted with our affiliate Electric Utilities under long-term power purchase agreements. Our Power Generation segment has been for our regulated utilities, we seek to expand our non-regulated power generation business by developingan experienced staff with significant expertise in planning, building and operating power plants in regional markets based on prevailing supply and demand fundamentals, in a manner that complements our existing fuel assets and marketing capabilities. We seek to grow this business through the development of newplants. 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, and disciplined acquisitions primarilyresulting in the western region, where we believe our detailed knowledgeefficient management of market and electric transmission fundamentals provides us a competitive advantage and, consequently, increases our ability to earn attractive returns. We prioritize small-scale facilities that serve incremental growth or provide critical back up to renewable resources and are typically easier to permit and construct than large-scale generation projects.

Mostall 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 capacity fromown majority interests in four of our non-regulatedfive 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 mid-cost-plus contracts with affiliates. A small portion of the mine’s production is sold to off-site industrial customers and long-term contracts. When possible, we structure long-term contracts as tolling arrangements, whereby the contract counterparty assumes the fuel risk. Going forward, we will continue to focus on selling a majoritydelivered by truck.

Expand utility operations through selective acquisitions of our non-regulated capacityelectric and energy primarily to load-serving utilities under long-term agreements that have been reviewed or approved by state utility commissions. An example of this strategy is the 200 MW of combined-cycle gas-fired generation constructed by our non-regulated power generation subsidiary to serve our Colorado Electric utility subsidiary.gas utilities. The plant commenced operations on January 1, 2012, under a 20-year tolling agreement.

Diligently manage the credit, priceelectric and operational risks inherent in buying and selling energy commodities. Over the last decade or so, Black Hills has strategically refocused itself as a utility-centered energy company. Most of our buying and selling activities are directly related to maintaining utilities operations, mainly by purchasing fuel for our power generating units and purchasing natural gas for distribution to our natural gas utility customers. Our oilindustries have consolidated significantly over the past two decades and gas business hascontinue 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 natural long position created by its natural gasscalable platform that simplifies the rapid integration of acquired utilities, providing significant benefits to both customers and crude oil production. We sell this production intoshareholders. 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 open marketnear-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 hedge some of the price risk for future production using financial derivatives.more rural utility systems.


AllGrow our dividend. We are extremely proud of our buyingtrack 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 selling activitiespaid in 2020, will represent 50 consecutive years of annual dividend increases. We intend to support operations require effective managementcontinue our record of counterparty credit risk. We mitigate this risk by conducting businessannual dividend increases with a diverse grouptargeted dividend payout ratio of creditworthy counterparties. In certain cases where creditworthiness merits security, we require prepayment, secured letters of credit or other forms of financial collateral. We establish counterparty credit limits and employ continuous credit monitoring, with regular review of compliance under our credit policy by our Executive Risk Committee. Our oil and gas and power generation operations require effective management of price and operational risks related50% to adverse changes in commodity prices and the volatility and liquidity of the commodity markets. To mitigate these risks, we implemented risk management policies and procedures. Our oversight committee monitors compliance with these policies.60%.


Maintain an investment grade credit rating and ready access to debt and equity capital markets.Access to capital has been and will continue to be critical to our success. We have demonstrated our ability to access the debt and equity markets, resulting in sufficient liquidity. 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. Our access to adequate and cost-effective financing depends uponWe have demonstrated our ability to maintaincost-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 primarilypredominately 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 acquisition of SourceGas,utilities and continued focus on improving efficiencies and reducing costs, implementation of a Cost of Service Gas Program and focused capital investments at our utilities.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.



Electric Utilities

Colorado Electric received a settlement agreement of its electric resource plan filed June 3, 2016, to meet requirements under the Colorado Renewable Energy Standard. The settlement, effective February 6, 2017, includes the addition of 60 megawatts of renewable energy to be in service by 2019 and provides for additional small solar and community solar gardens as part of the compliance plan. Colorado Electric plans to issue a request for proposal in the first half of 2017.

In December 2016, Colorado Electric received approval from the CPUC to increase its annual revenues by $1.2 million to recover investments in a $63 million, 40 MW natural gas-fired combustion turbine. This increase is in addition to approximately $5.9 million in annualized revenue being recovered under the Clean Air Clean Jobs Act construction financing rider. This turbine was completed in the fourth quarter of 2016, achieving commercial operation on December 29, 2016. The approval allowed a return on rate base of 6.02% for this turbine, with a 9.37% return on equity and a capital structure of 67.34% debt and 32.66% equity. Whereas, an authorized return on rate base of 7.4% was received for the remaining system investments, with a return on equity of 9.37% and an approved capital structure of 47.61% debt and 52.39% equity. On January 9, 2017, we filed an application with the CPUC for rehearing, reargument or reconsideration of the Commission’s December 19, 2016 rate decision.

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

Retail MWhs sold increased in 2016 primarily due to increased industrial loads driven by customer load growth. The increase in industrial loads is primarily driven by Wyoming Electric and Colorado Electric, both of which set new all-time peak loads in 2016. Wyoming Electric recorded an all-time summer peak load of 236 MW in July 2016, and an all-time winter peak of 230 MW in December 2016. Colorado Electric recorded an all-time summer peak load of 412 MW in July 2016.

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

Gas Utilities

On February 12, 2016, Black Hills Utility Holdings acquired SourceGas pursuant to a purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in debt at closing. The purchase price was subject to post-closing adjustments of which $11 million was agreed to and received in June 2016.

SourceGas, which was renamed Black Hills Gas Holdings, LLC, primarily operates four regulated natural gas utilities serving approximately 431,000 customers in Arkansas, Colorado, Nebraska and Wyoming and a 512 mile regulated intrastate natural gas transmission pipeline in Colorado.

We completed substantially all integration activities in 2016. All significant operations, customer, accounting, human resources and rebranding activities were successfully completed and implemented.

Our Gas Utilities investeddiscussion 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 gas distribution networkAnnual 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 related technology such as advanced metering infrastructure and mobile data terminals. We continually monitor our investments and costs of operations in all states to determine the appropriateness of additional rate reviews or other rate filings. As part of our growth strategy, we continue to look for opportunities to purchase municipal and privately-owned gas infrastructure and distribution systems.


Cost of Service Gas Program Filings

During the third quarter of 2016, the Company withdrew its Cost of Service Gas applications in Wyoming, Iowa, Kansas and South Dakota. In consideration of the July 2016 denial of the application from the NPSC and the April 2016 dismissal of its application from the CPUC, the Company is re-evaluating its Cost of Service Gas regulatory approval strategy.

The Company’s initial applications submitted in late 2015 were basedamounts are presented on a two-phase approach, the first of which would establish the criteria for how the program would work, and the second would seek approval for a specific gas reserves property. The orders in Colorado and Nebraska indicated the initial phase filings contained insufficientpre-tax basis unless otherwise indicated. Per share information and data to support customer benefits. The Company is currently considering filing new applications for approval of specific gas reserve properties.references diluted shares unless otherwise noted.


The Cost of Service Gas Program is designed to provide long-term natural gas price stability for the Company’s utility customers, along with a reasonable expectation of customer savings over the life of the program.

Mining

Production from the Mining segment primarily serves mine-mouth generation plants and select regional customers with long-term fuel needs. Total annual production was approximately 3.8 million tons for 2016, which was 8% less than 2015. Mining operations moved to an area with higher overburden ratios in 2016, which increased mining costs. However, lower fuel costs, and efficiencies in executing our mine plan offset these costs. Our stripping ratio at December 31, 2016 was 2.07 and we expect stripping ratios to decrease in 2017 to approximately 1.9 as the areas planned for mining contain lower overburden.

Our strategy is to sell the majority of our coal production to on-site, mine-mouth generation facilities under long-term supply contracts. Historically our limited off-site sales have been to consumers within a close proximity to our mine, including off-site sales contracts served by truck. We continue to pursue new opportunities to market our coal despite limitations inherent to transporting our lower-heat content coal.

Oil and Gas

Our strategy is to focus our Oil and Gas business toward supporting our Cost of Service Gas Program and similar programs in partnership with other utilities, while maintaining the upside value optionality of our Piceance Basin and other assets. We can best utilize our oil and gas expertise to develop and operate the Cost of Service Gas Program on behalf of our utility businesses and similar programs in partnership with third-party utilities. We are divesting non-core assets while retaining those best suited for a Cost of Service Gas Program. Our oil and gas strategy through 2015 had been to prove up the potential of the Mancos formation for our southern Piceance Basin asset, while improving our drilling and completion practices for the Mancos. We drilled 17 wells and completed 13, with production meeting or exceeding our expectations on the completed wells. Due to the sustained low oil and natural gas prices, production in 2016 was limited to meeting contractual agreements we have in the Piceance, and we have limited our planned future capital based on our Cost of Service Gas strategy. We are currently assessing the Piceance wells and acreage holdings to determine their potential fit for a Cost of Service Gas Program.

Corporate

We took advantage of historically low interest rates to complete several financing transactions, including permanent financing of the SourceGas Acquisition, refinancing on favorable terms the debt acquired in the Acquisition, amending and extending our Revolving Credit Facility and executing a new three-year term loan. In addition to our debt issuances and refinancings, we implemented an ATM equity offering program, executed a declining balance term loan, closed on a CP Program and settled $400 million of interest rate swaps. See additional detail in the 2016 Corporate highlights.





Results of Operations


ExecutiveConsolidated Summary and Overview
 For the Years Ended December 31,
 2016Variance2015Variance2014
 (in thousands)
Revenue      
Revenue$1,701,093
$270,811
$1,430,282
$(90,827)$1,521,109
Inter-company eliminations(128,119)(2,442)(125,677)1,862
(127,539)
 $1,572,974
$268,369
$1,304,605
$(88,965)$1,393,570
      
Net income (loss) available for common stock     
Electric Utilities(a)
$85,827
$8,248
$77,579
$20,309
$57,270
Gas Utilities(a)
59,624
20,318
39,306
(4,845)44,151
Power Generation (b)
25,930
(6,720)32,650
4,134
28,516
Mining10,053
(1,817)11,870
1,418
10,452
Oil and Gas (c) (d)
(71,054)108,904
(179,958)(171,433)(8,525)
 110,380
128,933
(18,553)(150,417)131,864
      
Corporate and Eliminations (a) (e) (f)
(37,410)(23,852)(13,558)(12,583)(975)
      
Net income (loss) available for common stock$72,970
$105,081
$(32,111)$(163,000)$130,889
 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.

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)Net
In 2019, we changed our measure of segment performance to adjusted operating income, availablewhich impacted our segment disclosures for common stock for 2016 included a net tax benefit of approximately $3.1 million for the following items: at the Electric Utilities, a $2.1 million benefit related to production tax credits associated with the Peak View Wind Project being placed into service and flow through treatment of a treasury grant related to the Busch Ranch Wind Project; at the Gas Utilities, a tax benefit of approximately $2.2 million related to favorable flow through adjustments; and, various other items netting to $1.2 million of tax expense that predominantly affected Corporate.
(b)On April 14, 2016, BHEG sold a 49.9% interest in Black Hills Colorado IPP. Net income available for common stock for 2016 was reduced by $9.6 million attributable to this noncontrolling interest.
(c)Net income (loss) available for common stock for 2016 and 2015 included non-cash after-tax impairments of our crude oil and natural gas properties of $67 million and $160 million.all periods presented. See Note 135 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
(d)Net income (loss) available10-K for common stock for 2016 included a tax benefit of approximately $5.8 million recognized from additional percentage depletion deductions that are being claimed with respect to our oil and gas properties involving prior years.
(e)
Net income (loss) available for common stock for 2016 and 2015include incremental SourceGas Acquisition costs, after-tax of $30 million and $6.7 million and after-tax internal labor costs attributable to the SourceGas Acquisition of $9.1 million and $3.0 million that otherwise would have been charged to other business segments.more information.
(f)Net income (loss) available for common stock for 2016 included tax benefits of approximately $4.4 million as a result of the re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016.


The following business group and segment information does not include inter-company eliminations and all amounts are presented on a pre-tax basis unless otherwise indicated. Per share information references diluted shares unless otherwise noted.



2016 Compared to 2015

Net income (loss) available for common stock was $73 million, or $1.37 per diluted share in 2016, compared to $(32) million, or $(0.71) per share in 2015. Net income available for common stock in 2016 increased over the same period in the prior year due primarily to: lower Oil and Gas property impairment charges; higher earnings at our Electric Utilities and Gas Utilities, which include earnings of $15 million from our acquired SourceGas utilities since the acquisition date of February 12, 2016; tax benefits of approximately $11 million from additional Oil and Gas properties’ percentage depletion deductions, and the re-measurement of uncertain tax positions’ liability predicated on an agreement reached with IRS Appeals. These increases were partially offset by $9.6 million of net income attributable to noncontrolling interests. Non-cash after-tax oil and gas property impairment charges were $67 million and after-tax SourceGas incremental acquisition and transition costs were $30 million in the year ended December 31, 2016. The Net income (loss) available for common stock for the year ended 2015 included non-cash after-tax ceiling test impairments of our oil and gas properties of $158 million, after-tax SourceGas incremental acquisition and transition costs of $6.7 million, and a non-cash after-tax impairment loss on an oil and gas equity investment of $2.9 million.

20162019 Overview of Business Segments and Corporate Activity


Electric Utilities

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


On December 19, 2016,13, 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 CPUCSDPUC to increase its annual revenuesthe offering under the program by $1.2 million12.5 MW. The two electric utilities also received a determination from the WPSC to recover investments in a $63 million, 40 MW natural gas-fired combustion turbine. This turbine was completed in the fourth quarter of 2016, achieving commercial operation on December 29, 2016. The approval allowed a return on rate base of 6.02% for this turbine, with a 9.37% return on equity and a capital structure of 67.34% debt and 32.66% equity. Whereas, an authorized return on rate base of 7.4% was received for the remaining system investments, with a return on equity of 9.37% and an approved capital structure of 47.6% debt and 52.4% equity.
Construction riders related toincrease the project increased gross marginsto 52.5 MW. The $79 million project is expected to be in service by approximately $5.1 millionyear-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, 2016.

On November 8, 2016, Colorado Electric completed2019 were 14% higher than the purchase of Peak View, a $109 million, 60 MW Wind Project located near Colorado Electric's Busch Ranch Wind Farm. Peak View achieved commercial operation on November 7, 2016 and was purchased through progress payments throughout 2016 under a commission approved third-party build- transfer and settlement agreement. This renewable energy project was originally submitted in response to Colorado Electric's all-source generation request on May 5, 2014. The Commission’s settlement agreement provides for recovery of the costs of the project through Colorado Electric’s Electric Cost Adjustments, Renewable Energy Standard Surcharge and Transmission Cost Adjustment for 10 years, after which Colorado Electric can propose base rate recovery.

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



Gas Utilities

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

Gas Utilities were unfavorably impacted by milder weather in 2016normal compared to 2015. Our service territories reported warmer29% higher than normal winter weather as measured by heating degree days, compared to the 30-year average, and compared to 2015. in 2018.

Heating degree days for the full year in 2016ended December 31, 2019 were 10% less5% 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 1% less than the same period in 2015.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.

◦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.
During
On December 1, 2019, Wyoming Gas placed in service the third quarter of 2016,$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 Company withdrew its Cost of ServiceWyoming Gas applicationsrate review completed in Wyoming, Iowa, Kansas and South Dakota. In consideration ofDecember 2019.

Heating degree days at the July 2016 denial ofGas Utilities for the application from the NPSC and the April 2016 dismissal of its application from the CPUC, the Company is re-evaluating its Cost of Service Gas regulatory approval strategy.year ended December 31, 2019 were 5% higher than normal compared to 2% higher than normal in 2018.


The Company’s initial applications submitted in late 2015 were based on a two-phase approach, the first of which would establish the criteria for how the program would work, and the second would seek approval for a specific gas reserves property. The orders in Colorado and Nebraska indicated the initial phase filings contained insufficient information and data to support customer benefits. Based on pre-hearing discovery and commission orders, the Company is considering filing new applications for approval of specific gas reserve properties.

Power Generation


Black Hills Colorado IPP owns and operates a 200 MW, combined cycle natural gas generating facility located in Pueblo, Colorado. On April 14, 2016,November 26, 2019, Black Hills Electric Generation soldplaced in service Busch Ranch II. Through a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million. FERC approval of the sale was received on March 29, 2016. Proceeds from the sale were used to pay down short-term debt.competitive bidding process, Black Hills Electric Generation continueswas selected to bedeliver 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 majority owner and operatorcapacity need for Wyoming Electric at the expiration of the facility, which is contracted to provide capacity and energy through 2031 tocurrent agreement on December 31, 2022. If approved, Black Hills Colorado Electric.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.


Oil and GasMining


Our Oil and Gas segment was impacted by lower net hedged prices received for crude oil and natural gasIn October 2019, negotiations were completed for the year ended December 31, 2016price 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 same period in 2015.prior contract price of $18.25 per ton. The average hedged price received for natural gas decreased by 24% for the year endedcontract expires on December 31, 2016 compared2022 and negotiations are underway to extend the same period in 2015. The average hedged price received for oil decreased by 6% for the year ended December 31, 2016 compared to the same period in 2015. Oil and Gas production volumes decreased 6% for the year ended December 31, 2016 compared to the same period in 2015 as production was limited to meeting minimum daily quantity contractual gas processing requirements in the Piceance.contract.

We review the carrying value of our natural gas and crude oil properties under the full cost accounting rules of the SEC on a quarterly basis, known as a ceiling test. We recorded a non-cash ceiling test impairment charge in each quarter of 2016 totaling $92 million for the year ended December 31, 2016. We also recorded a $14 million impairment of other Oil and Gas depreciable properties not included in our full cost pool during the second quarter of 2016 as we advanced our strategy to divest non-core oil and gas assets. In 2016, we sold non-core assets for total proceeds of $11 million.


Corporate Activitiesand Other


On March 18, 2016, we implemented an ATM equity offering program allowing us to sell shares of our common stock with an aggregate value of up to $200 million. The shares may be offered from time to time pursuant to a sales agreement dated March 18, 2016. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. Through December 31, 2016, we have sold and issued an aggregate of 1,968,738 shares of common stock under the ATM equity offering program for $119 million, net of $1.2 million in commissions.



On December 22, 2016, we implemented a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million. The notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. We did not borrow under the CP Program in 2016 and do not have any notes outstanding as of December 31, 2016.

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

On August 19, 2016,October 3, 2019, we completed a public debt offering of $700 million principal amount of senior unsecured notes. The debt offering consisted of $400 million of 3.15% 10-year senior notes due January 15, 2027 and $300 million of 4.20% 30-year senior notes due September 15, 2046. The proceeds of the notes were used for the following:

◦Repay the $325 million 5.9% senior unsecured notes assumed in the SourceGas Acquisition;

◦Repay the $95 million, 3.98% senior secured notes assumed in the SourceGas Acquisition;

◦Repay the remaining $100 million on the $340 million unsecured term loan assumed in the SourceGas Acquisition;

◦Pay down $100 million of the $500 million three-year unsecured term loan discussed below;

◦Payment of $29 million for the settlement of $400 million notional interest rate swaps; and

◦Remainder was used for general corporate purposes.

On August 9, 2016, we entered into a $500 million, three-year, unsecured term loan expiring on August 9, 2019. The proceeds of this term loan were used to pay down $240 million of the $340 million unsecured term loan assumed in the SourceGas Acquisition and the $260 million term loan expiring on April 12, 2017.

On August 9, 2016, we amended and restated our corporate Revolving Credit Facility to increase total commitments to $750 million from $500 million and extended the term through August 9, 2021, with two, one-year extension options (subject to consent from the lenders). The facility includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents and subject to receipt of additional commitments from existing or new lenders, to increase total commitments of the facility up to $1 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options, which are substantially the same as the former agreement.

On June 7, 2016, we issued a $29 million, declining balance five-year term loan maturing June 7, 2021, to finance the early termination of a gas supply agreement.

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

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

On January 13, 2016, we completed a public debt offering of $550 million in senior unsecured notes. The debt offering consists of $300Proceeds were used to repay the $400 million of 3.95%, 10-yearCorporate term loan due June 17, 2021, retire the $200 million 5.875% senior notes due 2026,July 15, 2020 and $250 millionrepay a portion of 2.50%, 3-year senior notes due 2019. Net proceeds after discounts and fees were approximately $546 million; andshort-term debt.




On November 23, 2015,During the year ended December 31, 2019, we completed the offeringsissued a total of common stock and equity units. We issued 6.3251.3 million shares of common stock for net proceeds of $246$99 million and 5.98 millionunder our ATM equity units for net proceeds of approximately $290 million.offering program.

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

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

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

2015 Compared to 2014

Net income (loss) was $(32) million, or $(0.71) per share, in 2015 compared to $131 million, or $2.93 per share, in 2014. 2015 Net income (loss) included a non-cash after-tax ceiling test impairment charge to our crude oil and natural gas properties of $158 million and a non-cash after-tax equity investment impairment charge of $2.9 million. 2015 Net income (loss) also included after-tax, external third-party costs of $6.7 million, primarily attributable to the SourceGas Acquisition. The 2014 Net income (loss) did not include any expenses, gains, or losses that we believe are not representative of our core operating performance.

2015 Overview of Business Segments and Corporate Activity

Electric Utilities

In our Electric Utilities service territories, mild winter weather in 2015 offset a hotter than normal summer. Heating degree days were 11% lower than the prior year and 10% lower than normal. Offsetting this was weather related demand during the peak summer months. Cooling degree days for the full year of 2015 were 32% higher than the same period in the prior year and 16% higher than normal.

Construction commenced in the second quarter of 2015 on Colorado Electric’s $63 million 40 MW natural gas-fired combustion turbine. As of December 31, 2015, approximately $35 million was expended Construction riders related to the project increased gross margins by approximately $1.9 million for the year ended December 31, 2015. This turbine was completed in and placed into service in December 2016.

On July 23, 2015, South Dakota Electric received approval from the WPSC for a CPCN to construct the Wyoming portion of a $54 million, 230-kV, 144 mile-long transmission line that would connect the Teckla Substation in northeast Wyoming, to the Lange Substation near Rapid City, South Dakota. South Dakota Electric received approval on November 6, 2014 from the SDPUC for a permit to construct the South Dakota portion. Construction commenced in the first quarter of 2016, and the project is expected to be placed in service in the first half of 2017.


On June 23, 2015, Colorado Electric filed for a CPCN with the CPUC to acquire the planned 60 MW Peak View Wind Project, to be located near Colorado Electric's Busch Ranch Wind Farm. This renewable energy project was originally submitted in response to Colorado Electric's all-source generation request on May 5, 2014. On October 21, 2015, the Commission approved a build transfer proposal and settlement agreement. The settlement provides for recovery of the costs of the project through Colorado Electric’s Electric Cost Adjustments and Renewable Energy Standard Surcharge for 10 years, after which Colorado Electric can propose base rate recovery. Colorado Electric will be required to make an annual comparison of the cost of the renewable energy generated by the facility against the bid cost of a PPA from the same facility. Colorado Electric purchased the project from a third-party for approximately $109 million through progress payments throughout 2016, with ownership transfer occurring on November 7, 2016.



On March 16, 2015, we announced plans to build a new corporate headquarters in Rapid City, South Dakota that will consolidate our approximately 500 employees in Rapid City from five locations into one. The investment in the new corporate headquarters will be approximately $70 million and will support all our businesses. The cost of the facility will replace existing expenses associated with our current facilities throughout Rapid City. Construction began in September 2015 with completion expected in the fall of 2017.

On March 2, 2015, the SDPUC issued an order approving a rate stipulation and agreement authorizing an annual electric revenue increase for South Dakota Electric of $6.9 million. The agreement was a Global Settlement and did not stipulate return on equity and capital structure. The SDPUC’s decision provides South Dakota Electric a return on its investment in Cheyenne Prairie and associated infrastructure, and provides recovery of its share of operating expenses for this natural gas-fired facility. South Dakota Electric implemented interim rates on October 1, 2014, coinciding with Cheyenne Prairie’s commercial operation date. Final rates were approved on April 1, 2015, effective October 1, 2014.

In January 2015, Colorado Electric implemented new rates in accordance with the CPUC approval received on December 19, 2014 for an annual electric revenue increase of $3.1 million. The approval also allowed a 9.83% return on equity and a capital structure of 49.83% equity and 50.17% debt, as well as approving implementation of a construction financing rider. This approval allows Colorado Electric to recover increased operating expenses and infrastructure investments, including those for the Busch Ranch Wind Farm, placed in service late 2012. The implementation of the rider allows Colorado Electric to recover a return on the construction costs for a $63 million natural gas-fired combustion turbine that was constructed in 2015 and 2016 to replace the retired W.N. Clark power plant.

Gas Utilities

Gas Utilities were unfavorably impacted by milder weather in 2015 compared to 2014. Our service territories reported warmer than normal winter weather as measured by heating degree days, compared to the 30-year average, and compared to 2014. Heating degree days for the full year in 2015 were 8% less than normal and 13% less than the same period in 2014.

On July 1, 2015, we completed the acquisition of Wyoming natural gas utility Energy West Wyoming, Inc., and natural gas pipeline assets from Energy West Development, Inc. The utility and pipeline assets were acquired for approximately $17 million, and operate as subsidiaries of Wyoming Electric. The acquired system serves approximately 6,700 customers, in Cody, Ralston, and Meeteetse, Wyoming. The pipeline acquisition includes a 30 mile gas transmission pipeline and a 42 mile gas gathering pipeline, both located near the utility service territory.

In January 2015, Kansas Gas implemented new base rates in accordance with the rate request approval received on December 16, 2014 from the KCC to increase base rates by $5.2 million. This increase in base rates allows Kansas Gas to recover infrastructure and increased operating costs. The approval was a Global Settlement and did not stipulate return on equity and capital structure.

Oil and Gas

Our Oil and Gas segment was impacted by lower commodity prices for crude oil and natural gas for the year ended December 31, 2015 compared to the same period in 2014. The average hedged price received for natural gas decreased by 39% for the year ended December 31, 2015 compared to the same period in 2014. The average hedged price received for oil decreased by 24% for the year ended December 31, 2015 compared to the same period in 2014. Oil and Gas production volumes increased 29% for the year ended December 31, 2015 compared to the same period in 2014.

We review the carrying value of our natural gas and oil properties under the full cost accounting rules of the SEC on a quarterly basis, known as a ceiling test. We recorded a non-cash ceiling impairment charge in each quarter of 2015, totaling $250 million for the year ended December 31, 2015.



We finished drilling the last of 13 Mancos Shale wells for our 2014/2015 drilling program in the Piceance Basin. Nine wells were placed on production in 2015, all with favorable production results to date, exceeding our expectations. We deferred the completion of our four remaining wells due to insufficient gas processing capacity and our expectation of continued low commodity prices. During the second quarter of 2015, we also reduced our planned 2016 and 2017 capital expenditures due to our strategic decision to focus our oil and gas expertise on being a cost of service gas provider for our electric and natural gas utilities.

Corporate Activities

On July 12, 2015 we entered into a definitive agreement to acquire SourceGas for approximately $1.89 billion, which included an estimated $200 million in capital expenditures through closing and the assumption of $760 million in long-term debt at closing. This acquisition closed on February 12, 2016. Financing activities related to this acquisition are detailed above in the 2016 Corporate activities.

On June 26, 2015,17, 2019, we amended our $500Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million corporate Revolving Credit Facility agreement to extendfrom $300 million and extended the term one year, through June 26, 2020. This facility is17, 2021 on substantially similar terms and covenants. The net proceeds were used to pay down short-term debt. Proceeds from the former agreement, which includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents, to increase the capacity of the facility to $750 million. Borrowings continue to be available under a base rate or various Eurodollar rate options.

On April 13, 2015, we entered into a new $300 million unsecured term loan. The loan has a two-year term with a maturity date of April 12, 2017. Proceeds of the term noteOctober 3, 2019 debt transaction were used to repay the existing $275 millionthis term note due June 19, 2015.loan.


Operating ResultsGas Utilities


A discussion of operating results from our business segments follows.

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


Non-GAAP Financial 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 from the measure. The presentation of gross margin is intended to supplement investors’ understanding of our operating performance.

In our Management Discussion and Analysis of Results of Operations, gross margin for our Electric Utilities is calculated as operating revenue less cost of fuel, purchased power and cost of gas sold. Gross margin for our Gas Utilities is calculated as operating revenues less costcontinued to consolidate utility jurisdictions within the States of gas sold. Our gross margin is impacted by the fluctuations in power purchasesColorado, Nebraska, and natural gas 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.Wyoming:

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):
 2016Variance2015Variance2014
      
Revenue$677,281
$(2,562)$679,843
$22,287
$657,556
      
Total fuel and purchased power261,349
(8,060)269,409
(22,235)291,644
      
Gross margin415,932
5,498
410,434
44,522
365,912
      
Operations and maintenance158,134
(2,790)160,924
4,672
156,252
Depreciation and amortization84,645
3,716
80,929
3,918
77,011
Total operating expenses242,779
926
241,853
8,590
233,263
      
Operating income173,153
4,572
168,581
35,932
132,649
      
Interest expense, net(50,291)754
(51,045)(3,995)(47,050)
Other income, net3,193
1,977
1,216
142
1,074
Income tax expense(40,228)945
(41,173)(11,770)(29,403)
      
Net income (loss) available for common stock$85,827
$8,248
$77,579
$20,309
$57,270


 201620152014
Regulated power plant fleet availability:   
Coal-fired plants  (a) (b)
90.2%91.5%93.8%
Other plants (c)
95.1%95.4%90.2%
Total availability93.5%94.0%91.5%
____________________
(a)◦2016 reflectsOn 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 planned outage at Wygen IIIreturn on equity of 9.40% and unplanned outages at Wyodaka capital structure of 50.23% equity and Neil Simpson II.49.77% debt. The approval also allows for a rider to recover integrity investments for system safety and reliability.

(b)◦2015 reflects planned outages at Neil Simpson II, Wygen IIOn February 1, 2019, Colorado Gas submitted a rate review with the CPUC to consolidate rates, tariffs and Wygen III.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.

(c)◦2014 reflects planned overhauls for control system upgradesOn October 29, 2019, Nebraska Gas received approval from the NPSC to meet NERC cyber security regulations onmerge 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 Ben French CTs 1-4.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.


2016 ComparedHeating degree days at the Gas Utilities for the year ended December 31, 2019 were 5% higher than normal compared to 20152% higher than normal in 2018.


Gross margin increased over the prior year reflecting increased rider margins of $4.9 million driven primarily by our construction and TCA riders, an increase of $2.4 millionPower Generation

On November 26, 2019, Black Hills Electric Generation placed in commercial and industrial margins driven by increased demand,service Busch Ranch II. Through a $1.5 million return on investment from the Peak View Wind Project, and a $1.4 million increase in residential margins driven by favorable weather. Offsetting these increasescompetitive bidding process, Black Hills Electric Generation was a $2.1 million prior-year benefit as a result of a one-time settlement with the Colorado Public Utilities Commission on ourselected to deliver renewable energy standard adjustment relatedunder a 25-year PPA to the Busch Ranch wind farm,Colorado Electric.

On August 2, 2019, Black Hills Wyoming and Wyoming Electric jointly filed a prior-year increase in return on invested capital of $1.2 million from South Dakota Electric’s rate case, and a $1.3 million decrease due to third-party billing true-ups relating to the current and prior years.

Operations and maintenance decreased primarily as a result of approximately $5.8 million lower employee costs primarily driven by a change in expense allocations impacting the electric utilities as a result of integrating the acquired SourceGas utilities. This decrease is partially offset by higher operating costs from the Peak View Wind Project, which commenced commercial operation in November 2016, and increased vegetation management costs.

Depreciation and amortization increased primarily due to a higher asset base driven partially by the addition of Peak View Wind Project.

Interest expense, net decreased primarily due to higher AFUDC interest income driven by construction in process as compared to prior year.

Other (expense) income, net increased primarily due to higher AFUDC equity in the current period compared to prior year.

Income tax benefit (expense): The effective tax rate was lower than prior year primarily due to the accelerated recognition of benefits associatedrequest with certain tax incentives.

2015 Compared to 2014

Gross margin increased primarily due to a return on additional investments which increased base electric margins by $29.8 million, and increased electric cost recoveries by $4.8 million. Higher industrial and commercial megawatt hours sold driven by customer load growth increased margins by $5.9 million. Colorado Electric receivedFERC for approval of a one-time settlementnew 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 CPUC on our renewable energy standard adjustment related to Busch Ranch, which increased margins by $2.1 million. An increaseFERC and awaits a decision from FERC.

Mining

In October 2019, negotiations were completed for the price reopener in residential customer growth and usagethe contract with the Wyodak power plant. Effective July 1, 2019, the new price was reset at $17.94 per customer increased margins by $2.4 million. These increases are partially offset by a $1.7 million decrease from lower demand and residential megawatt hours sold primarily driven by an 11% decrease in heating degree dayston with customary escalators, compared to the same periodprior 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 prior$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 facility improvements at one of our large industrial customers which resulted in a $1.8 million decrease in technical service revenues inextended the prior year.

Operationsterm through June 17, 2021 on substantially similar terms and maintenance increased primarily duecovenants. The net proceeds were used to costs related to Cheyenne Prairie, which was placed into commercial service on October 1, 2014.

Depreciation and amortization increased primarily due to a higher asset base driven by the addition of Cheyenne Prairie.

Interest expense, net increased primarily due to interest costspay down short-term debt. Proceeds from the $160 million of permanent financing placed during the fourth quarter of 2014 for Cheyenne Prairie.October 3, 2019 debt transaction were used to repay this term loan.


Income tax benefit (expense): The effective tax rate was comparable to the prior year.





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.

◦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.
Operating results
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 yearsyear ended December 31, for the Gas Utilities2019 were as follows (in thousands):
 2016Variance2015Variance2014
Revenue:     
Natural gas - regulated$769,082
$249,084
$519,998
$(107,135)$627,133
Other - non-regulated69,261
37,959
31,302
912
30,390
Total revenue838,343
287,043
551,300
(106,223)657,523
      
Cost of natural gas sold:     
Natural gas - regulated315,618
31,985
283,633
(104,330)387,963
Other - non-regulated36,547
20,535
16,012
194
15,818
Total cost of natural gas sold352,165
52,520
299,645
(104,136)403,781
      
Gross margin:     
Natural gas - regulated453,464
217,099
236,365
(2,805)239,170
Other - non-regulated32,714
17,424
15,290
718
14,572
Total gross margin486,178
234,523
251,655
(2,087)253,742
      
Operations and maintenance245,826
105,103
140,723
(1,301)142,024
Depreciation and amortization78,335
46,009
32,326
3,414
28,912
Total operating expenses324,161
151,112
173,049
2,113
170,936
      
Operating income162,017
83,411
78,606
(4,200)82,806
      
Interest expense, net(75,013)(57,702)(17,311)(290)(17,021)
Other expense (income), net184
(131)315
191
124
Income tax expense(27,462)(5,158)(22,304)(546)(21,758)
      
Net income (loss)59,726
20,420
39,306
(4,845)44,151
Net income attributable to noncontrolling interest(102)(102)—
—
—
Net income (loss) available for common stock$59,624
$20,318
$39,306
$(4,845)$44,151

2016 Compared to 2015

Gross margin increased primarily due to margins of approximately $236 million contributed by the SourceGas utilities acquired on Feb. 12, 2016 and Energy West Wyoming utility acquired on July 1, 2015. Partially offsetting this increase is a $ 2.0 million decrease due to weather. Heating degree days were 1% lower5% higher than the prior year and 10% lower than normal.

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

Depreciation and amortization increased primarily due to additional depreciation from the acquired SourceGas and Energy West Wyoming utilities of approximately $45 million, and due to a higher asset base at our other gas utilities over the same period in the prior year.



Interest expense, net increased primarily due to additional interest expense of approximately $58 million from the debt associated with the acquired SourceGas utilities.

Income tax: The effective tax rate for 2016, including the impact of the acquired SourceGas and Energy West Wyoming utilities, reflects additional tax benefits related primarily to a favorable flow through adjustment. Such adjustments are related to certain tax benefits that are recognized currently in accordance with prescribed regulatory treatment.

2015 Compared to 2014

Gross margin decreased primarily due to a $10.8 million impact from milder weathernormal compared to the same period2% higher than normal in the prior year and a $2.3 million decrease in retail volumes sold. Heating degree days in 2015 were 14% lower than the prior year and 8% lower than normal. Partially offsetting these decreases was $3.6 million of increased margins from the 2015 MCTC and Energy West Wyoming acquisitions, the impact from base rate increases from Kansas Gas, and an increase of $1.5 million from year over year customer growth.2018.


Operations and maintenance decreased primarily due to lower operating expenses, partially offset by an increase in property taxes.

Depreciation and amortization increased primarily due to a higher asset base than the prior year.

Interest expense, net is comparable to the prior year.

Income tax: The effective tax rate for 2015 is higher primarily due to a less favorable return to accrual adjustment related to flow-through items when compared to the prior year.

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.

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.


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.



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.


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):
 2016Variance2015Variance2014
      
Revenue$91,131
$341
$90,790
$3,232
$87,558
      
Operations and maintenance32,636
496
32,140
(986)33,126
Depreciation and amortization4,104
(225)4,329
(211)4,540
Total operating expenses36,740
271
36,469
(1,197)37,666
      
Operating income54,391
70
54,321
4,429
49,892
      
Interest expense, net(1,775)1,428
(3,203)466
(3,669)
Other income (expense), net2
(69)71
77
(6)
Income tax expense(17,129)1,410
(18,539)(838)(17,701)
      
Net income (loss)35,489
2,839
32,650
4,134
28,516
Net income attributable to noncontrolling interest(9,559)(9,559)—
—
—
Net income (loss) available for common stock$25,930
$(6,720)$32,650
4,134
$28,516
 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.



On April 14, 2016, Black Hills Electric Generation2018 Compared to 2017

Revenue decreased in 2018 due to a decrease in MWh sold, primarily from a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million. Black Hills Electric Generation continuesplanned outage at Wygen I. Operating expenses increased due to be the majority ownerhigher maintenance expenses primarily related to outage costs at Wygen I and operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric. Net income available for common stock for the year ended December 31, 2016, was reduced by $9.6 million 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.higher depreciation.




 201620152014
Contracted fleet plant availability:   
Gas-fired plants99.2%99.1%99.0%
Coal-fired plants (a)
95.5%98.4%94.7%
Total98.3%98.9%97.8%
 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 an unplanned outage in 2016 and a planned outage in 2014.2018
(c)Change from 2018 to 2019 is driven by Black Hills Electric Generation’s acquisition of new wind assets.


2016 Compared to 2015

Revenue increased primarily due to increased PPA prices, partially offset by a decrease in contracted revenue driven by the Wygen I plant outage in the second quarter of 2016.

Operations and maintenance increased primarily due to fan upgrades to the Colorado IPP generator and increased Wygen I chemical and major maintenance costs as compared to the same period in the prior year.

Depreciation and amortization decreased primarily due to lower depreciation at Wygen I. The generating facility located in Pueblo, Colo. is accounted for as a capital lease under GAAP; as such, depreciation expense for the original cost of the facility is recorded at Colorado Electric for segment reporting purposes.

Interest expense, net decreased due to higher interest income driven by the proceeds from the noncontrolling interest sale in April 2016.

Income tax expense: Black Hills Colorado IPP went from a single member LLC, wholly owned by Black Hills Generation, to a partnership as a result of the sale of 49.9 percent of its membership interest in April 2016. The effective tax rate reflects the income attributable to the noncontrolling interest for which a tax provision was not recorded.

Net income attributable to noncontrolling interest: Net income attributable to the noncontrolling interest increased by $9.6 million as a result of the noncontrolling interest sale in April 2016.

2015 Compared to 2014

Revenue increased primarily due to an increase in megawatt hours delivered at higher prices and an increase in fired hours, partially offset by the net effect of the expiration of the Gillette CTII PPA and subsequent economy energy PPA, which was impacted by lower natural gas prices in 2015.

Operations and maintenance decreased primarily due to lower outside services and materials, and maintenance costs from the Wygen I outage in the prior year.

Depreciation and amortization decreased primarily due to lower depreciation at Black Hills Wyoming. The generating facility located in Pueblo, Colo. is accounted for as a capital lease under GAAP; as such, depreciation expense for the original cost of the facility is recorded at Colorado Electric for segment reporting purposes.

Interest expense, net decreased primarily due to favorable interest income driven by a higher allocated note receivable compared to the same period in the prior year.

Income tax expense: The effective tax rate was lower in 2015 primarily due to an unfavorable return to accrual adjustment recorded in 2014. Such adjustment was related to the filed 2013 income tax return.






Mining


Mining operating results for the years ended December 31 were as follows (in thousands):
 2016Variance2015Variance2014
      
Revenue$60,280
$(4,786)$65,066
$1,708
$63,358
      
Operations and maintenance39,576
(2,054)41,630
458
41,172
Depreciation, depletion and amortization9,346
(460)9,806
(470)10,276
Total operating expenses48,922
(2,514)51,436
(12)51,448
      
Operating income (loss)11,358
(2,272)13,630
1,720
11,910
      
Interest (expense) income, net(377)22
(399)35
(434)
Other income, net2,209
(38)2,247
(28)2,275
Income tax benefit (expense)(3,137)471
(3,608)(309)(3,299)
      
Net income (loss) available for common stock$10,053
$(1,817)$11,870
$1,418
$10,452
 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):
 2016 2015 2014 
Tons of coal sold3,817
 4,140
 4,317
 
       
Cubic yards of overburden moved (a)
7,916
 6,088
 4,646
 
       
Coal reserves at year-end199,905
 203,849
 208,231
 
 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
____________
(a)Increase in overburden was due to relocating mining operations to areas of the mine with higher overburden.


20162019 Compared to 20152018


RevenueCurrent year revenue decreased primarily due to an 8 percent decrease in9% fewer tons sold resulting from adriven primarily by planned five-week outage inand unplanned generation facility outages at the second quarter of 2016, which was extended by an additional six weeks at Wyodak plantPlant. Operating expenses decreased primarily due to an unplannedlower royalties and production taxes on decreased revenues and lower fuel, labor, and major repair of a turbine rotor. Pricing was comparable to the same period in the prior year. Approximately 50 percent of our coal production was sold under contracts that are priced based on actual mining costs, including income taxes, as compared to 46 percent for the same period in the prior year.maintenance expenses.


Operations2018 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 maintenancerental revenue, previously reported in Other income, net. Operating expenses decreased primarily due to lower major maintenance requirements, fuel costs, and employee costs, as well as decreased royalties and revenue-related taxes driven by decreased revenue compared to the same period in the prior year.expenses.

Depreciation, depletion and amortization decreased primarily due to revised cost estimates for our asset retirement obligation driving lower accretion and depreciation.

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

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



2015 Compared to 2014

Revenueincreased primarily due to a 7% increase in the price per ton sold driven primarily by a coal price increase with the third-party operator of the Wyodak plant. Partially offsetting this was a 4% decrease in tons of coal sold primarily driven by a forced outage at Neil Simpson II, and the decommissioning of Neil Simpson I in March of the prior year. Approximately 50% of our coal production is sold under contracts that include price adjustments based on actual mining costs, including income taxes.

Operations and maintenanceincreased primarily due to mining in areas with higher overburden, and an increase in royalties and revenue related taxes driven by increased revenue, partially offset by lower fuel costs and lower employee costs.

Depreciation, depletion and amortizationdecreased primarily due to lower depletion, lower depreciation on mine assets and lower depreciation of mine reclamation costs.

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


OilCorporate and GasOther


OilCorporate and GasOther operating results for the years ended December 31 were as follows (in thousands):
 2016Variance2015Variance2014
      
Revenue$34,058
$(9,225)$43,283
$(11,831)$55,114
      
Operations and maintenance32,158
(9,435)41,593
(1,066)42,659
Depreciation, depletion and amortization13,902
(15,385)29,287
5,041
24,246
Impairment of long-lived assets106,957
(142,651)249,608
249,608
—
Total operating expenses153,017
(167,471)320,488
253,583
66,905
      
Operating income (loss)(118,959)158,246
(277,205)(265,414)(11,791)
      
Interest expense, net(4,864)(2,355)(2,509)(824)(1,685)
Other income (expense), net110
447
(337)(520)183
Impairment of equity investments—
4,405
(4,405)(4,405)—
Income tax benefit (expense)52,659
(51,839)104,498
99,730
4,768
      
Net income (loss) available for common stock$(71,054)$108,904
$(179,958)$(171,433)$(8,525)
(in thousands)2019Variance2018Variance2017
      
Adjusted operating (loss) (a)
$(1,632)$1,393
$(3,025)$3,271
$(6,296)



The following tables provide certain operating statistics for the Oil and Gas segment:
Crude Oil and Natural Gas Production201620152014
Bbls of oil sold318,613
371,493
337,196
Mcf of natural gas sold9,430,288
10,057,378
7,155,076
Bbls of NGL sold133,304
101,684
134,555
Mcf equivalent sales12,141,790
12,896,440
9,985,584

Average Price Received (a) (b)
201620152014
Gas/Mcf$1.36
$1.78
$2.91
Oil/Bbl$57.34
$60.69
$79.39
NGL/Bbl$12.27
$13.66
$35.53
______________________________________
(a)Net of hedge settlement gains/losses
(b)
Impairment charges of $107 million and $250 million were recorded for the years ended December 31, 2016 and 2015, respectively.

 201620152014
Depletion expense/Mcfe (a)
$0.79
$1.91
$1.84
___________
(a)The average depletion rate per Mcfe is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented. See Note 21 of NotesDue to the Consolidated Financial Statements includedchanges in this Annual Report filed on Form 10-K.

The following is a summary of certain annual average costs per Mcfe at December 31:
 2016
 LOE
Gathering, Compression, Processing and Transportation
Production TaxesTotal
San Juan$1.67
$1.14
$0.33
$3.14
Piceance0.37
1.84
(0.06)2.15
Powder River2.20
—
0.63
2.83
Williston1.45
—
0.70
2.15
All other properties1.30
—
0.14
1.44
Average$1.05
$1.20
$0.18
$2.43

 2015
 LOE
Gathering, Compression, Processing and Transportation
Production TaxesTotal
San Juan$1.44
$1.27
$0.34
$3.05
Piceance0.34
1.97
0.19
2.50
Powder River2.03
—
0.58
2.61
Williston1.07
—
0.44
1.51
All other properties1.75
0.02
0.49
2.26
Average$1.03
$1.23
$0.32
$2.58



 2014
 LOE
Gathering, Compression, Processing and Transportation
Production TaxesTotal
San Juan$1.52
$1.11
$0.56
$3.19
Piceance0.31
3.74
0.38
4.43
Powder River1.77
—
1.26
3.03
Williston1.46
—
1.24
2.70
All other properties1.43
—
0.43
1.86
Average$1.24
$1.37
$0.68
$3.29

In the Piceance and San Juan Basins, our natural gas is transported through our own and third-party gathering systems and pipelines, for which we incur processing, gathering, compression and transportation fees. The sales price for natural gas, condensate and NGLs is reduced for these third-party costs, and the cost of operating our own gathering systems is included in operations and maintenance. The gathering, compression, processing and transportation costs shown in the tables above include amounts paid to third parties, as well as costs incurred in operations associated with our own gas gathering, compression, processing and transportation.

Our 2014 amounts were impacted by a ten-year gas gathering and processing contract for natural gas production in our Piceance Basin in Colorado that became effective in 2014. This take-or-pay contract requires us to pay the fee on a minimum of 20,000 Mcf per day, regardless of the volume delivered. In 2014, our delivery of production did not meet the minimum requirement, and in 2015, we did not meet the minimum requirements of this contract until mid-February. We have excess production capacity from wells completed in 2015, and four additional wells which have not been completed, therefore do not foresee any challenges in our ability to meet this commitment. Our gathering, compression and processing costs on a per Mcfe basis, as shown in the tables above, will be higher in periods when we are not meeting the minimum contract requirements.

The following is a summary of our proved oil and gas reserves at December 31:
 201620152014
Bbls of oil (in thousands)2,242
3,450
4,276
MMcf of natural gas54,570
73,412
65,440
Bbls of NGLs (in thousands)1,712
1,752
1,720
Total MMcfe78,294
104,624
101,416

Reserves are based on reports prepared by CG&A, an independent consulting and engineering firm. Reserves are determined using SEC-defined product prices. Such reserve estimates are inherently imprecise and may be subject to revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. The current estimate takes into account 2016 production of approximately 12.1 Bcfe, additions from extensions, discoveries and acquisitions (sales) of (4.7) Bcfe and negative revisions to previous estimates of (9.4) Bcfe, primarily due to oil and natural gas prices.

Reserves reflect SEC-defined pricing held constant for the life of the reserves, as follows:
 2016 2015 2014
 Oil 
Gas (a)
 Oil Gas 
Oil 
 Gas
NYMEX prices$42.75
 $2.48
 $50.28
 $2.59
 $94.99
 $4.35
Well-head reserve prices$37.35
 $2.25
 $44.72
 $1.27
 $85.80
 $3.33
__________
(a)For reserves purposes, costs to gather gas previously netted from the gas price were reclassified into operating expensesour segment disclosures discussed in 2016, with approximate rates of $1.54/Mcf for Piceance, $0.92/Mcf for San Juan and $0.53/Mcf for all others. For accounting purposes, consistent with prior years, the sales price for natural gas is adjusted for transportation costs and other related deductions when applicable, as further described in Note 15 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.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.






20162019 Compared to 20152018


Revenue decreasedThe variance in Adjusted operating (loss) was primarily due to lowerprior 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.



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.


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 both crude oilunforeseen events affecting cash needs will continue to exist.

Our Utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas resultingwhich 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 24 percent decreasedowngrade 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 averagefuture is dependent on the amount of the initial transaction, changes in the market price, received, including hedges, foropen 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 soldhedging and storage programs in many of our regulated jurisdictions to mitigate significant changes in natural gas commodity pricing. We target hedging a 6 percent decreasepercentage 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.


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 average price received, including hedges, for crude oil sold. In addition, production decreased by 6 percent as compared to prior year as we limited natural gas production to meet minimum daily quantity contractual gas processing commitmentsstate in which the Piceance. Crude oil production also decreased due to non-core property sales in the fourth quarter of 2016.

Operations and maintenance decreased primarily due to lower employee costsutility assets are located. Furthermore, as a result of the reduction in staffing in the prior year, and lower production taxes and ad valorem taxes on lower revenue.

Depreciation, depletion and amortization decreased primarily dueour holding company structure, our right as a common shareholder to a reductionreceive assets of any of our full cost pool resulting fromdirect or indirect subsidiaries upon a subsidiary's liquidation or reorganization is subordinate to the ceiling test impairments incurred in currentclaims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and prior years.

Impairmentfuture claims of long-lived assets represents a non-cash write-down in the valuecreditors of our natural gassubsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and crude oil properties driven by low natural gasguarantee 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 crude oil pricesour ability to access the public and movement of certain unevaluated assets intoprivate 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 full-cost pool.counterparty to meet these obligations. The write-down of $107 million included a $14 million write-down of depreciable properties excluded from our full-cost pool and a ceiling test write-down of $93 million. The ceiling test write-down for the 12 months endedcash collateral we were required to post at December 31, 2016 used an average NYMEX natural gas price of $2.48 per Mcf, adjusted to $2.25 per Mcf at the wellhead, and $42.75 per barrel for crude oil, adjusted to $37.35 per barrel at the wellhead, compared to the $250 million ceiling test write-down in the same period of the prior year which used an average NYMEX natural gas price of $2.59 per Mcf, adjusted to $1.27 per Mcf at the wellhead, and $50.82 per barrel for crude oil, adjusted to $44.72 per barrel at the wellhead.2019 was not material.

Interest expense, net increased primarily due to higher interest expense driven by an increase in intercompany notes payable.

Impairment of equity investments represents a prior year non-cash write-down in equity investments related to interests in a pipeline and gathering system. The impairment resulted from continued declining performance, market conditions, and a change in view of the economics of the facilities that we considered to be other than temporary.

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

2015 Compared to 2014

Revenue decreased primarily due to lower commodity prices for both crude oil and natural gas, resulting in a 24 percent decrease in the average price received, including hedges, for crude oil sold and a 39 percent decrease in the average price received, including hedges, for natural gas sold. A 29 percent production increase driven by the nine Piceance Mancos shale wells placed on production in 2015 partially offset the decrease in commodity prices.

Operations and maintenancedecreased primarily due to lower production taxes and ad valorem taxes on lower revenue, partially offset by severance costs.

Depreciation, depletion and amortizationincreased primarily due to a higher depletion rate applied to increased production, partially offset by the reduction in our full cost pool as a result of the impact from the ceiling test impairments in the current year.

Impairment of long-lived assets represents a non-cash write-down in the value of our natural gas and crude oil properties driven by low natural gas and crude oil prices. The write-down reflected a trailing 12 month average NYMEX price of $2.59 per Mcf, adjusted to $1.27 per Mcf at the wellhead, for natural gas, and $50.28 per barrel, adjusted to $44.72 per barrel at the wellhead, for crude oil.

Interest expense, netincreased primarily due to third-party interest received on non-operated well revenue in the prior year that offset 2014 expense.

Impairment of equity investments represents a non-cash write-down in equity investments related to interests in a pipeline gathering system. The impairment resulted from continued declining performance, market conditions, and a change in the view of the economics of the facilities that we considered to be other than temporary.



Income tax (expense) benefit: The effective tax rate was comparable to the prior year.


CorporateDEBT, EQUITY AND LIQUIDITY


Corporate results represent certain unallocated costsDebt

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 administrative activitiesmore information.

We have a $750 million, unsecured CP Program that supportis backstopped by the business segments. Corporate also includes business development activities that do not fallRevolving Credit Facility. Amounts outstanding under the two business groups.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.


2016 Compared to 2015Our Revolving Credit Facility and CP Program had the following borrowings, outstanding letters of credit, and available capacity (in millions):

Net income (loss) available for common stock
  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, 2016,2019 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%


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.


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 $(37)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.


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 net (loss) available for common stock of $(14) million for the same period in the prior year.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.


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 variance$361 million increase from the prior year was due to higher corporate expenses, primarilycapital expenditures driven by costs relatedhigher 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 SourceGas Acquisition includingfollowing:

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 $30$299 million from the Equity Unit conversion partially offset by current year net proceeds of after-tax acquisition and transition costs$99 million through our ATM equity offering program;

Cash dividends on common stock of $125 million were paid in 2019 compared to $6.7$107 million of after-tax acquisitionpaid 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 priorOctober 3, 2019 debt transaction.




CAPITAL EXPENDITURES

Capital expenditures are a substantial portion of our cash requirements each year and approximately $9.1 million of after-tax internal labor that otherwise would have been chargedwe continue to other business segmentsforecast a robust capital expenditure program during the yearnext 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 2016, comparedwere 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 $3.0 millionoperate 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 after-tax internal laborcounterparties. After assessing the current operating performance, liquidity and credit ratings of the Company, management believes that otherwise wouldthe Company will have been charged to other business segments during the year ended December 31, 2015. These costs were partially offset by a tax benefit of approximately $4.4 million recognized during the year ended December 31, 2016 as a result of an agreement reached with IRS Appeals relatingaccess to the releasecapital 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 the reserve for after-tax interest expense previously accrued with respect to the liability for uncertain tax positions involving a like-kind exchange transaction from 2008.any other rating.


2015 ComparedThe 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 2014pay 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.


Net income (loss) available for common stock forCONTRACTUAL 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 twelve months ended future. The following information summarizes our cash obligations and commercial commitments at December 31, 2015, was $(14)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 comparedMMBtu, 3.7 million MMBtu, and 1.8 million MMBtu in each of the years from 2020 to net income (loss) available for common stock of $(1) million for the same period2022, respectively.

Off-Balance Sheet Commitments

We have entered into various off-balance sheet commitments in the prior year. The variance fromform 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 prior year was due to higher corporate expenses, primarily driven by costs relatedNotes to the SourceGas Acquisition including approximately $4.3 millionConsolidated Financial Statements in this Annual Report on Form 10-K.


Letters of after-tax bridge financing costs recognized in interest expense, approximately $3.0 millionCredit

Letters of after-tax internal labor that otherwise would have been charged to other business segments, and approximately $2.3 million in after-tax other expenses attributablecredit 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 acquisition during the year ended December 31, 2015, compared to the same periodConsolidated Financial Statements in the prior year.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.


Goodwill


We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired.  Beginning in 2016, we changed ourOur annual goodwill impairment testing date from November 30 tois as of October 1, to better align thewhich aligns our testing date with our financial planning process.   We believe that the change in the date of the annual goodwill impairment test from November 30 to October 1 is not a material change in the application of an accounting principle.  The new and old testing dates are close in proximity; both are in the fourth quarter of the year, and our current testing date is within ten months of the most recent impairment testing. We would not expect a materially different outcome as a result of testing on October 1 as compared to November 30. The change in assessment date does not have a material effect on the financial statements.




Accounting standards for testing goodwill for impairment require 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,calculation; 2) estimates of long-term growth rates for our businesses,businesses; 3) the determination of an appropriate weighted-average cost of capital or discount rate,rate; and 4) the utilization of market information such as recent sales transactions for comparable assets within the utility and energy industries. Varying by reporting unit, the weighted average cost of capital in the range of 5% to 8%6% and the long-term growth rate projections in the 1% to 2% range were utilized in the goodwill impairment test performed in the fourth quarter of 2016.2019. 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 cases,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, 2016, 2015,2019, 2018, and 2014,2017, there were no significant impairment losses recorded. At December 31, 2016,2019, the fair value substantially exceeded the carrying value at all reporting units.


Full Cost MethodAs described in Note 1 of Accounting for Oil and Gas Activities

Accounting for oil and gas activities is subject to special, unique rules. Two generally accepted methods of accounting for oil and gas activities are available - successful efforts and full cost. We account for our oil and gas activities under the full cost method, whereby all productive and nonproductive costs related to acquisition, exploration, development, abandonment and reclamation activities are capitalized. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonments of properties, are generally treated as adjustmentsNotes to the cost of the properties with no gain or loss recognized. Net capitalized costs are subject to a ceiling test that limits such costs to the aggregate of the present value of future net revenues of proved reserves and the lower of cost or fair value of unproved properties. This method values the reserves based upon SEC-defined prices for oil and gas as of the end of each reporting period adjusted for contracted price changes. The prices, as well as costs and development capital, are assumed to remain constant for the remaining life of the properties. If the net capitalized costs exceed the full-cost ceiling, then a permanent non-cash write-down is required to be charged to earnings in that reporting period. Under these SEC-defined product prices, our net capitalized costs were more than the full cost ceiling throughout 2016, which required an after-tax write-down of $58 million for the year ended December 31, 2016. Reserves in 2016 and 2015 were determined consistent with SEC requirements using a 12-month average price calculated using the first-day-of-the-month price for each of the 12 months in the reporting period held constant for the life of the properties adjusted for contracted price changes. Because of the fluctuations in natural gas and oil prices, we can provide no assurance that future write-downs will not occur.



Oil, Natural Gas, and Natural Gas Liquids Reserve Estimates

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

Despite the inherent imprecision in estimating our crude oil, natural gas and NGL reserves, the estimates are used throughout our financial statements. For example, since we use the unit-of-production method of calculating depletion expense, the amortization rate of our capitalized oil and gas properties incorporates the estimated unit-of-production attributable to the estimates of proved reserves. The net book value of our crude oil and gas properties is also subject to a “ceiling” limitation based in large part on the value of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures.

Risk Management Activities

In addition to the information provided below, see Note 9, “Risk Management Activities” and Note 10, “Fair Value Measurements,” of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.10-K, we have prospectively adopted ASU 2017-04, Simplifying the Test for Goodwill Impairment, on January 1, 2020.


Derivatives

We currently use derivative instruments, including options, swaps, and futures, to mitigate commodity purchase price risk and manage interest rate risk. Our typical hedging transactions fix the price received for anticipated future production at our Oil and Gas segment, or to fulfill the natural gas hedging plans for our Gas and Electric utilities. We also enter into interest rate swaps to convert a portion of our variable rate debt, or associated variable rate interest payments, to a fixed rate.

Accounting standards for derivatives require the recognition of all derivative instruments at fair value with changes in fair value ultimately recorded in the income statement. Our policy for recognizing the changes in fair value of these derivatives in earnings is contingent upon whether the derivative has been designated and qualified as part of a hedging relationship or if regulatory accounting requirements require a different accounting treatment. For gas derivatives in our regulated utility business, changes in fair value and settled gains and losses are recorded to regulatory assets or liabilities, and recognized subsequently as gas or fuel costs under regulatory-approved cost recovery mechanisms. For our other derivatives, if they are designated as cash flow hedges, the effective portion is recorded as a component of other comprehensive income (loss) until it is reclassified into earnings in the same period that the hedged item is recognized in earnings. The ineffective portion is recorded in current earnings.

Fair values of derivative instruments contracts are based on actively quoted market prices or other external source pricing information, where possible. If external market prices are not available, fair value is determined based on other relevant factors and pricing models that consider current market and contractual prices for the underlying financial instruments or commodities, as well as time value and yield curve or volatility factors underlying the positions.

Pricing models and their underlying assumptions impact the amount and timing of unrealized gains and losses recorded, and the use of different pricing models or assumptions could produce different financial results.

PensionLiquidity and Other Postretirement BenefitsCapital 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.


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.


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 describedan 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 187 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%


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 one benefit pension plan,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.


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 defined post-retirement healthcare plansregulated utilities, we are subject to various regulations that could influence our liquidity. Our utilities in Arkansas, Colorado, Iowa, Kansas and non-qualified retirement plans. A Master Trust holdsNebraska 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 Pension Plans. Trusts for$400 million Corporate term loan due June 17, 2021, retire the funded$200 million 5.875% senior notes due July 15, 2020, and repay a portion of the post-retirement healthcare plans have also been established.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 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.


Accounting for pensionShort-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 postretirement benefit obligations involves numerous assumptions, the most significant of which relateworking capital requirements;

Cash inflows increased by approximately $59 million compared to the discount rates, health care cost trend rates, expected return on plan assets, compensation increases, retirement ratesprior year primarily as a result of lower accounts receivable driven by lower pass-through revenues reflecting lower commodity prices; and mortality rates. The determination

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

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


The pension benefit cost for 2017 for our non-contributory funded pension plan is expected to be $2.1Investing Activities:

Net cash used in investing activities was $816 million in 2019, compared to $7.5net cash used in investing activities of $466 million in 2016.2018 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 decrease in pension benefit cost is$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 mergingCorriedale Wind Energy Project at our Electric Utilities segment, construction of the three benefit pension plans into one, improved mortality ratesfinal 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 better than expected return on plan assets,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 a decreasecurrent 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 discount rate.October 3, 2019 debt transaction.




BeginningCAPITAL 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 2016,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, changedmanagement believes that the method usedCompany will have access to estimate the servicecapital 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 interest cost componentsmay be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of the net periodic pension, supplemental non-qualified defined benefit andany other postretirement benefit costs. The new method used the spot yield curve approach to estimate the service and interest costs by applying the specific spot rates along the yield curve used to determine the benefit obligations to relevant projected cash outflows. Prior to 2016, the service and interest costs were determined using a single weighted-average discount rate based on hypothetical AA Above Median yield curves used to measure the benefit obligation at the beginning of the period. The change does not affect the measurement of the total benefit obligations as the change in service and interest costs offsets the actuarial gains and losses recorded in other comprehensive income.rating.


The Company changed tofollowing table represents the new method to provide a more precise measurecredit ratings, outlook and risk profile of service and interest costs by improving the correlation between the projected benefit cash flows and the discrete spot yield curve rates. The Company accounted for this change as a change in estimate prospectively beginning in 2016.

The effect of hypothetical changes to selected assumptions on the pension and other postretirement benefit plans would be as follows in thousands of dollars:BHC at December 31, 2019:
Rating AgencySenior Unsecured RatingDecember 31,
AssumptionsPercentage Change
2016
Increase/(Decrease)
PBO/APBO (a)
2017
 Increase/(Decrease) Expense - Pretax
PensionOutlook
Discount rate S&P (b)(a)
 +/- 0.5BBB+(25,788)/28,367(2,835)/3,080
Expected return on assets +/- 0.5N/A(1,816)/1,817
OPEBStable
Discount rate Moody’s (b)

 +/- 0.5Baa2(2,813)/3,051(29)/59
Expected return on assets +/- 0.5N/A(40)/40Stable
Health care cost trend rate Fitch (b)(c)
 +/- 1.0BBB+2,569/(2,191)374/(312)Stable
____________________________________
(a)Projected benefit obligation (PBO) for pension plansOn February 28, 2019, S&P affirmed our BBB+ rating and accumulated postretirement benefit obligation (APBO) for OPEB plans.maintained a Stable outlook.
(b)Impact on service cost, interest costOn December 20, 2019, Moody’s affirmed our Baa2 rating and amortization of gains or losses.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.


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.


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 utility operationsregulated Electric and Gas Utilities are subject to cost-of-service regulation with respectand earnings oversight from federal and state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our retail electric and gas utility rates service area, accounting,are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of our costs, as reviewed and various other matters by stateapproved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and federal regulatory authorities. The accounting regulations provide that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effects of the manner in which independent third-party regulators establish rates. Regulatory assets generally represent incurred or accrued costs that have been deferred when future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.allowed return on invested capital at any given time.


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


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.


Unbilled RevenueGoodwill


Revenues attributableWe 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 gasanalyze 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 delivered to customers,industries. These valuations require significant judgments, including, but not yet billed under the cycle billing method, arelimited 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 and accrued and the related costs are charged to expense. Factors influencingusing a terminal value calculation; 2) estimates of long-term growth rates for our businesses; 3) the determination of unbilled revenues may include estimatesan appropriate weighted-average cost of deliveredcapital or discount rate; and 4) the utilization of market information such as recent sales volumes based on weather informationtransactions for comparable assets within the utility and customer consumption trends.

Income Taxes

The Companyenergy industries. Varying by reporting unit, weighted average cost of capital in the range of 5% to 6% and its subsidiaries file consolidated federal income tax returns. Aslong-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 resultlong-term growth rate projection, the short-term projected growth rate is higher with planned recovery of the SourceGas transaction, certain acquired subsidiaries file as a separate consolidated group. Each tax-paying entity records income taxes as if it were a separate taxpayercapital investments through rider mechanisms and consolidating 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 liabilitiesrate 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 lossdata 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 tax credit carryforwards. Such temporary differences are the result of provisionsassumptions used in the income tax law that either require or permit certain items to be reportedimpairment assessments are based on the income tax return in a different period thanavailable market information and we believe they are reportedreasonable. However, variations in the financial statements.

In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or allany of the deferred tax assets willassumptions could result in materially different calculations of fair value and determinations of whether or not be realizedan impairment is indicated. For the years ended December 31, 2019, 2018, and provides any necessary valuation allowances as required. If we determine that we will be unable2017, 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 realize all or part of our deferred tax assets in the future, an adjustment to the deferred tax asset would be charged to income in the period such determination was made. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretations of tax laws and the resolution of current and any future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements.

See Note 15 in our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K, we have prospectively adopted ASU 2017-04, Simplifying the Test for additional information.Goodwill Impairment, on January 1, 2020.


Business Combinations

We record acquisitions in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. The excess of the purchase price over the estimated fair values of the net tangible and net intangible assets acquired is recorded as goodwill. The application of ASC 805, Business Combinations requires management to make significant estimates and assumptions in the determination of the fair value of assets acquired and liabilities assumed in order to properly allocate purchase price consideration between goodwill and assets that are depreciated and amortized. Pertaining to our current year acquisition of SourceGas, substantially all of SourceGas’ operations are subject to the rate-setting authority of state regulatory commissions, and are accounted for in accordance with GAAP for regulated operations. SourceGas’ assets and liabilities subject to rate setting provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair value of these assets and liabilities equal their historical net book values.

Our estimates are based on historical experience, information obtained from the management of the acquired companies and, when appropriate, include assistance from independent third-party appraisal firms. These estimates are inherently uncertain and unpredictable. In addition, unanticipated events or circumstances may occur which may affect the accuracy or validity of such estimates. See Note 2 in our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.



Liquidity and Capital Resources


OVERVIEW


BHC and its subsidiaries requireOur company requires significant cash to support and grow theirour businesses. Our predominant source of cash is supplied byfrom our operations and supplemented with corporate borrowings.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.


The most significant uses of cash are our capital expenditures, the purchase of natural gas for our Gas Utilities and our Power Generation segment, as well as the payment of dividends to our shareholders. We experience significant cash requirements during peak months of the winter heating season due to higher natural gas consumption and during periods of high natural gas prices.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, and anticipated dividends, and anticipated capital expenditures.expenditures discussed in this section.


The following table provides an informational summary of our financial position as of December 31 (dollars in thousands):

Financial Position Summary2016201520192018
Cash and cash equivalents (a)
$13,580
$440,861
$9,777
$20,776
Restricted cash and equivalents$2,274
$1,697
$3,881
$3,369
Notes payable$349,500
$185,620
Short-term debt, including current maturities of long-term debt$102,343
$76,800
$5,743
$5,743
Long-term debt$3,211,189
$1,853,682
Long-term debt (a)
$3,140,096
$2,950,835
Stockholders’ equity$1,614,639
$1,465,867
$2,362,123
$2,181,588
  
Ratios  
Long-term debt ratio67%56%57%57%
Total debt ratio67%57%60%59%
______________
(a)Cash and cash equivalents include the proceeds from the November 23, 2015 issuanceCarrying amount of common stock and equity units as discussed below.long-term debt is net of deferred financing costs.

As described below in the Debt and Liquidity section, in 2016, we implemented a $750 million, unsecured CP Program that is backstopped by our Revolving Credit Facility, we amended and restated our corporate Revolving Credit Facility to increase total commitments to $750 million from $500 million and extended the term through August 9, 2021 and we entered into a new $500 million term loan expiring August 9, 2019. We completed the permanent financing for the SourceGas Acquisition. In addition to the net proceeds of $536 million from our November 2015 equity issuances, we completed the Acquisition financing with $546 million of net proceeds from our January 2016 debt offering. We also refinanced the long-term debt assumed with the SourceGas Acquisition primarily through $693 million of net proceeds from our August 19, 2016 debt offerings. In addition to our debt refinancings, we issued 1.97 million shares of common stock for approximately $119 million through our ATM equity offering program, and sold a 49.9% noncontrolling interest in Black Hills Colorado IPP for $216 million.


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 the Companywe 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.

In August 2016, we settled $400 million of interest rate swaps, and our remaining interest rate swap expired in January 2017. We currently have no interest rate swap transactions for which we could be required to post collateral on the value of such swaps in the event of an adverse change in our financial condition, including a credit downgrade to below investment-grade.

At December 31, 2016, we had $1.3 million of collateral posted related to our wholesale commodity contracts transactions, and no collateral posted related to our interest rate swap transactions. At December 31, 2016,2019, we had sufficient liquidity to cover any additional 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 approximately 50% to 70%a percentage of our forecasted natural gas supply consumption using options, futures, basis swaps and over-the-counter swaps.physical fixed price purchases.

Oil and Gas Factors

Our cash flows in our Oil and Gas segment can be subject to fluctuations in commodity prices.  Significant changes in crude oil or natural gas commodity prices can have a significant impact on liquidity needs.  Since commodity prices are uncontrollable, we have implemented a hedging program to mitigate the effects of significant changes in crude oil and natural gas commodity pricing on existing production.  New production is subject to market prices until the production can be quantified and hedged. We use a price-based approach where, based on market pricing, our existing natural gas and crude oil production can be hedged using options, futures and basis swaps for a maximum term of three years forward.  See “Market Risk Disclosures” for hedge details.


Interest Rates


SeveralSome of our debt instruments hadhave a variable interest rate component which can change significantly depending on the economic climate. We deploy hedging strategies that include pay-fixeddo not have any interest rate swap agreements to reduce our exposure to interest rate fluctuations. At at December 31, 2016, 86%2019; 90% of our interest rate exposure has been mitigated through either fixed or hedged interest rates.


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

At December 31, 2016, we had $50 million notional amount pay-fixed interest rate swap, which expired in January 2017. These swaps were designated as cash flow hedges and accordingly their mark-to-market adjustments were recorded in AOCI on the accompanying Consolidated Balance Sheets. The mark-to-market value of these swaps was a liability of $0.1 million at December 31, 2016.



Federal and State Regulations

Federal


We are structured as a utility holding company which owns several regulated utilities. Within this structure, we are subject to various regulations by our commissions that can influence our liquidity. As an example, the issuance of debt by our regulated subsidiaries and the use of our utility assets as collateral generally require the prior approval of the state regulators in the state in which the utility assets are located. Furthermore, as a result of our holding company structure, our right as a common shareholder to receive assets of any of our direct or indirect subsidiaries upon a subsidiary's liquidation or reorganization is subordinate to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders.

Income Tax

Acceleration of depreciation for tax purposes including 50% bonus depreciation was previously available for certain property placed in service during 2014. The Protecting Americans from Tax Hikes Act (PATH), enacted into law on December 18, 2015, extended 50% bonus depreciation generally to qualifying property placed in service during 2015 through 2017, 40% bonus depreciation generally to qualifying property placed in service during 2018, and 30% bonus depreciation generally to qualifying property placed in service during 2019. These provisions resulted in approximately $179 million of cash tax benefits for BHC as indicated in the table below:
(in millions)201620152014
Tax benefit$81$33$65

In addition, bonus depreciation will apply to qualifying property whose construction and completion period encompasses multiple tax years. The exception being with respect to costs that would be incurred in 2020 when, under current law, bonus depreciation is scheduled to expire. No projects are expected to be subject to this provision. The effect of additional depreciation deductions as a result of bonus depreciation will serve to reduce taxable income and contribute to extending the tax loss carryforwards from being fully utilized until 2021 based on current projections.

The cash generated by bonus depreciation is an acceleration of tax benefits that we would have otherwise received over 15 to 20 years. Additionally, from a regulatory perspective, while the capital additions at the Company’s regulated businesses generally increase future revenue requirements, the bonus depreciation associated with these capital additions will partially mitigate future rate increases related to capital additions.

See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.


CASH GENERATION AND CASH REQUIREMENTS


Cash Generation


Our primary sources of cash are generated from operating activities, our five-year Revolving Credit Facility expiring August 9, 2021,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 positions with the counterparty to meet these obligations.

We have posted the following amounts of The cash collateral with counterpartieswe were required to post at December 31, (in thousands):2019 was not material.

Purpose of Cash Collateral20162015
Natural Gas Futures and Basis Swaps Pursuant to Utility Commission Approved Hedging Programs$12,722
$27,659
Oil and Gas Derivatives2,733
1,672
Total Cash Collateral Positions$15,455
$29,331



DEBT, EQUITY AND LIQUIDITY


Operating ActivitiesDebt


Our principal sources to meet day-to-day operating cash requirements are cash from operations, our corporate Revolving Credit Facility and our CP Program.Program


Revolving Credit Facility

On August 9, 2016,July 30, 2018, we amended and restated our corporate Revolving Credit Facility, to increasemaintaining total commitments toof $750 million from $500 million and extendextending the term through August 9, 2021July 30, 2023 with two one-year extension options (subject to consent from the lenders). This facility is similar to the former agreement,revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, andthe issuing agents and subject to receipt of additional commitments from existingeach bank increasing or providing a new lenders,commitment, to increase total commitments of the facility up to $1$1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated withSee Note 7 of our Notes to the letters of credit or borrowings andConsolidated 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 commitment feeRevolving Credit Facility. Amounts outstanding under the Revolving Credit Facility are determined based uponand the CP Program, either individually or in the aggregate, cannot exceed $750 million. See Note 7 of our most favorable Corporate credit rating from either S&P or Moody’sNotes to the Consolidated Financial Statements in this Annual Report on Form 10-K for our unsecured debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.250%, 1.250%, and 1.250%, respectively, at December 31, 2016. A 0.200% commitment fee is charged on the unused amount of the Revolving Credit Facility.more information.


Our Revolving Credit Facility at December 31, 2016,and CP Program had the following borrowings, outstanding letters of credit, and available capacity (in millions):
 CurrentBorrowings atLetters of Credit atAvailable Capacity at CurrentShort-term borrowings atLetters of Credit atAvailable Capacity at
Credit FacilityExpirationCapacityDecember 31, 2016December 31, 2016ExpirationCapacityDecember 31, 2019December 31, 2019
Revolving Credit FacilityAugust 9, 2021$750
$97
$36
$617
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%


The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on certain liens, restrictions on certain transactions, and maintenance of a certain Consolidated Indebtedness to Capitalization Ratio. Under the Revolving Credit Facility, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.70 to 1.00 for the quarter ending December 31, 2016 and subsequently for future quarters beginning March 31, 2017, maintain the 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, certain guarantees issued and excludes RSNs by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interests in subsidiaries and includes the aggregate outstanding amount of the RSNs. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. We were in compliance with these covenants as of December 31, 2016.2019. 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.


On December 22, 2016, we implementedCross-Default Provisions

Our $7 million Corporate term loan contains cross-default provisions that could result in a $750default 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 unsecured CP Programor more that is backstopped bypermits the Revolving Credit Facility. Amounts outstanding under theacceleration of debt maturities or mandatory debt prepayment. Our Revolving Credit Facility contains the same provisions and the CP Program, either individuallythreshold 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 aggregate, cannot exceed $750 million. The notes issued underCompany. We have established utility money pool agreements which address these requirements. These agreements are on file with the CP ProgramFERC and appropriate state regulators. Under the utility money pool agreements, our utilities may have maturities notat their option, borrow and extend short-term loans to exceed 397 daysour 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 date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things,Company (as ultimate parent company), the size and maturity date ofmoney pool arrangement does not allow loans from our utility subsidiaries to 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 pursuantCompany (as ultimate parent company) or to an exemption registration. We did not borrow under the CP Program in 2016 and do not have any notes outstanding as of non-regulated affiliates.

At December 31, 2016.2019, 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
Capital Resources

Equity
Our principal sources for our long-term capital needs
Shelf Registration

We have been issuances of long-term debt securities byan effective automatic shelf registration statement on file with the Company and its subsidiaries along with proceeds obtained from public and private offerings of equity and proceeds from our ATM equity offering program.

Recent Financing Transactions

On March 18, 2016,SEC under which we implemented an ATM equity offering program allowing us to sell shares of our common stock with an aggregate value of up to $200 million. The shares may be offeredissue, from time to time, pursuantsenior 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 a sales agreement dated March 18, 2016. Sharesissue 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 are offered pursuant to our shelf registration statement filed with the SEC. Throughand 25 million shares of preferred stock. As of December 31, 2016,2019, 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.


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 soldregulatory 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 an aggregatea total of 1,968,7381.3 million shares of common stock under the ATM equity offering program for $119proceeds of $99 million, net of $1.2 million in commissions. As of December 31, 2016, there were no shares sold that were not settled.issuance costs.


On December 22, 2016, we implemented a CP Program as outlined above.

On August 19, 2016,October 3, 2019, we completed a public debt offering of $700 million principal amount ofin senior unsecured notes. The debt offering consisted of $400 million of 3.15%3.05% 10-year senior notes due JanuaryOctober 15, 20272029, and $300 million of 4.20%3.875% 30-year senior notes due SeptemberOctober 15, 2046.2049. Proceeds were used to repay the debt assumed in SourceGas Acquisition which included $95$400 million Corporate term loan due June 17, 2021, retire the $200 million 5.875% senior unsecured notes $325due 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 senior unsecured notesfrom $300 million, extended the term through June 17, 2021 and continued to have substantially similar terms and covenants as the remaining $100 million of the former $340 million term loan. Additionally, theamended and restated Revolving Credit Facility. The net proceeds were used to pay down $100 million onshort-term debt. Proceeds from the term loan issued August 9, 2016 discussed below, and for other corporate uses.

On August 9, 2016, we entered into a $500 million, three-year, unsecured term loan expiring on August 9, 2019. The proceeds of this term loanOctober 3, 2019 debt transaction were used to pay down $240 million of the $340 million unsecuredrepay this term loan assumed in the SourceGas Acquisition and the $260 million term loan expiring on April 12, 2017.loan.


On August 9, 2016, we amended and restatedShort-term borrowings from our corporate Revolving Credit Facility to increase total commitments to $750 million from $500 million and extended the term through August 9, 2021 with two one-year extension options (subject to consent from lenders). This facility is similar to the former agreement, which included an accordion feature that allows us, with the consent of the administrative agent and issuing agents and subject to receipt of additional commitments from existing or new lenders, to increase total commitments of the facility to up to $1 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options.CP Program.


On June 7, 2016, we entered into a 2.32%, $29 million term loan, due June 7, 2021. Proceeds from this term loan were used to finance the regulatory asset related to the early termination of a gas supply contract (see Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K). Principal and interest are payable quarterly at approximately $1.6 million, the first of which was paid on June 30, 2016.

On April 14, 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for approximately $216 million. FERC approval of the sale was received on March 29, 2016. We used the proceeds from this sale to pay down borrowings on our revolving credit facility. This sale resulted in an increase to stockholders’ equity of approximately $62 million as this sale of a portion of the business that is still controlled is accounted for as an equity transaction and no gain or loss on such sale is recorded.

We completed the following equity and debt transactions in placing permanent financing for SourceGas:

On January 13, 2016, we completed a public debt offering of $550 million in senior unsecured notes. The debt offering consists of $300 million of 3.95%, 10-year senior notes due 2026, and $250 million of 2.5%, 3-year senior notes due 2019. Net proceeds after discounts and fees were approximately $546 million; and

On November 23, 2015, we completed the offerings of common stock and equity units. We issued 6.325 million shares of common stock for net proceeds of $246 million and 5.98 million equity units for net proceeds of $290 million. Each equity unit has a stated amount of $50 and consists of a contract to (i) purchase Company common stock and (ii) a 1/20, or 5%, undivided beneficial ownership interest in $1,000 principal amount of remarketable junior subordinated notes due 2028. Pursuant to the purchase contracts, holders are required to purchase Company common stock no later than November 1, 2018.



Our $1.17 billion bridge commitment signed on July 12, 2015 was reduced to $88 million on January 13, 2016, with respect to reductions from our equity and debt offerings. The remaining commitment terminated on February 12, 2016 as part of the closing of the SourceGas Acquisition.

We assumed the following tranches of debt through the SourceGas Acquisition on February 12, 2016; all of which were refinanced in August 2016 as outlined above:

$325 million, 5.9% senior unsecured notes with an original issue date of April 16, 2007, due April 16, 2017.

$95 million, 3.98% senior secured notes with an original issue date of September 29, 2014, due September 29, 2019.

$340 million unsecured corporate term loan due June 30, 2017. Interest expense under this term loan was LIBOR plus a margin of 0.88%.

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

Future Financing Plans


During the next three years, BHC will evaluateWe anticipate the following financing activities:activities in 2020:


Extending our Revolving Credit Facility;

RenewingRenew our shelf registration and ATM;

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


Remarketing junior subordinated notes maturing in 2018;

Refinancing our term loan maturing in 2019; and

Paying off our $250 million, 3-year note maturing in 2019.

Cross-Default Provisions

Our $400 million and $24 million corporate term loans contain cross-default provisions that could result inRefinance a default under such agreements if BHC or its material subsidiaries failed to make timely paymentsportion of debt obligations or triggered other default provisions under any debt agreement totaling, inshort-term borrowings held through the aggregate principal amount of $50 million or more that permits the acceleration of debt maturities or mandatory debt prepayment. Our Revolving Credit Facility contains the same provisions and a threshold principal amount is $50 million.

The Revolving Credit Facility prohibits us from paying cash dividends if we are in default or if paying dividends would cause us to be in default.

Equity

Outside of our ATM equity offering program mentioned above, and based on our current capital spending forecast, we do not anticipate the need to further access the equity capital markets in the next three years.

Shelf Registration

We have an effective automatic shelf registration statement on file with the SEC under which we may issue, from time to time, senior debt securities, subordinated debt securities, common stock, preferred stock, warrants and other securities. Although the shelf registration statement does not limit our issuance capacity, our ability to issue securities is limited to the authority granted by our Board of Directors, certain covenants in our financing arrangements and restrictions imposed by federal and state regulatory authorities. This shelf registration expires in August 2017. Our articles of incorporation authorize the issuance of 100 million shares of common stock and 25 million shares of preferred stock. As of December 31, 2016, we had approximately 53 million shares of common stock outstanding and no shares of preferred stock outstanding.



Common Stock Dividends

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

On January 25, 2017, our Board of Directors declared a quarterly dividend of $0.445 per share or an annualized equivalent dividend rate of $1.78 per share. The table below provides our historical three-year dividend payout ratio and dividends paid per share:

 201620152014
Dividend Payout Ratio (a)
123%(228)%53%
Dividends Per Share$1.68$1.62$1.56
____________________________
(a)2016 and 2015 reflect the impacts of non-cash impairments of our Oil and Gas properties totaling $107 million and $250 million, respectively.

Our three-year compound annualized dividend growth rate was 3.4% and all dividends were paid out of available operating cash flows.

Dividend Restrictions

As a utility holding company which owns several regulated utilities, we are subject to various regulations that could influence our liquidity. For example, the issuance of debt by our utility subsidiaries (including the ability of Black Hills Utility Holdings to issue debt) and the use of our utility assets as collateral generally requires the prior approval of the state regulators in the state in which the utility assets are located. As a result of our holding company structure, our right as a common shareholder to receive assets from any of our direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders.
Our credit facilities and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be deemed to have occurred if we did not comply with certain financial or other covenants. At December 31, 2016, our Revolving Credit Facility and Corporate term loans included a Consolidated IndebtednessCP Program to Capitalization Ratio notlong-term debt; and

Continue to exceed 0.70assess debt and equity needs to 1.00, changing to 0.65 to 1.00 in subsequent quarters, beginning March 31, 2017. As of December 31, 2016, we were in compliance with these covenants.support our capital expenditure plan.

In addition, the agreements governing our equity units generally restrict the payment of cash dividends at any time we have exercised our right to defer payment of contract adjustment payments under the purchase contracts or interest payments under the junior subordinated notes included in such equity units. Moreover, holders of purchase contracts will be entitled to additional shares of our common stock upon settlement of the purchase contracts if we pay regular quarterly dividends in excess of $0.405 per share while the purchase contracts are outstanding. On January 25, 2017, we declared a quarterly dividend of $0.445 per share.

Covenants within Wyoming Electric's financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of no more than .60 to 1.00. Our utilities in Arkansas, Colorado, Iowa, Kansas and Nebraska have regulatory agreements in which they cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40% of their total capitalization; and neither Black Hills Utility Holdings nor its utility subsidiaries can extend credit to the Company except in the ordinary course of business and upon reasonable terms consistent with market terms. Additionally, our utility subsidiaries may generally be limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may have further restrictions under the Federal Power Act. As of December 31, 2016, the restricted net assets at our Electric and Gas Utilities were approximately $257 million.



Utility Money Pool

As a utility holding company, we are required to establish a cash management program to address lending and borrowing activities between our utility subsidiaries and the Company. We have established utility money pool agreements which address these requirements. These agreements are on file with the FERC and appropriate state regulators. Under the utility money pool agreements, our utilities may at their option, borrow and extend short-term loans to our other utilities via a utility money pool at market-based rates (2.213% at December 31, 2016). While the utility money pool may borrow funds from the Company (as ultimate parent company), the money pool arrangement does not allow loans from our utility subsidiaries to the Company (as ultimate parent company) or to non-regulated affiliates.

At December 31, money pool balances included (in thousands):
 
Borrowings From
(Loans To) Money Pool Outstanding
Subsidiary20162015
Black Hills Utility Holdings$52,370
$98,219
South Dakota Electric(28,409)(76,813)
Wyoming Electric20,737
25,815
Total Money Pool borrowings from Parent$44,698
$47,221


CASH FLOW ACTIVITIES


The following table summarizes our cash flows (in thousands):
201620152014201920182017
Cash provided by (used in)  
Operating activities$320,463
$424,295
$315,317
$505,513
$488,811
$428,261
Investing activities$(1,588,742)$(476,389)$(401,147)$(816,210)$(465,849)$(317,118)
Financing activities$840,998
$483,702
$91,067
$300,210
$(17,057)$(108,695)


20162019 Compared to 20152018


Operating Activities:


Net cash provided by operating activities was $104$17 million lowerhigher than in 20152018. The variance to the prior year was primarily attributable to the SourceGas acquisition and the following:to:


Cash earnings (income from continuing operations plus non-cash adjustments) were $63$37 million higher than prior year.year driven primarily by higher margins at our Electric and Gas Utilities;


Net outflowoutflows from operating assets and liabilities was $144were $25 million higher than prior year, primarily attributable to:

Cash inflows decreased by approximately $75 million compared to the prior year as a result of higher materials, supplies and fuel and higher accounts receivable partially due to colder weather and higher natural gas volumes sold;

Cash inflows decreased by approximately $34 million primarily as a result of changes in our current regulatory assets and liabilities driven by differences in fuel cost adjustments and commodity price impacts compared to the same period in the prior year;


Cash outflows increased by approximately $35$40 million as a result of changes in accounts payable and accrued liabilities, driven primarily by acquisition and transitionthe impact of higher outside services, employee costs and a reduction in uncertain tax positions liability, partially offset by an increase in accrued interest;other working capital requirements;


Cash outflowsinflows increased by approximately $29$59 million compared to the prior year primarily as a result of interestlower 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 swap settlements;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 increased by $4.0decreased approximately $5.5 million due to pension contributions; and



Cash inflows increased approximately $9.8 million for otherthe absence of operating activities compared to the prior year.of discontinued operations in 2019.


Investing Activities:


Net cash used in investing activities was $1.6 billion$816 million in 2016, which2019, compared to net cash used in investing activities of $466 million in 2018 for a variance of $350 million. This variance was an increase in outflows of $1.1 billion from 2015 primarily due to:

Capital expenditures of approximately $818 million in 2019 compared to $458 million in 2018. The $361 million increase from the following:

Cash outflows of $1.1 billion for the acquisition of SourceGas, net of $11 million cash received from a working capital adjustment and $760 million of long term debt assumed (see Note 2 in Item 8 of Part II of this Annual Report on Form 10-K);

In 2016, we hadprior year was due to higher capital expenditures of $19 million primarilydriven by higher programmatic safety, reliability and integrity spending at our Electric and Gas Utilities segments, the Corriedale Wind Energy Project at our Electric Utilities and Gas Utilities, driven by current year wind and natural gas generation additionssegment, construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota, to Stegall, Nebraska, at our Electric Utilities and additional capitalsegment, the 35-mile Natural Bridge pipeline project at our acquired SourceGas Utilities. This is partially offset by lower current year capital expendituresGas Utilities segment, and construction of Busch Ranch II at our Oil and Gas segment. In 2015 our Oil and Gas segment completed their 2014/2015 Piceance drilling program, while 2016 had no further drilling capital deployed;

Our Oil and Gas segment divested of non-core assets, selling properties for $11 million;Power Generation segment; and


In 2015, we acquired the net assetsNet cash used in investing activities decreased $4.0 million due to prior year activities associated with divesting of two naturalour oil and gas utilities for $22 million.segment.


Financing Activities:


Net cash provided by financing activities was $841$300 million in 2016,2019 as compared to net cash used by financing activities of $17 million in 2018, an increase of $357$317 million from 2015 primarily due to the following:


ProceedsIncrease of $216$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 sale of a 49.9% noncontrolling interest of Black Hills Colorado IPP (see Note 12 in Item 8 of Part II of this Annual Report on Form 10-K);

Long-term borrowings increased due to the $693 million of net proceeds from our August 19, 2016 public debt offering used to refinance the debt assumed in the SourceGas Acquisition, the $500 million of proceeds from our new term loan on August 9, 2016 used to pay off existing debt, the $546 million of net proceeds from our January 13, 2016 public debt offering used toEquity Unit conversion partially finance the SourceGas Acquisition, and proceeds from a $29 million term loan used to fund the early settlement of a gas gathering contract, compared to proceeds of $300 million from long-term borrowings from a term loan in the prior year;

Payments on long term borrowings increased due to payments made in theoffset by current year to refinance the $760 million of long-term debt assumed in the SourceGas Acquisition and $404 million of current year payments made on term loans compared to the payment of $275 million made as part of a term-loan refinancing in the prior year;

In 2015, we received net proceeds of $290$99 million from the issuance of our RSNs;

Proceeds of $120 million primarily from issuing common stock underthrough our ATM equity offering program. 2015 included net proceeds fromprogram;

Cash dividends on common stock issuances of $246 million;$125 million were paid in 2019 compared to $107 million paid in 2018; and

Net short-term borrowings under the revolving credit facility for the year ended December 31, 2016 were $18 million higher than the prior year primarily due to higher working capital requirements in the current year;

Distributions to noncontrolling interests of $9.6 million;


Cash outflows for other financing activities increased by approximately $14$5.5 million driven primarily by approximately $22 million ofcurrent year financing costs and make whole payments madeincurred in 2016 compared to $7 million of bridge facility fees paid in 2015, andthe October 3, 2019 debt transaction.




Cash dividends on common stock of $88 million were paid in 2016 compared to $73 million paid in 2015.



2015 Compared to 2014

Operating Activities:

Net cash provided by operating activities was $109 millionhigher than in 2014 primarily attributable to:

Net inflow from operating assets and liabilities of continuing operations was $128 million higher than prior year, primarily attributable to:

Cash inflows increased by approximately $11 million compared to the prior year as a result of decreased gas volumes in inventory due to milder weather and lower natural gas prices;

Cash inflows from working capital increased, driven primarily by $52 million as a result of lower customer receivables and by $61 million as a result of lower working capital requirements for natural gas for the year ended December 31, 2015 compared to the prior year. Colder weather and higher natural gas prices during the first quarter 2014 peak winter heating season drove a significant increase in natural gas volumes sold, and in natural gas volumes purchased and fuel cost adjustments recorded in regulatory assets. These fuel cost adjustments deferred in the prior year are recovered through their respective cost mechanisms as allowed by state utility commissions;

Cash outflows increased approximately $11 million for other operating activities compared to the prior year, primarily by increased benefit plan expenses; and

Cash earnings (income from continuing operations plus non-cash adjustments) were $9 million lower than prior year.

Investing Activities:

Net cash used in investing activities was $476 million in 2015, which was an increase in outflows of $75 million from 2014 primarily due to the following:

In 2015, we had higher capital expenditures of $57 million primarily due to our Oil and Gas segment completing the 2014/2015 Piceance drilling program, lower prior year capital affected by weather delays, and increased capital expenditures at our Coal Mine and Gas Utilities. Offsetting these 2015 capital expenditure increases is the construction of Cheyenne Prairie at our Electric Utilities segment occurring in the prior year; and

In 2015, we acquired the net assets of two natural gas utilities for $22 million.

Financing Activities:

Net cash provided by financing activities was $484 million in 2015, which was an increase in inflow of $393 million from 2014 primarily due to the following:

Net Long-term borrowings were $315 million in 2015 reflecting a $25 million net increase in our Corporate term loan, and the $290 million issuance of our RSNs, net of issuance costs, compared to net long-term borrowings of $148 million in 2014 when South Dakota Electric and Wyoming Electric sold $160 million of first mortgage bonds in a private placement to provide permanent financing for Cheyenne Prairie and repaid $12 million of South Dakota Electric’s pollution control bonds;

In 2015, we issued 6.325 million shares of common stock for $246 million, net of issuance costs;

Net Short-term borrowings under the revolving credit facility were $9.3 million higher than the prior year;

Cash outflows for other financing activities increased by approximately $26 million driven primarily by $7 million of bridge facility fees paid in 2015, and proceeds of $22 million received in 2014 from the sale of an asset at our Power Generation segment, which under GAAP, this transaction did not qualify as the sale of an asset and the proceeds are presented as a financing activity; and

Cash dividends on common stock of $73 million were paid in 2015 compared to $70 million paid in 2014.



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


Historically, aA significant portion of our capital expenditures relate primarilyrelates to safety, reliability and integrity assets benefiting customers that may be included in utility rate base and if considered prudent by regulators, can be recovered from our utility customers.customers following regulatory approval. Those capital expenditures also earn a rate of return authorized by the commissions in the jurisdictions in which we operate and are subject to rate agreements. During 2016, our Electric Utilities’ capital expenditures included additional generation from Colorado Electric’s Peak View Wind Project and their natural gas CT, improvements to generating stations, transmission and distribution lines. Capital expenditures associated with our Gas Utilities are primarily to improve or expand the existing gas distribution network. We believe that cash generated from operations and borrowing on our CP Program and our existing Revolving Credit Facility will be adequate to fund ongoing capital expenditures.operate.


Historical Capital Requirements


Our primary capital requirements for the three years ended December 31 were as follows (in thousands):
2016 2015 20142019 2018 2017
Property additions: (a)
          
Electric Utilities (b)
$258,739
 $171,897
 $171,475
$222,911
 $152,524
 $138,060
Gas Utilities (b)(c)
173,930
 99,674
 92,252
512,366
 288,438
 184,389
Power Generation(d)4,719
 2,694
 2,379
85,346
 30,945
 1,864
Mining5,709
 5,767
 6,676
8,430
 18,794
 6,708
Oil and Gas (c)
6,669
 168,925
 109,439
Corporate17,353
 9,864
 9,046
Total expenditures for property, plant and equipment467,119
 458,821
 391,267
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 dividends87,570
 72,604
 69,636
124,647
 106,591
 96,744
Maturities/redemptions of long-term debt1,164,308
 275,000
 12,200
905,743
 854,743
 105,743
$1,718,997
 $806,425
 $473,103
Total capital requirements$1,880,145
 $1,466,160
 $563,398
____________________________
(a)
Includes accruals for property, plant and equipment.equipment as disclosed in Note 17 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
(b)Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported inCurrent year capital expenditures at our Gas Utilities segment. Cheyenne Light’s gas utility property additions as of the years ended December 31, 2015 and 2014 have been reclassified from the Electric Utilities segment increased due to higher programmatic safety, reliability and integrity spending, the Gas Utilities segment. Property additionsCorriedale wind project and construction of $30 million and $22 million, respectively, previously reported in the Electric Utilitiesfinal segment in 2015 and 2014 are now presented inof the Gas Utilities segment.175-mile transmission line from Rapid City, South Dakota, to Stegall, Nebraska.
(c)In 2015, we drilledCurrent year capital expenditures at our Gas Utilities segment increased due to higher programmatic safety, reliability and integrity spending and the last35-mile Natural Bridge pipeline project.
(d)Current year capital expenditures at our Power Generation segment increased due to construction of 13 Mancos Shale wells for our 2014/2015 drilling program. We placed nine on production in 2015. Completion of the four remaining wells was deferred based on the positive results of our nine wells, insufficient gas processing capacity, and continued low commodity prices in 2016.Busch Ranch II.




Forecasted Capital Expenditure Requirements

Our primary capital expenditure requirements for the three years ended December 31 are expected to be as follows (in thousands):
 2017 2018 2019
      
Electric Utilities$121,000
 $112,000
 $139,000
Gas Utilities179,000
 169,000
 190,000
Power Generation2,000
 9,000
 18,000
Mining7,000
 7,000
 8,000
Oil and Gas3,000
 5,000
 2,000
Corporate12,000
 3,000
 8,000
 $324,000
 $305,000
 $365,000

We have removed Cost of Service Gas capital expenditures from this forecast due to uncertainties related to the timing of regulatory approvals and other information associated with those approvals, such as the quantity of gas to be provided from a cost of service gas program and whether such gas will be provided from producing reserve purchases or ongoing drilling programs, or both.

We continue to evaluate potential future acquisitions and other growth opportunities which are dependent upon the availability of economic opportunities and, as a result, capital expenditures may vary significantly from the estimates identified above.


CREDIT RATINGS AND COUNTERPARTIES


Financing for operational needs and capital expenditure requirements, not satisfied by operating cash flows, depends upon the cost and availability of external funds through both short and long-term financing. The inabilityIn order to operate and grow our business, we need to consistently maintain the ability to raise capital on favorable terms could negatively affect the Company’s ability to maintain or expand its businesses.terms. Access to funds is dependent upon factors such as general economic and capital market conditions, regulatory authorizations and policies, the Company’s credit ratings, cash flows from routine operations and the credit ratings of counterparties. After assessing the current operating performance, liquidity and credit ratings of the Company, management believes that the Company will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. BHC 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.


The following table represents the credit ratings, outlook and risk profile of BHC at December 31, 20162019:
Rating AgencySenior Unsecured RatingOutlook
S&P (a)
BBBBBB+Stable
Moody’s (b)
Baa2Stable
Fitch (c)
BBB+NegativeStable
__________
(a)On February 12, 2016,28, 2019, S&P reaffirmed BBBaffirmed our BBB+ rating and maintained a Stable outlook following the closing of the SourceGas Acquisition, reflecting their expectation that management will continue to focus on the core utility operations while maintaining an excellent business risk profile following the acquisition.outlook.
(b)On December 9, 2016,20, 2019, Moody’s issued aaffirmed our Baa2 rating withand maintained a Stable outlook, which reflects the higher debt leverage resulting from the incremental debt used to fund the SourceGas Acquisition.outlook.
(c)On February 12, 2016,August 29, 2019, Fitch affirmed our BBB+ rating and maintained a Negative outlook following the closing of the SourceGas Acquisition, which reflects the initial increased leverage associated with the SourceGas acquisition.Stable outlook.


OurCertain of our fees and our interest paymentsrates under various corporate debtbank credit agreements are based on our credit ratings at all three rating agencies.  If all of our ratings are at the higher credit ratingsame level, or if two of our ratings are the same level and one differs, these fees and interest rates will be based on the ratings that are at the same level.  If all of our ratings are at different levels, these fees and interest rates will be based on the middle level.  Currently, our Fitch and S&P ratings are at the same level, and our Moody’s rating is one level below.  Therefore, if Fitch or Moody’s. If either S&P or Moody’s downgraded our senior unsecured debt, we maywill be required to pay additionalhigher fees and incur higher interest rates under currentthese bank credit agreements.




The following table represents the credit ratings of South Dakota Electric at December 31, 20162019:
Rating AgencySenior Secured Rating
S&P(a)
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 or other trigger events.ratings.


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, 20162019. Actual future obligations may differ materially from these estimated amounts (in thousands):

 Payments Due by Period
Contractual ObligationsTotal
Less Than
1 Year
1-3
Years
4-5
Years
After 5
Years
Long-term debt(a)(b)
$3,243,261
$5,743
$661,485
$214,178
$2,361,855
Unconditional purchase obligations(c)
793,040
163,297
311,290
303,327
15,126
Operating lease obligations(d)
27,280
6,739
12,645
3,083
4,813
Other long-term obligations(e)
69,639
—
—
—
69,639
Employee benefit plans(f)
181,773
16,741
51,074
34,034
79,924
Liability for unrecognized tax benefits in accordance with accounting guidance for uncertain tax positions(g)
3,592
—
3,592
—
—
Notes payable96,600
96,600
—
—
—
Total contractual cash obligations(h)
$4,415,185
$289,120
$1,040,086
$554,622
$2,531,357
 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.
(b)
The following amounts are estimated for interest payments over the next five years based on a mid-year retirement date for long-term debt expiring during the identified period and are not included within the long-term debt balances presented: $126 million in 2017, $126 million in 2018, $121 million in 2019, $113 million in 2020 and $101 million in 2021. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 20162019.
(c)(b)
Unconditional purchase obligations include the energy and capacity costs associated with our PPAs, capacity and certain transmission, gas transportation and storage agreements, and gathering commitments for our Oil and Gas segment.agreements. The energy charges under the PPAs are variable costs, which for purposes of estimating our future obligations, were based on costs incurred during 20162019 and price assumptions using existing prices at December 31, 20162019. Our transmission obligations are based on filed tariffs as of December 31, 20162019. The gathering commitments for our Oil
(c)Includes leases associated with several office and Gas segment are described in Part I, Delivery Commitments, of this Annual Report filed on Form 10-K.operating facilities, communication tower sites, equipment and materials storage.
(d)Includes operating leases
Represents estimated payments for AROs associated with several office buildings, warehouseslong-lived assets primarily related to retirement and call centers, equipmentreclamation of natural gas pipelines, mining sites, wind farms and vehicles.
(e)
Includes estimated asset retirement obligations associated with our Electric Utilities, Gas Utilities, Miningan evaporation pond. See Notes 1 and Oil and Gas segments as discussed in Note 8 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.10-K for additional information.
(f)(e)
Represents both estimated employer contributions to the Defined Benefit Pension Plans and payments to employees forPlan, the Non-Pension Defined Benefit Postretirement Healthcare PlansPlan and the Supplemental Non-Qualified Defined Benefit Plans through the year 2024.
(g)
In the first quarter of 2016, we reached a settlement2029 as discussed in principle with IRS Appeals in regard to the like-kind exchange transaction associated with the gain deferred from the tax treatment related to the IPP Transaction and the Aquila Transaction. A settlement was also reached with respect to research and development credits and deductions. Both issues were the subject of an IRS Appeals process involving the 2007 to 2009 tax years. See Note 1518 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.10-K.
(h)(f)
Amounts in the table exclude: (1) any obligation that may arise from our derivatives, including interest rate swaps and commodity related contracts that have a negative fair value at December 31, 20162019. These amounts have been excluded as it is impractical to reasonably estimate the final amount and/or timing of any associated payments; and (2) a portion of our gas purchases are hedged. These hedges are in place to reduce our customers' underlying exposure to commodity price fluctuations. The impact of these hedges is not included in the above table.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 Utility segment hasUtilities 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, 2016,2019, we are committed to purchase 7.93.7 million MMBtu, 1.8 million MMBtu, 1.3 million MMBtu, 0.63.7 million MMBtu, and 0.41.8 million MMBtu in each of the years from 20172020 to 2021,2022, respectively.


Off-Balance Sheet CommitmentsFinancing 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.


GuaranteesOn 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.


We have entered into various off-balance sheet commitments in the form of guaranteesShort-term borrowings from our Revolving Credit Facility and letters of credit. We provide various guarantees supporting certain of our subsidiaries under specified agreements or transactions. At December 31, 2016, we had outstanding guarantees as indicated in the table below. For more information on these guarantees, see Note 20 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.CP Program.


Future Financing Plans

We hadanticipate the following guaranteesfinancing activities in place2020:

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):
 Outstanding atYear
Nature of GuaranteeDecember 31, 2016Expiring
Indemnification for subsidiary reclamation/surety bonds (a)
$57,105
Ongoing
 $57,105
 
 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.


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.




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)We have guarantees
Includes accruals for property, plant and equipment as disclosed in place for reclamationNote 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 surety bonds forintegrity 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 subsidiaries. The guarantees were entered into inGas Utilities segment increased due to higher programmatic safety, reliability and integrity spending and the normal course35-mile Natural Bridge pipeline project.
(d)Current year capital expenditures at our Power Generation segment increased due to construction of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets.Busch Ranch II.


Letters of Credit

Letters of credit reduce the borrowing capacity available on our corporate Revolving Credit Facility. We had $36 million in letters of credit issued under our Revolving Credit Facility at December 31, 2016.


Market Risk DisclosuresCREDIT 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.


Our activities inThe following table represents the regulatedcredit ratings, outlook and non-regulated energy sectors expose us to a numberrisk profile of risks in the normal operations of our businesses.Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures.

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

Commodity price risk associated with our natural long position of crude oil and natural gas reserves and production, our retail natural gas marketing activities, and our fuel procurement for certain of our gas-fired generation assets; and

Interest rate risk associated with our variable rate debt as described in Notes 6 and 7 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Our exposure to these market risks is affected by a number of 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 and reviewed by the Audit Committee of our Board of Directors. These policies relate to numerous matters including governance, control infrastructure, authorized commodities and trading instruments, prohibited activities and employee conduct. The Executive Risk Committee, which includes senior level executives, meets on a regular basis 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. All of our utilities have GCA provisions that allow them to pass the prudently-incurred cost of gas through to the customer. To the extent that gas 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 natural gas cost we incurred. In South Dakota, Colorado, Wyoming and Montana, we have a mechanism for our regulated electric utilities that serves a purpose similar to the GCAs for our regulated gas utilities. To the extent that our fuel and purchased power costs are higher or lower than the energy cost built into our tariffs, the difference (or a portion thereof) is passed through to the customer. These adjustments are subject to periodic prudence reviews by the state utility commissions.

The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements) expose our utility customers to volatility in natural gas prices. 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 (Loss), or the Consolidated Statements of Comprehensive Income (Loss).

We buy, sell and deliver natural gasBHC 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 2017 through April 2019.

The fair value of our Electric and Gas Utilities derivative contracts at December 31, is summarized below (in thousands)2019:
 2016 2015
Net derivative liabilities$(4,733) $(22,292)
Cash collateral12,722
 27,659
 $7,989
 $5,367
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.


Oil and GasCONTRACTUAL OBLIGATIONS AND OTHER COMMITMENTS


Oil and Gas Exploration and ProductionContractual Obligations


We produce natural gas, NGLs and crude oil through our exploration and production activities. Our natural long positions, or unhedged open positions from these activities, result in commodity price risk and variabilityIn addition to our cash flows.

To mitigate commodity price riskcapital expenditure programs, we have contractual obligations and preserve cash flows, we primarily use exchange traded futures, swaps and options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on the swaps and futures contracts. Our hedging policy allows our natural gas and crude oil production from proven producing reservesother commitments that will need to be hedged for a period up to three yearsfunded in the future. SomeThe 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 our commoditynatural gas under contracts are subjectindexed to master netting agreements, where our asset and liability positions include cash collateral that allow us to settle positive and negative positions.



We have entered into agreements to hedgevarious forward natural gas price curves. In addition, a portion of our estimated 2017gas purchases are purchased under evergreen contracts and 2018 natural gas and crude oil production from the Oil and Gas segment. The hedge agreements in place astherefore, for purposes of this disclosure, are carried out for 60 days. As of December 31, 2016,2019, we are as follows: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.


Natural Gas
 For the Three Months Ended
 March 31,June 30,September 30,December 31,Total Year
2017     
Swaps - MMBtu810,000
810,000
540,000
540,000
2,700,000
Weighted Average Price per MMBtu$3.15
$3.11
$3.04
$3.04
$3.09

Crude Oil
 For the Three Months Ended
 March 31,June 30,September 30,December 31,Total Year
2017     
Swaps - Bbls18,000
18,000
18,000
18,000
72,000
Weighted Average Price per Bbl$50.07
$50.85
$51.55
$52.33
$51.20
      
Calls - Bbls9,000
9,000
9,000
9,000
36,000
Weighted Average Price per Bbl$50.00
$50.00
$50.00
$50.00
$50.00
      
2018     
Swaps - Bbls9,000
9,000
9,000
9,000
36,000
Weighted Average Price per Bbl$49.58
$49.85
$50.12
$50.45
$50.00

The fair value of our Oil and Gas segment’s derivative contracts at December 31 is summarized below (in thousands):

 2016 2015
Net derivative asset (liability)$(1,433) $10,088
Cash collateral (received) paid2,733
 (8,415)
 $1,300
 $1,673

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

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.


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 engageanticipate 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 manage risksthe 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.


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 changesdivesting 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.




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.


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 rates. 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.


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 pay-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations and anticipated debt refinancings. At December 31, 2016, we had $50 million of notional amount pay-fixed interest rate swap that expired in January 2017. This swap was designated as a cash flow hedge in accordance with accounting standards for derivatives and hedges and accordingly its mark-to-market adjustments were recorded in AOCI on the accompanying Consolidated Balance Sheets.

On January 20, 2016, we executed a 10-year, $150 million notional forward starting pay fixed interest rate swap at an all-in rate of 2.09%, and on October 2, 2015, we executed a 10-year, $250 million notional forward starting pay fixed interest rate swap at an all-in rate of 2.29% to hedge the risks of interest rate movement between the hedge dates and the pricing date for long-term debt refinancings occurring in August 2016. On August 19, 2016, we settled these interest rates swaps for a loss of $29 million. The effective portionvarious off-balance sheet commitments in the amountform of $28 million was recognized in AOCIguarantees and is being amortized over the 10-year lifeletters of the associated debt.credit.



Guarantees


Further detailsWe provide various guarantees supporting certain of the swapour subsidiaries under specified agreements are set forth in or transactions. For more information on these guarantees, see Note 920 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.


On 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, 20162019 and December 31, 2015, our interest rate swaps2018, we had total regulatory assets of $271 million and related balances were as follows (dollars in thousands):$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.


Goodwill
 Notional Weighted Average Fixed Interest Rate Maximum Terms in Years Non- current Assets Current Liabilities, net of Cash Collateral Non- current Liabilities Pre-tax AOCI Pre-tax Unrealized Gain (Loss)
December 31, 2016               
                
Interest rate swaps$50,000
 4.94% 0.08 years $—
 $90
 $—
 $(90) $—
 $50,000
     $—
 $90
 $—
 $(90) $—
                
December 31, 2015               
                
Interest rate swaps$250,000
 2.29% 1.33 $3,441
 $—
 $—
 $3,441
 $—
Interest rate swaps75,000
 4.97% 1.08 years —
 2,835
 156
 (2,991) —
 $325,000
     $3,441
 $2,835
 $156
 $450
 $—


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.   
Based
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, 2016 market interest2019, 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 balances,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 loss of approximately $2.9 million would be realizeddecrease in the discount rate and reported in pre-tax earnings during the next 12 months. This includes the $28 million loss currently deferred in AOCI. Estimated and realized losses will likely change during the next twelve months as market interest rates change.lower expected return on assets.

The table below presents principal amountseffect of hypothetical changes to selected assumptions on the pension and related weighted average interest rates by yearother postretirement benefit plans would be as follows in thousands of maturity for our long-term debt obligations, including current maturities (dollars in thousands):dollars:
 20172018201920202021ThereafterTotal
Long-term debt       
Fixed rate(a)
$5,743
$5,743
$255,742
$205,742
$1,436
$2,349,000
$2,823,406
Average interest rate (b)
2.32%2.32%2.5%5.78%2.32%4.29%4.23%
        
Variable rate$—
$—
$400,000
$—
$7,000
$12,855
$419,855
Average interest rate (b)
—%—%1.74%—%0.72%0.76%1.7%
        
Total long-term debt$5,743
$5,743
$655,742
$205,742
$8,436
$2,361,855
$3,243,261
Average interest rate (b)
2.32%2.32%2.04%5.78%0.99%4.27%3.9%
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)/3,09590/116
Expected return on assets +/- 0.5N/A(39)/39
___________________________________________________
(a)Excludes unamortized premium or discount.Projected benefit obligation (PBO) for the pension plan and accumulated postretirement benefit obligation (APBO) for OPEB plans.
(b)The averageImpact on service cost, interest rates do not include the effectcost and amortization of interest rate swaps.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.

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


CreditOur credit risk isdisclosures are detailed in Note 9 of the risk of financial loss resulting from non-performance of contractual obligations by a counterparty. 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.


We seek to mitigate our credit risk by conducting a majority of our business with investment grade companies, setting tenor and credit limits commensurate with counterparty financial strength, obtaining netting agreements and securing our 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 our review of their current credit information. We maintain a provision for estimated credit losses based upon our historical experience and any specific customer collection issue that we have identified. While most credit losses have historically been within our expectations and provisions established, we cannot provide assurance that we will continue to experience the same credit loss rates that we have in the past, or that an investment grade counterparty will not default sometime in the future.

At December 31, 2016, our credit exposure included a $1.1 million exposure to a non-investment grade rural electric utility cooperative. The remainder of our credit exposure was concentrated primarily among retail utility customers, investment grade companies, municipal cooperatives and federal agencies.




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 20162019 or pending adoption.






ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


INDEX TO CONSOLIDATED FINANCIAL STATEMENTS




Management’s Report on Internal Controls Over Financial Reporting
12373
Reports of Independent Registered Public Accounting Firm
74
  
Reports of Independent Registered Public Accounting Firm
124
Consolidated Statements of Income (Loss) for
77
Consolidated Statements of Comprehensive Income
78
Consolidated Balance Sheets
79
Consolidated Statements of Cash Flows
81
Consolidated Statements of Equity
82
Notes to the three years ended December 31, 2016Consolidated Financial Statements
83
Note 1. Business Description and Significant Accounting Policies
83
Note 2. Revenue
92
Note 3. Property, Plant and Equipment
94
Note 4. Jointly Owned Facilities
96
Note 5. Business Segments
97
Note 6. Long-term Debt
102
Note 7. Notes Payable
104
Note 8. Asset Retirement Obligations
105
Note 9. Risk Management Activities
106
Note 10. Fair Value Measurements
109
Note 11. Fair Value of Financial Instruments
112
Note 12. Equity
112
Note 13. Regulatory Matters
116
Note 14. Leases
120
Note 15. Income Taxes
123
Note 16. Other Comprehensive Income
126
Consolidated Statements of Comprehensive Income (Loss) for the three years ended December 31, 2016
127Note 17. Supplemental Cash Flow Information
Consolidated Balance Sheets as of December 31, 2016 and 2015
128
Consolidated Statements of Cash Flows for the three years ended December 31, 2016
Note 18. Employee Benefit Plans
130128
Consolidated Statements of Equity for the three years ended December 31, 2016
Note 19. Commitments and Contingencies
131135
Note 20. Guarantees
139
Notes to Consolidated Financial Statements
Note 21. Discontinued Operations
132140
Note 22. Quarterly Historical Data (unaudited)
141







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, 20162019, 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, 20162019.

Our assessment of the effectiveness of our internal controls over financial reporting as of December 31, 2016 excluded the assets and operations acquired on February 12, 2016 in the SourceGas Transaction. SourceGas’ assets and operations constitute approximately 20% of total assets and 22% of sales (excluding SourceGas’ goodwill and intangible assets which were integrated into the Company’s systems and control environment) of the consolidated financial statement amounts as of and for the year ended December 31, 2016. Such exclusion was in accordance with SEC guidance that an assessment of a recently acquired business may be omitted in management’s report on internal control over financial reporting, provided the acquisition took place within twelve months of management’s evaluation.


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, 2016.2019. Deloitte & Touche LLP's report on Black Hills Corporation's internal control over financial reporting is included herein.

Black Hills Corporation




REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Black Hills Corporation
Rapid City, South Dakota

We have audited the accompanying consolidated balance sheets of Black Hills Corporation and subsidiaries (the “Company”) as of December 31, 2016 and 2015, and the related consolidated statements of income (loss), comprehensive income (loss), equity, and cash flows for each of the three years in the period ended December 31, 2016. Our audits also included the financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedule based on our audits.


We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.


In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Black Hills Corporation and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2017 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota
February 24, 2017





REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the shareholders and the Board of Directors and Stockholders of
Black Hills Corporation
Rapid City,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).

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.


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

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Black Hills Corporation and subsidiaries (the “Company”"Company") as of December 31, 2016,2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. As describedCommission (COSO). In our opinion, the Company maintained, in Management’s Report on Internal Control over Financial Reporting, management excluded from its assessment theall material respects, effective internal control over financial reporting at Black Hills Gas Holdings, LLC, formerly known as SourceGas Holdings, LLC (“SourceGas”), which was acquiredof December 31, 2019, based on February 12, 2016, and whose assets and operations constitute approximately 20%criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of total assets and 22% of sales (excluding SourceGas’ goodwill and intangibles which were integrated into the Company’s systems and control environment)Public Company Accounting Oversight Board (United States) (PCAOB), of the consolidated financial statementsand financial statement amountsschedule of the Company as of and for the year ended December 31, 2016. Accordingly,2019, and our audit did not include the internal control overreport dated February 14, 2020 expressed an unqualified opinion on those consolidated financial reporting at SourceGas. statements and financial statement schedule.
Basis for Opinion
The Company’sCompany's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting.Reporting. Our responsibility is to express an opinion on the Company’sCompany's internal control over financial reporting based on our audit.

We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).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 by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel 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 theits inherent limitations, of internal control over financial reporting including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be preventedprevent or detected on a timely basis.detect misstatements. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2016, of the Company and our report dated February 24, 2017, expressed an unqualified opinion on those consolidated financial statements and financial statement schedule.


/s/ DELOITTE & TOUCHE LLP


Minneapolis, Minnesota
February 24, 201714, 2020







BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
Year endedDecember 31, 2016December 31, 2015December 31, 2014December 31, 2019December 31, 2018December 31, 2017
(in thousands, except per share amounts)(in thousands, except per share amounts)
  
Revenue$1,572,974
$1,304,605
$1,393,570
$1,734,900
$1,754,268
$1,680,266
  
Operating expenses:  
Fuel, purchased power and cost of natural gas sold499,132
456,887
581,782
570,829
625,610
563,288
Operations and maintenance456,399
361,109
359,095
495,994
481,706
454,605
Depreciation, depletion and amortization189,043
155,370
144,745
209,120
196,328
188,246
Impairment of long-lived assets106,957
249,608
—
Taxes - property, production and severance48,522
44,353
43,580
Taxes - property and production52,915
51,746
51,578
Other operating expenses50,335
7,483
500
—
1,841
5,813
Total operating expenses1,350,388
1,274,810
1,129,702
1,328,858
1,357,231
1,263,530
  
Operating income222,586
29,795
263,868
406,042
397,037
416,736
  
Other income (expense):  
Interest charges -  
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts)(139,590)(86,278)(73,017)
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 - borrowed2,981
1,250
1,075
6,556
2,104
2,415
Capitalized interest1,197
1,309
982
Interest income1,429
1,621
1,925
1,632
1,641
1,016
Allowance for funds used during construction - equity3,270
897
994
472
619
2,321
Other expense(609)(372)(377)
Other income1,842
2,256
2,065
Impairment of investment(19,741)—
—
Other income (expense), net(6,212)(1,799)(213)
Total other income (expense)(129,480)(79,317)(66,353)(163,140)(141,155)(134,994)
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes93,106
(49,522)197,515
Equity in earnings (loss) of unconsolidated subsidiaries—
(344)(1)
Impairment of equity investments—
(4,405)—
Income before income taxes242,902
255,882
281,742
Income tax benefit (expense)(10,475)22,160
(66,625)(29,580)23,667
(73,367)
Net income (loss)82,631
(32,111)130,889
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(9,661)—
—
(14,012)(14,220)(14,242)
Net income (loss) available for common stock$72,970
$(32,111)$130,889
Net income available for common stock$199,310
$258,442
$177,034
  
Earnings (loss) per share of common stock: 
Earnings (loss) per share, Basic$1.41
$(0.71)$2.95
Earnings (loss) per share, Diluted$1.37
$(0.71)$2.93
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:  
Basic51,922
45,288
44,394
60,662
54,420
53,221
Diluted53,271
45,288
44,598
60,798
55,486
55,120


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


BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)


Year endedDecember 31, 2016December 31, 2015December 31, 2014
 (in thousands)
Net income (loss)$82,631
$(32,111)$130,889
    
Other comprehensive income (loss), net of tax:   
Benefit plan liability adjustments - net gain (loss) (net of tax of $757, $(1,375) and $5,004, respectively)(1,738)2,657
(10,590)
Benefit plan liability adjustments - prior service (costs) (net of tax of $107, $0 and $(17), respectively)(247)—
237
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(600), $(972) and $(348), respectively)1,378
1,850
646
Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $67, $88 and $76, respectively)(154)(150)(141)
Derivative instruments designated as cash flow hedges:   
Net unrealized gains (losses) on interest rate swaps (net of tax of $10,920, $(598) and $186, respectively)(20,302)2,290
(350)
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(1,365), $(1,348) and $(1,356), respectively)2,534
2,299
2,313
Net unrealized gains (losses) on commodity derivatives (net of tax of $212, $(3,898) and $(5,425), respectively)(361)5,884
9,256
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $4,067, $5,619 and $(988), respectively)(6,938)(8,841)1,007
Other comprehensive income (loss), net of tax(25,828)5,989
2,378
    
Comprehensive income (loss)56,803
(26,122)133,267
Less: comprehensive income attributable to non-controlling interest(9,661)—
—
Comprehensive income (loss) available for common stock$47,142
$(26,122)$133,267
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 16for additional disclosures related to Comprehensive Income.


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




BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS

As ofAs of
December 31, 2016December 31, 2015December 31, 2019December 31, 2018
(in thousands)(in thousands)
ASSETS  
Current assets:  
Cash and cash equivalents$13,580
$440,861
$9,777
$20,776
Restricted cash and equivalents2,274
1,697
3,881
3,369
Accounts receivable, net263,289
147,486
255,805
269,153
Materials, supplies and fuel107,210
86,943
117,172
117,299
Derivative assets, current4,138
—
342
1,500
Income tax receivable, net—
368
16,446
12,978
Regulatory assets, current49,260
57,359
43,282
48,776
Other current assets27,063
71,763
26,479
29,982
Total current assets466,814
806,477
473,184
503,833
  
Investments12,561
11,985
21,929
41,013
    
Property, plant and equipment6,412,223
4,976,778
6,784,679
6,000,015
Less accumulated depreciation and depletion(1,943,234)(1,717,684)(1,281,493)(1,145,136)
Total property, plant and equipment, net4,468,989
3,259,094
5,503,186
4,854,879
  
Other assets:  
Goodwill1,299,454
359,759
1,299,454
1,299,454
Intangible assets, net8,392
3,380
13,266
14,337
Derivative assets, non-current222
3,441
Regulatory assets, non-current246,882
175,125
228,062
235,459
Other assets, non-current12,130
7,382
19,376
14,352
Total other assets, non-current1,567,080
549,087
1,560,158
1,563,602
TOTAL ASSETS$6,515,444
$4,626,643
$7,558,457
$6,963,327


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






BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
(Continued)

As ofAs of
December 31, 2016December 31, 2015December 31, 2019December 31, 2018
(in thousands, except share amounts)(in thousands, except share amounts)
 
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND EQUITY 
LIABILITIES AND EQUITY 
Current liabilities:  
Accounts payable$153,477
$89,794
$193,523
$210,609
Accrued liabilities244,034
232,061
226,767
215,501
Derivative liabilities, current2,459
2,835
2,254
947
Accrued income tax, net12,552
—
Regulatory liabilities, current13,067
4,865
33,507
29,810
Notes payable96,600
76,800
349,500
185,620
Current maturities of long-term debt5,743
—
5,743
5,743
Total current liabilities527,932
406,355
811,294
648,230
  
Long-term debt, net of current maturities3,211,189
1,853,682
3,140,096
2,950,835
  
Deferred credits and other liabilities:  
Deferred income tax liabilities, net, non-current535,606
450,579
Derivative liabilities, non-current274
156
Deferred income tax liabilities, net360,719
311,331
Regulatory liabilities, non-current193,689
148,176
503,145
510,984
Benefit plan liabilities173,682
146,459
154,472
145,147
Other deferred credits and other liabilities138,643
155,369
124,662
109,377
Total deferred credits and other liabilities1,041,894
900,739
1,142,998
1,076,839
  
Commitments and contingencies (See Notes 6, 7, 8, 9, 14, 18, 19, and 20)

  
Redeemable noncontrolling interest4,295
—
 
Equity:  
Stockholders’ equity -  
Common stock $1 par value; 100,000,000 shares authorized; issued: 53,397,467 and 51,231,861 shares, respectively53,397
51,232
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 capital1,138,982
953,044
1,552,788
1,450,569
Retained earnings457,934
472,534
778,776
700,396
Treasury stock at cost - 15,258 and 39,720 shares, respectively(791)(1,888)
Treasury stock at cost - 3,956 and 44,253, respectively(267)(2,510)
Accumulated other comprehensive income (loss)(34,883)(9,055)(30,655)(26,916)
Total stockholders’ equity1,614,639
1,465,867
2,362,123
2,181,588
Noncontrolling interest115,495
—
101,946
105,835
Total equity1,730,134
1,465,867
2,464,069
2,287,423
  
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND TOTAL EQUITY$6,515,444
$4,626,643
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.




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

Year endedDecember 31, 2016December 31, 2015December 31, 2014
 (in thousands)
Operating activities:   
Net income (loss)$82,631
$(32,111)$130,889
Adjustments to reconcile net income (loss) to net cash provided by operating activities:   
Depreciation, depletion and amortization189,043
155,370
144,745
Deferred financing cost amortization6,180
6,364
2,127
Impairment of long-lived assets and equity method investments106,957
254,013
—
Stock compensation10,885
4,076
9,329
Deferred income taxes36,217
(26,028)70,232
Employee benefit plans14,291
20,616
14,814
Other adjustments, net(5,518)(4,872)14,415
Change in certain operating assets and liabilities:   
Materials, supplies and fuel1,099
7,197
(4,563)
Accounts receivable, unbilled revenues and other current assets(28,414)40,125
(18,684)
Accounts payable and other current liabilities(40,195)(4,779)7,887
Regulatory assets3,614
21,883
(38,774)
Regulatory liabilities(14,082)1,675
(7,633)
Contributions to defined benefit pension plans(14,200)(10,200)(10,200)
Interest rate swap settlement(28,820)—
—
Other operating activities, net775
(9,034)733
Net cash provided by operating activities320,463
424,295
315,317
    
Investing activities:   
Property, plant and equipment additions(474,783)(455,481)(398,494)
Acquisition of net assets, net of long-term debt assumed(1,124,238)(21,970)—
Proceeds from sale of assets11,418
—
—
Other investing activities(1,139)1,062
(2,653)
Net cash provided by (used in) investing activities(1,588,742)(476,389)(401,147)
    
Financing activities:   
Dividends paid on common stock(87,570)(72,604)(69,636)
Common stock issued121,619
248,759
3,251
Short-term borrowings - issuances425,400
397,310
396,250
Short-term borrowings - repayments(405,600)(395,510)(403,750)
Long-term debt - issuance1,767,608
300,000
160,000
Long-term debt - repayments(1,164,308)(275,000)(12,200)
Sale of noncontrolling interest216,370
—
—
Distributions to noncontrolling interests(9,561)—
—
Equity units - issuance—
290,030
—
Other financing activities(22,960)(9,283)17,152
Net cash provided by (used in) financing activities840,998
483,702
91,067
    
Net change in cash and cash equivalents(427,281)431,608
5,237
    
Cash and cash equivalents beginning of year440,861
9,253
4,016
Cash and cash equivalents end of year$13,580
$440,861
$9,253



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.


BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY


Common StockTreasury Stock Common StockTreasury Stock 
(in thousands except share amounts)SharesValueSharesValueAdditional Paid in CapitalRetained EarningsAOCINon controlling InterestTotalSharesValueSharesValueAdditional Paid in CapitalRetained EarningsAOCINon controlling InterestTotal
Balance at December 31, 201344,550,239
$44,550
50,877
$(1,968)$742,344
$515,996
$(17,422)$—
$1,283,500
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—
—
—
—
—
130,889
—
—
130,889
—
—
—
—
—
177,034
—
14,242
191,276
Other comprehensive income (loss), net of tax—
—
—
—
—
—
2,378
—
2,378
—
—
—
—
—
—
681
—
681
Reclassification of certain tax effects from AOCI—
—
—
—
—
7,000
(7,000)—
—
Dividends on common stock—
—
—
—
—
(69,636)—
—
(69,636)—
—
—
—
—
(96,744)—
—
(96,744)
Share-based compensation111,507
112
(8,651)93
4,210
—
—
—
4,415
134,266
134
23,806
(1,515)8,948
—
—
—
7,567
Tax effect of share-based compensation—
—
—
—
(499)—
—
—
(499)—
—
—
—
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 plan52,326
52
—
—
2,826
—
—
—
2,878
4,061
4
—
—
216
—
—
—
220
Other stock transactions—
—
—
—
(41)—
—
—
(41)—
—
—
—
154
(72)—
—
82
Balance at December 31, 201444,714,072
$44,714
42,226
$(1,875)$748,840
$577,249
$(15,044)$—
$1,353,884
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—
—
—
—
—
(32,111)—
—
(32,111)—
—
—
—
—
199,310
—
14,012
213,322
Other comprehensive income (loss), net of tax—
—
—
—
—
—
5,989
—
5,989
—
—
—
—
—
—
(3,739)—
(3,739)
Dividends on common stock—
—
—
—
—
(72,604)—
—
(72,604)—
—
—
—
—
(124,647)—
—
(124,647)
Share-based compensation126,765
127
(2,506)(13)4,126
—
—
—
4,240
103,759
104
(40,297)2,243
4,729
—
—
—
7,076
Issuance of common stock6,325,000
6,325
—
—
248,256
—
—
—
254,581
1,328,332
1,328
—
—
98,672
—
—
—
100,000
Issuance costs—
—
—
—
(17,926)—
—
—
(17,926)—
—
—
—
(1,182)—
—
—
(1,182)
Premium on Equity Units—
—
—
—
(33,118)—
—
—
(33,118)
Dividend reinvestment and stock purchase plan66,024
66
—
—
2,891
—
—
—
2,957
Other stock transactions—
—
—
—
(25)—
—
—
(25)
Balance at December 31, 201551,231,861
$51,232
39,720
$(1,888)$953,044
$472,534
$(9,055)$—
$1,465,867
Net income (loss) available for common stock—
—
—
—
—
72,970
—
9,661
82,631
Other comprehensive income (loss), net of tax—
—
—
—
—
—
(25,828)—
(25,828)
Dividends on common stock—
—
—
—
—
(87,570)—
—
(87,570)
Share-based compensation145,634
146
(16,165)668
4,665
—
—
—
5,479
Issuance of common stock1,968,738
1,969
—
—
118,021
—
—
—
119,990
Issuance costs—
—
—
—
(1,566)—
—
—
(1,566)
Dividend reinvestment and stock purchase plan51,234
50
—
—
2,933
—
—
—
2,983
Other stock transactions—
—
(8,297)429
47
—
—
—
476
Sale of noncontrolling interest—
—
—
—
61,838
—
—
115,395
177,233
Other—
—
—
—
—
327
—
—
327
Implementation of ASU 2016-02 Leases—
—
—
—
—
3,390
—
—
3,390
Distributions to noncontrolling interest—
—
—
—
—
—
—
(9,561)(9,561)—
—
—
—
—
—
—
(17,901)(17,901)
Balance at December 31, 201653,397,467
$53,397
15,258
$(791)$1,138,982
$457,934
$(34,883)$115,495
$1,730,134
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 $1.682.05, $1.621.93 and $1.561.81 for the years ended December 31, 20162019, 20152018 and 20142017, respectively.


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








BLACK HILLS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
December 31, 20162019, 20152018 and 20142017


(1)
BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES


Business Description


Black Hills Corporation is a customer-focused, growth-oriented vertically-integrated utility company headquartered in Rapid City, South Dakota. We are a holding company that, through our subsidiaries, conducts our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation Mining, and OilMining. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Gas.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. Prior to 2016, our segments were reported within two business groups, our Utilities Group, containing the Electric Utilities and Gas Utilities segments, and our Non-regulated Energy Group, containing the Power Generation, Mining and Oil and Gas segments. We have continued to report our operations consistently through our reportable segments. However, we will no longer separate the segments by business group.


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


AllMost of our non-utility business segments support our electric utilities, other than the Oil and Gas segment.Electric Utilities. Our Power Generation segment, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in WyomingColorado, Iowa and Colorado.Wyoming. Our Mining segment, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyoming. Our Oil and Gas segment, which is conducted through BHEP and its subsidiaries, engages in crude oil and natural gas exploration and production activities in Colorado, Louisiana, Montana, Oklahoma, New Mexico, North Dakota, Wyoming, Texas and California. Our Oil and Gas segment’s focus is on cost of service gas programs. We are divesting non-core oil and gas assets while retaining those best suited for a cost of service gas program and have refocused our professional staff on assisting our utilities with the implementation of a Cost of Service Gas Program.

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 following changes have been made to our Consolidated Statements of Income (Loss) to reflect combined revenueOil and combined operationsGas segment assets and maintenance expenses, rather than by business groupliabilities were classified as previously reported,held for the twelve months ended December 31, 2015sale and December 31, 2014 respectively:
 Year Ended December 31, 2015 Year Ended December 31, 2014
(in thousands)As Previously ReportedPresentation ReclassificationAs Currently Reported As Previously ReportedPresentation ReclassificationAs Currently Reported
Revenue:       
Utilities$1,219,526
$(1,219,526)$—
 $1,300,969
$(1,300,969)$—
Non-regulated energy$85,079
$(85,079)$—
 $92,601
$(92,601)$—
Revenue$—
$1,304,605
$1,304,605
 $—
$1,393,570
$1,393,570
        
Operating Expenses:       
Utilities - operations and maintenance$272,407
$(272,407)$—
 $270,954
$(270,954)$—
Non-regulated energy operations and maintenance$88,702
$(88,702)$—
 $88,141
$(88,141)$—
Operations and maintenance$—
$361,109
$361,109
 $—
$359,095
$359,095

This presentation reclassification did not impact our consolidated financial position,the results of operations or cash flows.



Segment Reporting Transition of Cheyenne Light’s Natural Gas Distribution

Effective January 1, 2016, the natural gaswere shown in income (loss) from discontinued operations, of Cheyenne Light have been included in our Gas Utilities Segment. Through December 31, 2015, Cheyenne Light’s natural gas operations were included in our Electric Utilities Segment as these natural gas operations were consolidated within Cheyenne Light since its acquisition. This change is a result of our business segment reorganization to, among other things, integrate all regulated natural gas operations, including the SourceGas Acquisition, into our Gas Utilities Segmentthan certain general and administrative costs and interest expense which is led by the Group Vice President, Natural Gas Utilities. Likewise, all regulated electric utility operations, including Cheyenne Light’s electric utility operations, are reported in our Electric Utilities Segment, which is led by the Group Vice President, Electric Utilities. The prior periods have been reclassified to reflect this change in presentation between the Electric Utilities and Gas Utilities segments. See Note 5 for Revenues and Net Income amounts reclassified from the Electric Utilities segment to the Gas Utilities segment for the twelve months ended December 31, 2015 and December 31, 2014; and Segment Assets reclassified from the Electric Utilities segment to the Gas Utilities segment for the twelve months ended December 31, 2015. This segment reclassification did not impact our consolidated financial position, results ofmeet the criteria for income (loss) from discontinued operations in 2018 or cash flows.
Revisions

Certain revisions have been made to prior years’ financial information to conform to2017. At the current year presentation.
The Company revised its presentation of cashtime the assets were classified as held for sale, depreciation, depletion and book overdrafts.  For accounts withamortization expenses were no longer recorded. Unless otherwise noted, the same financial institution where there is a banking arrangement that clears payments with balancesamounts presented in other bank accounts, book overdrafts are presented on a combined basis by bank as cash and cash equivalents. Prior year amounts were corrected to conform with the current year presentation, which decreased cash and cash equivalents and accounts payable by $16 million, $12 million and $3.8 million as of December 31, 2015, December 31, 2014 and December 31, 2013, respectively, and decreased net cash flows provided by operations by $3.7 million and $8.1 million for the years ended December 31, 2015 and 2014 respectively. We assessed the materiality of these changes, taking into account quantitative and qualitative factors, and determined them to be immaterialaccompanying notes to the consolidated balance sheet as of December 31, 2015 andfinancial statements relate to the consolidated statements of cash flows for the years ended December 31, 2015 and 2014. There is no impact to the Consolidated Statements of Income (Loss), the Consolidated Statements of Comprehensive Income (Loss) or the Consolidated Statements of Equity, for any period reported.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. Investment in non-controlled entities over which we have the ability to exercise significant influence over operating and financial policies are accounted for using the equity method of accounting. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for our proportionate share of earnings and losses and distributions. Under this method, a proportionate share of pretax income is recorded as Equity earnings (loss) of unconsolidated subsidiaries. All inter-companyintercompany balances and transactions have been eliminated in consolidation. For additional information on inter-companyintercompany revenues, see Note 5.


Our Consolidated Statements of Income (Loss) include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our working interests in oil and gas properties and for our ownership interest in any jointly-owned electric utility generating facility, wind project or transmission tie and the BHEP gas processing plant.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 so, 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.



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 VIEsVIE’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 itour interest qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE’s economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement. Black Hills Colorado IPP is a VIE. See additional information in Note 12.12.


Cash and Cash Equivalents and Restricted Cash


We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Restricted Cash and Equivalents

cash equivalents. We maintain cash accounts for various specified purposes. Therefore, we classify these amountspurposes, which are classified as restricted cash.


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 Mining, OilPower Generation and Gas, and Power GenerationMining business segments consists of amounts due from sales of coal, crude oil and natural gas, electric energy and capacity.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.



Following is a summary of accounts receivable as of December 31 (in thousands):
2016Accounts Receivable, TradeUnbilled RevenueLess Allowance for Doubtful AccountsAccounts Receivable, net
2019Accounts Receivable, TradeUnbilled RevenueLess Allowance for Doubtful AccountsAccounts Receivable, net
Electric Utilities$41,730
$36,463
$(353)$77,840
$41,428
$33,886
$(592)$74,722
Gas Utilities88,168
88,329
(2,026)174,471
97,607
79,616
(1,683)175,540
Power Generation1,420
—
—
1,420
2,164
—
—
2,164
Mining3,352
—
—
3,352
2,277
—
—
2,277
Oil and Gas3,991
—
(13)3,978
Corporate2,228
—
—
2,228
1,271
—
(169)1,102
Total$140,889
$124,792
$(2,392)$263,289
$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):
2015Accounts Receivable, TradeUnbilled RevenueLess Allowance for Doubtful AccountsAccounts Receivable, net
Electric Utilities (a)
$41,679
$35,874
$(727)$76,826
Gas Utilities (a)
30,330
32,869
(1,001)62,198
Power Generation1,187
—
—
1,187
Mining2,760
—
—
2,760
Oil and Gas3,502
—
(13)3,489
Corporate1,026
—
—
1,026
Total$80,484
$68,743
$(1,741)$147,486
  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
________________
(a)Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility accounts receivable has been reclassified from the Electric Utilities segment to the Gas Utilities segment. Accounts receivable of $6.8 million as of December 31, 2015, previously reported in the Electric Utilities segment is now presented in the Gas Utilities segment.


Revenue Recognition

Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price and delivery has occurred or services have been rendered. Sales and franchise taxes collected from our customers is recorded on a net basis (excluded from Revenue).

Utility revenues are based on authorized rates approved by the state regulatory agencies and the FERC. Revenues related to the sale, transmission and distribution of energy, and delivery of service are generally recorded when service is rendered or energy is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets.

For long-term non-regulated power sales agreements, revenue is recognized either in accordance with accounting standards for revenue recognition, or in accordance with accounting standards for leases, as appropriate. Under accounting standards for revenue recognition, revenue is generally recognized as the lesser of the amount billed or the average rate expected over the life of the agreement.

Natural gas and crude oil sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectibility of the revenue is reasonably assured. Our Oil and Gas segment records its share of revenues based on production volumes and contracted sales prices. The sales price for natural gas, crude oil, condensate and NGLs is adjusted for transportation costs and other related deductions when applicable. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment.



Materials, Supplies and Fuel


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

 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

 December 31, 2016December 31, 2015
Materials and supplies$68,456
$55,726
Fuel - Electric Utilities3,667
5,567
Natural gas in storage35,087
25,650
Total materials, supplies and fuel$107,210
$86,943


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 using weighted-average cost.at the lower-of-cost or net realizable value. The value of our naturalNatural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas.


Investments

In February 2018, we made a contribution of $28 million of assets in exchange for equity securities in a privately held oil and gas company as we divested of our Oil and Gas segment. The carrying value of our investment in the equity securities was recorded at cost. We review this investment on a periodic basis to determine whether a significant event or change in circumstances has occurred that may have an adverse effect on the value of the investment.

During the third quarter of 2019, we assessed our investment for impairment as a result of a deterioration in earnings performance of the privately held oil and gas company and an adverse change in future natural gas prices. 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.

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 (in thousands):

 December 31, 2016December 31, 2015
Accrued employee compensation, benefits and withholdings$56,926
$43,342
Accrued property taxes40,004
32,393
Accrued payments related to litigation expenses and settlements—
38,750
Customer deposits and prepayments51,628
53,496
Accrued interest and contract adjustment payments45,503
25,762
Other (none of which is individually significant)49,973
38,318
Total accrued liabilities$244,034
$232,061

Property, Plant and Equipment

Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets. We also classify our base or “cushion gas” as property, plant and equipment. Cushion gas is the portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability.

The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs associated with non-legal obligations related to our regulated properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other assets, except for crude oil and natural gas properties as described below, result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred.

Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the applicable estimated service life of the various class of property. Capitalized coal mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-utility power plant components, depreciation is computed on a unit-of-production methodology based on plant hours run.



Oil and Gas Operations

We account for our oil and gas activities under the full cost method. Under the full cost method, costs related to acquisition, exploration and estimated future expenditures to be incurred in developing proved reserves as well as estimated reclamation and abandonment costs, net of estimated salvage values are capitalized. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonment of properties, are typically treated as adjustments to the cost of the properties with no gain or loss recognized.

Costs directly associated with unproved properties and major development projects, if any, are excluded from the costs to be amortized. These excluded costs are subsequently included within the costs to be amortized when it is determined whether or not proved reserves can be assigned to the properties. The properties excluded from the costs to be amortized are assessed for impairment at least annually and any amount of impairment is added to the costs to be amortized. These costs are generally expected to be included in costs to be amortized within the term of the underlying lease agreement, which varies in length.

Under the full cost method, net capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test which limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC, plus the lower of cost or market value of unevaluated properties. Future net cash flows are estimated based on SEC-defined end-of-period commodity prices adjusted for contracted price changes and held constant for the life of the reserves. An average price is calculated using the price at the first day of each month for each of the preceding 12 months. If the net capitalized costs exceed the full cost “ceiling” at period end, a permanent non-cash write-down would be charged to earnings in that period. As a result of lower natural gas prices, we recorded non-cash ceiling test impairments of oil and gas long-lived assets included in the Oil and Gas segment in 2016 and 2015. No ceiling test write-down was recorded in 2014. See Note 13 for additional information.

The SEC definition of “reliable technology” permits the use of any reliable technology to establish reserve volumes in addition to those established by production and flow test data. This definition allows, but does not require us, to calculate PUDs to be booked at more than one location away from a producing well. We have no PUDs at December 31 2016. See information on our oil and gas drilling activities in Note 21.

Companies are permitted but not required to disclose probable and possible reserves. We have elected not to report these additional reserve categories.

Goodwill and Intangible Assets

Goodwill and intangible assets with indefinite lives are not amortized, but the carrying values are reviewed upon an indicator of impairment or at least annually. Intangible assets with a finite life continue to be amortized over their estimated useful lives.

We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired.  Beginning in 2016, we changed our annual goodwill impairment testing date from November 30 to October 1 to better align the testing date with our financial planning process.   We believe that the change in the date of the annual goodwill impairment test from November 30 to October 1 is not a material change in the application of an accounting principle.  The new and old testing dates are close in proximity; both are in the fourth quarter of the year, and our current testing date is within ten months of the most recent impairment testing. We would not expect a materially different outcome as a result of testing on October 1 as compared to November 30. The change in assessment date does not have a material effect on the financial statements.

We estimated the fair value of the goodwill using discounted cash flow methodology, EBITDA multiple method and an analysis of comparable transactions. This analysis required the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, timing and level of success in regulatory rate proceedings, the cost of debt and equity capital and long-term earnings and merger multiples for comparable companies.

The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results. See Note 5 for additional business segment information.



Goodwill at our Electric utilities primarily arose from Colorado Electric, acquired in the Aquila acquisition, which allocated approximately $246 million, or 72% of the transaction to Colorado Electric. Goodwill at our Gas Utilities is primarily from the SourceGas Acquisition, which was allocated entirely to the Gas Utilities adding $940 million in goodwill and the Aquila Transaction, which allocated approximately $94 million, or 28% of the transaction, to the Gas Utilities.

We believe that the goodwill reflects the inherent value of the relatively stable, long-lived cash flows of the regulated electric and gas utility businesses, considering the regulatory environment, and the long-lived cash flow and rate base growth opportunities at our utilities. Goodwill balances were as follows (in thousands):
 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

 
Electric Utilities (a)
Gas Utilities (a)
Power GenerationTotal
Ending balance at December 31, 2014$248,479
$96,152
$8,765
$353,396
Additions (b)
—
6,363
—
6,363
Ending balance at December 31, 2015$248,479
$102,515
$8,765
$359,759
Additions (c)
—
939,695
—
939,695
Ending balance at December 31, 2016$248,479
$1,042,210
$8,765
$1,299,454
_________________
(a)Goodwill of $2.0 million and $6.3 million for December 31, 2014 and December 31, 2015, respectively, is now presented in the Gas Utilities segment as a result of the inclusion of Cheyenne Light’s Gas operations in the Gas Utilities segment, previously reported in the Electric Utilities segment. See above in this Note 1 for additional details.
(b)Goodwill was recorded on the July 1, 2015 acquisition of Wyoming natural gas utility Energy West Wyoming, Inc., and natural gas pipeline assets from Energy West Development, Inc.
(c)Represents goodwill recorded with the acquisition of SourceGas. See Note 2 for more information.

Our intangible assets represent easements, rights-of-way, customer listings, and trademarks and are amortized using a straight-line method based on estimated useful lives. The finite lived intangible assets are currently being amortized from 2 years up to 40 years. Changes to intangible assets for the years ended December 31, were as follows (in thousands):
 201620152014
Intangible assets, net, beginning balance$3,380
$3,176
$3,397
Additions5,522
434
—
Amortization expense (a)
(510)(230)(221)
Intangible assets, net, ending balance$8,392
$3,380
$3,176
_________________
(a)Amortization expense for existing intangible assets is expected to be $0.8 million for each year of the next five years.


Asset Retirement Obligations


Accounting standards for asset retirement obligationsAROs associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income (Loss).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, other than Oil and Gas. For the Oil and Gas segment, differences in the settlement of the liability and the recorded amount are generally reflected as adjustments to the capitalized cost of oil and gas properties and depleted pursuant to our use of the full cost method.operations. Additional information is included in Note 8.



Fair Value Measurements


Derivative Financial Instruments


AssetsWe 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. This levelLevel 1 instruments primarily consistsconsist of highly liquid and actively traded financial instruments such as exchange-traded securities or listed derivatives.with quoted pricing information on an ongoing basis.


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


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


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


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

Oil and Gas Segment:


The commodity contracts for the Oilour Electric and Gas segmentUtilities are valued underusing the market approach and include exchange-traded futures and basis swaps. Fair value was derived using exchange quoted settlement prices from third party brokers for similar instruments as to quantity and timing. The prices are then validated through third party sources and therefore support Level 2 disclosure.

Electric Utilities and Gas Utilities Segments:

The commodity contracts for the Utilities, valued using the market approach, include exchange-traded futures, options, basis swaps and over-the-counter swaps (Level 2) for natural gas contracts. For exchanged-tradedexchange-traded futures, options and basis swap Level 2 assets and liabilities, fair value was derived using broker quotes validated by the Chicago Mercantile Exchangeexchange settlement pricing for similar instruments.the applicable instrument. For over-the-counter swaps and option Level 2 assets and liabilities,instruments, fair value was derived from, or corroborated by, observable market data where market data for pricing is observable. In addition, the fair value for the over-the-counter swaps and option derivatives include a CVA component. The CVA considers the fair value of the derivative and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings.



Corporate Segment:

The interest rate swaps are valued using the market valuation approach. We establish fair value by obtaining price quotes directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty is then validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value, forwhich we validate by comparing our valuation with the same instrument. In addition, thecounterparty. The fair value for the interest rate swap derivativesof these swaps includes a CVA component. The CVA considers the fair value of the interest rate swap and the probability of default based on the lifecredit spreads of the contract. For the probability of a default component,counterparties when we utilize observable inputs supporting Level 2 disclosure by usingare in an unrealized gain position or on our own credit default spread if available, or a generic credit default spread curve that takes into account our credit ratings. Our remaining interest rate swap as of December 31, 2016 expiredwhen we are in January 2017.an unrealized loss position.


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


Derivatives and Hedging Activities


The accounting standards forAll our derivatives and hedging require that derivative instruments be recorded on the balance sheet as either an asset or liabilityare measured at its fair value and that changes inrecognized as either assets or liabilities on the Consolidated Balance Sheets, except for derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met and designated accordingly, or if theycontracts that qualify for certain exemptions, includingand are elected under the normal purchasespurchase and normal sales exemption. Each Consolidated Balance Sheet reflects the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when a legal right of offset exists.

Accounting standards for derivatives and hedging require that the unrealized gains or losses on a derivative instrument designated and qualifying as a fair value hedging instrument as well as the offsetting unrealized gain or loss on the hedged item attributable to the hedged risk be recognized currently in earnings in the same accounting period. Conversely, the effective portion of the unrealized gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument must be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, is recognized currently in earnings.

Revenues and expenses on contracts that qualify are designated as normal purchases and normal sales and are recognized when the underlying physical transaction is completed under the accrual basis of accounting.exception. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time, and 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 electricElectric and gas utilityGas Utilities’ operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. These

In addition, certain derivatives contracts include short-term and long-term commitments to purchase and sell energyapproved by regulatory authorities are either recovered or refunded through customer rates. Any changes in the retail and wholesale markets with the intent and ability to deliver or take delivery. If it was determined that a transaction designated as a normal purchase or normal sale no longer met the exceptions, the fair value of the related contract would be reflectedthese approved derivative contracts are deferred as either ana regulatory asset or regulatory liability under the accounting standards for derivatives and hedging.pursuant to ASC 980.


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 using the effective interest method over the estimated useful life of the related debt.

Development Costs

According to accounting standards for business combinations, we expense, when incurred, development and acquisition costs associated with corporate development activities prior to acquiring or beginning construction of a project. Expensed development These costs are included in Other operating expensespresented on the accompanying Consolidated Statements of Income (Loss).balance sheet as an adjustment to the related debt liabilities.



Legal Costs

Litigation liabilities, including potential settlements, are recorded when it is both probable that a liability or settlement has been incurred and the amount can be reasonably estimated. Legal costs related to ongoing litigation are expensed as incurred.
When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, we record a loss contingency at the minimum amount in the range. If the loss contingency at issue is not both probable and reasonably estimable, we do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable.


Regulatory Accounting


Our regulated Electric Utilities and Gas Utilities followare 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 and reflect the effects of the numerous rate-making principles followed by the various state and federal agencies regulating the utilities. The accounting policies followed are generally subject to the Uniform System of Accounts of the FERC.operations. These accounting policies differ in some respects from those used by our non-regulated businesses. Under these regulated operations accounting standards:

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

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

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

If rate recovery becomes unlikely or uncertain due to competition orchanges in the regulatory action, these accounting standardsenvironment occur, we may no longer be eligible to apply which would require these net assetsthis accounting treatment, and may be required to be charged to current income or OCI. Our regulatory assets represent amounts for which we will recover the cost, but generally are not allowed a return, except as described below. In the event we determine that our regulated net assets no longer meet the criteria for following accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations, which could be material.

We had the followingeliminate regulatory assets and liabilities (in thousands):from our balance sheet. Such changes could adversely affect our results of operations, financial position or cash flows.

 Maximum  
 AmortizationAs ofAs of
  (in years)December 31, 2016December 31, 2015
Regulatory assets   
Deferred energy and fuel cost adjustments - current (a)(d)
1$17,491
$24,751
Deferred gas cost adjustments (a)(d)
115,329
15,521
Gas price derivatives (a)
48,843
23,583
Deferred taxes on AFUDC (b)
4515,227
12,870
Employee benefit plans (c) (e)
12108,556
83,986
Environmental (a)
subject to approval1,108
1,180
Asset retirement obligations (a)
44505
457
Loss on reacquired debt (a)
2220,188
3,133
Renewable energy standard adjustment (a)
51,605
5,068
Deferred taxes on flow through accounting (c)
3537,498
29,722
Decommissioning costs (b)
1016,859
18,310
Gas supply contract termination (a)
526,666
—
Other regulatory assets (a)
1526,267
13,903
  $296,142
$232,484
    
Regulatory liabilities   
Deferred energy and gas costs (a)
1$10,368
$7,814
Employee benefit plans (c)
1268,654
47,218
Cost of removal (a)
44118,410
90,045
Other regulatory liabilities (c)
259,324
7,964
  $206,756
$153,041
__________
(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, respectively.
(d)Our deferred energy, fuel cost and gas cost adjustments represent the cost of electricity and gas delivered to our electric and gas utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. Our electric and gas utilities file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions.
(e)Increase compared to 2015 was driven by the addition of the SourceGas employee benefit plans.



Regulatory assets represent itemsAs of December 31, 2019 and 2018, we expect to recover from customers through probable future rates.

Deferred Energy and Fuel Cost Adjustments - Current - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our electric utility customers that is either higher or lower than the current rates and will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state commission.

Deferred Gas Cost Adjustment - Our regulated gas utilities have GCA provisions that allow them to pass the cost of gas on to their customers. The GCA is based on forecasts of the upcoming gas costs and recovery or refund of prior under-recovered or over-recovered costs. To the extent that gas costs are under-recovered or over-recovered, they are recorded as a regulatory asset or liability, respectively. Our Gas Utilities file periodic estimates of future gas costs based on market forecasts with state utility commissions.

Gas Price Derivatives - Our regulated utilities, as allowed or required by state utility commissions, have entered into certain exchange-traded natural gas futures and options to reduce our customers’ underlying exposure to fluctuations in gas prices. Gas price derivatives represent our unrealized positions on our commodity contracts supporting our utilities. The 4-year term represents the maximum forward term hedged.

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

Employee Benefit Plans - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plans and post-retirement benefit plans inhad total regulatory assets rather than in AOCI, including costs being amortized from the Aquila Transaction.of $271 million and $284 million respectively, and total regulatory liabilities of $537 million and $541 million respectively. See Note 13 for further information.

Environmental - Environmental expenditures are costs associated with manufactured gas plant sites. The amortization of this asset is first offset by recognition of insurance proceeds and settlements with other third parties. Any remaining recovery will be requested in future rate filings. Recovery has not yet been approved by the applicable commission or board and therefore, the recovery period is unknown.

Asset Retirement Obligations - Asset retirement obligations represent the estimated recoverable costs for legal obligations associated with the retirement of a tangible long-lived asset. See Note 8 for additional details.

Loss on Reacquired Debt - Loss on reacquired debt is recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue.

Renewable Energy Standard Adjustment - The renewable energy standard adjustment is associated with incentives for our Colorado Electric customers to install renewable energy equipment at their location. These incentives are recovered over time with an additional rider charged on customers’ bills.

Deferred Taxes on Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. A regulatory asset was established to reflect that future increases in income taxes payable will be recovered from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit for costs considered currently deductible for tax purposes, but are capitalized for book purposes.

Decommissioning Costs - South Dakota Electric and Colorado Electric received approval in 2014 for recovery of the remaining net book values and decommissioning costs of their decommissioned coal plants. South Dakota Electric is allowed a return on their costs, in addition to recovery of those costs.



Gas Supply Contract Termination - Black Hills Gas Holdings had agreements under the previous ownership that required the Company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. The majority of these purchases were committed to distribution customers in Nebraska, Colorado, and Wyoming, which are subject to cost recovery mechanisms. The prices to be paid under these agreements varied, ranging from $6 to $8 per MMBtu at the time of acquisition, and exceeded market prices. We recorded a liability for this contract in our purchase price allocation. We were granted approval to terminate these agreements from the NPSC, CPUC and WPSC, on the basis that these agreements are not beneficial to customers over the long term. We received written orders allowing us to create a regulatory asset for the net buyout costs associated with the contract termination, and recover the majority of costs from customers over a period of five years. We terminated the contract and settled the liability on April 29, 2016.

Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates.

Deferred Energy and Gas Costs - Deferred energy costs and gas costs related to over-recovery of purchased power, transmission and natural gas costs.

Employee Benefit Plans - 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 aspect of a rate regulated environment.

Cost of Removal - Cost of removal represents the estimated cumulative net provisions for future removal costs included in depreciation expense for which there is no legal obligation for removal.


Income Taxes


The Company and its subsidiaries file consolidated federal income tax returns. As a result of the SourceGas transaction, certain subsidiaries acquired file as a separate consolidated group. Where applicable, each tax-payingEach entity records both federal and state income taxes as if it were a separate taxpayer and consolidating expense adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss.


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


It is our policy to apply the flow-through method of accounting for investment tax credits.ITCs. Under the flow-through method, investment tax creditsITCs are reflected in net income as a reduction to income tax expense in the year they qualify. An exception to this general policy is the deferral method, which applies to our regulated businesses. Such a method results in the investment tax creditITC being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that generatedgave 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 (Loss).Income.


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




Earnings per Share of Common Stock


Basic earnings per share from continuing and discontinued operations is computed by dividing IncomeNet income (loss) from continuing orand 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, and outstanding stock options, restricted stock and performance shares under our equity compensation plans.


A reconciliation of share amounts used to compute earnings (loss) per share is as follows for the years ended December 31 (in thousands):
 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

 December 31, 2016December 31, 2015December 31, 2014
    
Net income (loss) available for common stock$72,970
$(32,111)$130,889
    
Weighted average shares - basic51,922
45,288
44,394
Dilutive effect of:   
Equity Units1,222
—
—
Equity compensation127
—
204
Weighted average shares - diluted53,271
45,288
44,598
    
Net income (loss) available for common stock, per share - Diluted$1.37
$(0.71)$2.93


Due to our Net loss available for common stock for the year ended December 31, 2015, potentially dilutedThe following securities were excluded from the diluted lossearnings per share calculation due to their anti-dilutive effect. In computing diluted net loss per share, 83,000 equity compensation shares were excluded from the computation for the yearyears ended December 31 2015.

The following outstanding securities were not included in the computationbecause of diluted earnings per share as their effect would have been anti-dilutive nature (in thousands):
 201920182017
    
Equity compensation1
16
11
Anti-dilutive shares excluded from computation of earnings per share1
16
11

 December 31, 2016December 31, 2015December 31, 2014
    
Equity compensation3
112
81
Equity units—
6,440
—
Anti-dilutive shares excluded from computation of earnings (loss) per share3
6,552
81

Business Combinations

We record acquisitions in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. The excess of the purchase price over the estimated fair values of the net tangible and net intangible assets acquired is recorded as goodwill. The application of ASC 805, Business Combinations requires management to make significant estimates and assumptions in the determination of the fair value of assets acquired and liabilities assumed in order to properly allocate purchase price consideration between goodwill and assets that are depreciated and amortized. Our estimates are based on historical experience, information obtained from the management of the acquired companies and, when appropriate, include assistance from independent third-party appraisal firms. These estimates are inherently uncertain and unpredictable. In addition, unanticipated events or circumstances may occur which may affect the accuracy or validity of such estimates. See Note 2 for additional detail on the accounting for the SourceGas Acquisition.


Noncontrolling InterestInterests


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.




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 and Adopted Accounting Standards


Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments,Simplifying the Accounting for Income Taxes, ASU 2016-152019-12


In August 2016,December 2019, the FASB issued ASU 2016-15, Statement2019-12, Simplifying the Accounting for Income Taxes as part of Cash Flows (Topic 230): Classification of Certain Cash Receiptsits overall simplification initiative to reduce costs and Cash Payments (a consensuscomplexity in applying accounting standards while maintaining or improving the usefulness of the Emerging Issues Task Force). This ASU requires changes ininformation provided to users of the presentationfinancial statements. Amendments include removal of certain items including but not limitedexceptions to debt prepayment or debt extinguishment costs; contingent consideration payments made afterthe general principles of ASC 740, Income Taxes, and simplification in several other areas such as accounting for a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. franchise tax (or similar tax) that is partially based on income. The ASU will benew guidance is effective for fiscal yearsinterim and annual periods beginning after December 15,, 2017. 2020 with early adoption permitted. We will use the retrospective transition method to adoptare 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 fiscal yearsthe 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, 2017. This2019, 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 willprospectively on January 1, 2020. Adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.


Improvements to Employee Share-Based Payment Accounting,Simplifying the Test for Goodwill Impairment, ASU 2016-092017-04


In March 2016,January 2017, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This ASU simplifies several aspects2017-04, Simplifying the Test for Goodwill Impairment by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of the accounting for employee share-based payment transactions, including the accounting for forfeitures, income taxes, and statutory tax withholding requirements. The ASUa 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 fiscal years,interim and interimannual reporting periods within those years, beginning after December 15, 2016,2019, applied on a prospective basis with early adoption permitted. Certain amendmentsWe adopted this standard prospectively on January 1, 2020. Adoption of this guidance areis not expected to be applied retrospectively and others prospectively. We will adopt this standard for fiscal years, and interim periods within those years, beginning after December 15, 2016. The adoption of this standard will not have a materialany impact on our financial position, results of operations or cash flows.


Leases,Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, ASU 2016-022018-19


In FebruaryJune 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), 2016-13, Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, which supersedes ASC 840, Leases.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 ASU requires lessees to recognize a right-of-use asset and lease liabilitynew guidance adds an impairment model that is based on the balance sheet for all leases with terms of moreexpected losses rather than 12 months. Lessees are permitted to make an accounting policy election to not recognize the asset and liability for leases with a term of 12 months or less. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. In addition, the ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which includes a number of practical expedients. The guidanceincurred losses. It is effective for the Companyinterim and annual reporting periods beginning after December 15, 2018. Early2019, with early adoption is permitted.

We are currently assessing the impact that adoption of ASU 2016-02 will haveadopted this standard on our financial position, results of operations or cash flows.

Simplifying the Accounting for Measurement-Period Adjustments, ASU 2015-16

In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments. This ASU eliminates the requirement to retrospectively account for changes to provisional amounts recognized at the acquisition date in a business combination. ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustments are determined, including the effect of the change in the provisional amount as if the accounting had been completed at the acquisition date. The provisions of this ASU are effective for fiscal years beginning after December 31, 2015, including interim periods within those fiscal years and should be applied prospectively to adjustments to provisional amounts that occur after the effective date. We have implemented ASU 2015-16 as of January 1, 2016.2020 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.




Recently Adopted Accounting Standards


Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent),Leases, ASU 2015-072016-02


On May 1, 2015,In February 2016, the FASB issued ASU 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent).The ASU removes2016-02, Leases (Topic 842) to increase transparency and comparability among organizations by requiring the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedientrecognition of right-of-use assets and also removes certain disclosure requirements. The new requirements were effective for us beginning January 1, 2016 and were applied retrospectively to all periods presented, in our 2016 Form 10-K. This ASU did not materially affect our financial statements and disclosures, but did change certain presentation and disclosure of the fair value of certain plan assets in our pension and other postretirement benefit plan disclosures in our 2016 Form 10-K, for all periods presented.

Simplifying the Presentation of Debt Issuance Costs, ASU 2015-03

In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. Debt issuance costs related to a recognized debt liability will be presentedlease liabilities on the balance sheet as a direct deduction fromfor most leases, whereas previously only financing-type lease liabilities (capital leases) were recognized on the debt liability, similarbalance sheet. Under the new standard, disclosures are required to meet the presentationobjective of debt discounts, rather than as an asset. Amortizationenabling users of these costs will continuefinancial statements to be reported as interest expense. ASU 2015-03 is effective for annual and interim reporting periods beginning after December 15, 2015. We adopted ASU 2015-03 inassess the first quarter of 2016 on a retrospective basis. As of December 31, 2016, we presented the debt issuance costs, previously reported in other assets, as direct deductions from the carrying amount of long-term debt. The implementation of this standard resulted in reductions of other assets, non-current and long-term debt of $13 million in the Consolidated Balance Sheets as of December 31, 2015.

Revenue from Contracts with Customers, ASU 2014-09

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows arising from revenue contracts with customers. The guidance isleases.

We adopted the standard effective for annual and interim reporting periods beginning after December 15, 2017 with early adoption on January 1, 2017 permitted. Entities2019. We elected not to recast comparative periods coinciding with the new lease standard transition and will havereport these comparative periods as presented under previous lease guidance. In addition, we elected the optionpackage of using either a full retrospective or modified retrospective approach to adopting this guidance. Underpractical expedients permitted under the modified approach, an entity would recognize the cumulative effect of initially applying thetransition guidance with an adjustmentthe new standard, which among other things, allowed us to carry forward the opening balance of retained earnings inhistorical lease classification. We also elected the period of adoption.practical expedient related to land easements, allowing us to carry forward our accounting treatment for existing land easement agreements.


We will adopt this standard for annual and interim reporting periods beginning after December 15, 2017 and are actively assessing all of our sources of revenue to determine the impact that adoptionAdoption of the new standard willresulted 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 andor cash flows.


(2)REVENUE

Our evaluation includes identifying revenue streams by like contracts generally provide for performance obligations that are fulfilled and transfer control to allowcustomers 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 easethe performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice. Our primary types of implementation. A majorityrevenue 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.


•
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 our revenues are from regulated tariff offerings that provide natural gas or electricity with a defined contractual term. For such arrangements, we expect that therevenue, including intercompany revenue, from contracts with thecustomers by customer will be equivalent to the electricity or gas delivered in that period. Therefore, we do not expect that there will be a significant shift in thetype and timing or pattern of revenue recognition for regulated tariff based sales. The evaluationeach of other revenue streams is ongoing, including our non-regulated revenues and those tied to longer term contractual commitments. However, a number of industry-specific implementation issues are still unresolved and the final resolution of these issues could impact our current accounting policies and/or patterns for revenue recognition, as well as the transition method selected.

(2)    ACQUISITION

Acquisition of SourceGas

On February 12, 2016, Black Hills Corporation acquired SourceGas, pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, including the assumption of $760 million in debt at closing. The purchase price was subject to post-closing adjustments for capital expenditures, indebtedness and working capital. Post-closing adjustments of approximately $11 million were agreed to and received from the sellers in June 2016.  SourceGas is a 99.5% owned subsidiary of Black Hills Utility Holdings, Inc., a wholly-owned subsidiary of Black Hills Corporation and has been renamed Black Hills Gas Holdings, LLC. Black Hills Gas Holdings primarily operates four regulated natural gas utilities serving approximately 429,000 customers in Arkansas, Colorado, Nebraska and Wyoming, and a 512-mile regulated intrastate natural gas transmission pipeline in Colorado.



Cash consideration of $1.135 billion paid on February 12, 2016 to close the SourceGas Acquisition included net proceeds of approximately $536 million from the November 23, 2015 issuance of 6.325 million shares of our common stock, 5.98 million equity units, and $546 million in net proceeds from our debt offerings on January 13, 2016. We funded the cash consideration and out-of-pocket expenses payable with the SourceGas Acquisition using the proceeds listed above, cash on hand, and draws under our revolving credit facility.

In connection with the acquisition, the Company recorded pre-tax, incremental acquisition costs of approximately $45 million and $10 millionreporting segments, for the years ending December 31, 2016 and 2015, respectively. These costs consisted of transaction costs, professional fees, employee-related expenses and other miscellaneous costs. The costs are recorded primarily in Other operating expenses and Interest expense on the Consolidated Statements of Income (Loss).

Our consolidated operating results for the year ended December 31, 2016 include2019 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


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 $348 million and net income (loss)our revenue contracts are based on variable quantities delivered; any fixed consideration contracts with an expected duration of $15 million, attributableone year or more are immaterial to SourceGasour 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 period from February 12 through December 31, 2016. The SourceGas operating results are reportedprincipal in our Gas Utilities segment. We believerevenue contracts, as we have control over the SourceGas Acquisition enhances Black Hills Corporation’s utility growth strategy, providing greater operating scale, driving more efficient delivery of services and benefiting customers.

We accounted for the SourceGas Acquisition in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. Substantially all of SourceGas’ operations are subjectprior to those services being transferred to the rate-setting authoritycustomer.

Revenue Not in Scope of state regulatory commissions, and are accounted for in accordance with GAAP for regulated operations. SourceGas’ assets and liabilities subject to rate setting provisions provideASC 606
Other revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair value of these assets and liabilities equal their historical net book values.

The final purchase price allocation of the fair value of the assets acquired and liabilities assumed is included in the table below. The cash consideration paid of $1.124 billion, net of long-term debt assumed of $760 millionabove 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 working capital adjustment received of approximately $11 million, resulted in goodwill of $940 million. We had up to one year fromfinance lease. See Note 5 for additional information.

Significant Judgments and Estimates
Unbilled Revenue

To the acquisition date to finalize the purchase price allocation. From the time of acquisition through December 31, 2016, we decreased goodwill by $6.7 million, reflecting the working capital adjustment received of $11 million and changes in valuation estimates for intangible assets, accrued liabilities and deferred taxes. Approximately $252 millionextent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the goodwill balancerevenue since the latest billing. This estimate is amortizable for tax purposes, relating tocalculated based upon several factors including billings through the partnership interests that were directly acquired in the transaction. The remainder of the goodwill balance is not amortizable for tax purposes. Goodwill generated from the acquisition reflects the benefits of increased operating scale and organic growth opportunities.
 (in thousands)
Purchase Price  $1,894,882
Less: Long-term debt assumed  (760,000)
Less: Working capital adjustment received  (10,644)
 Consideration Paid, net of working capital adjustment received  $1,124,238
    
Allocation of Purchase Price:   
Current Assets  $112,983
Property, plant & equipment, net  1,058,093
Goodwill  939,695
Deferred charges and other assets, excluding goodwill  133,299
Current liabilities  (172,454)
Long-term debt  (758,874)
Deferred credits and other liabilities  (188,504)
Total consideration paid, net of working-capital adjustment received  $1,124,238



Conditions of SourceGas Acquisition Regulatory Approval

The acquisition was subject to regulatory approvals from the public utility commissions in Arkansas (APSC), Colorado (CPUC), Nebraska (NPSC), and Wyoming (WPSC). Approvals were obtained from all commissions, subject to various conditions as set forth below:

The APSC order includes a twelve-month base rate moratorium, an annual $0.25 million customer credit for a term of up to five years or until we file the next rate review, whichever comes first, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements.

The CPUC order includes a two-year base rate moratorium for our regulated transmission and wholesale natural gas provider, a three-year base rate moratorium for our regulated gas distribution utility, an annual $0.2 million customer credit for a term of up to five-years or until we file the next rate review, whichever comes first, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements.

The NPSC order includes a three-year base rate moratorium, a three-year continuation of the Choice Gas Program, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate review, as well as various other terms and reporting requirements.

The WPSC order includes a three-year continuation of the Choice Gas Program, as well as various other terms and reporting requirements.

All four orders also disallowed recovery of goodwill and transaction costs. Recovery of transition costs is disallowed in Arkansas, Colorado and Nebraska. However, Wyoming allows for request of recovery of transition costs. Transition costs are those non-recurring costs related to the transition and integration of SourceGas. In the conditions mentioned above, the orders that include base rate moratoriums over a specified period of time do not impact our ability to adjust rates through riders or gas supply cost recovery mechanisms as allowed under the current enacted state tariffs. In certain cases, we may file for leave to increase general base rates and/or cost of sales recovery limited to material adverse changes, but only if there are changes in law or regulations or the occurrence of other extraordinary events outside of our control which resultlast billing cycle in a material adverse changemonth and prices in revenues,effect in our jurisdictions. Each month the estimated unbilled revenue requirement and/or increaseamounts are trued-up and recorded in operating costs.

Settlement of Gas Supply Contract

On April 29, 2016, we settled for $40 million, a former SourceGas contract that required the Company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. This contract’s intangible negative fair value is included with Current liabilities in the purchase price allocation. Approximately 75% of these purchases were committed to distribution customers in Nebraska, Colorado and Wyoming, which are subject to cost recovery mechanisms, while the remaining 25% was not subject to regulatory recovery. The prices to be paid under this contract varied, ranging from $6 to $8 per MMBtu at the time of acquisition and exceeded market prices. We applied for and were granted approval to terminate this agreement from the NPSC, CPUC and WPSC, on the basis that the agreement was not beneficial to customers in the long term. We received written orders allowing recovery of theAccounts receivable, net buyout costs associated with the contract termination that were allocated to regulated subsidiaries. These costs were recorded as a regulatory asset of approximately $30 million that is being recovered over a five-year period.



Pro Forma Results (unaudited)

We calculated the pro forma impact of the SourceGas Acquisition and the associated debt and equity financings on our operating results for the year ended December 31, 2016. The following pro forma results give effect to the acquisition, assuming the transaction closed on January 1, 2015:
  Pro Forma Results
  December 31,
  20162015
  (in thousands, except per share amounts)
Revenue $1,651,936
$1,763,901
Net income (loss) available for common stock $112,878
$(13,369)
Earnings (loss) per share, Basic $2.17
$(0.26)
Earnings (loss) per share, Diluted $2.12
$(0.26)

We derived the pro forma results for the SourceGas Acquisition based on historical financial information obtained from the sellers and certain management assumptions. Our pro forma adjustments relate to incremental interest expense associated with the financings to effect the transaction, and for the year ended December 31, 2015, also include adjustments to shares outstanding to reflect the equity issuances as if they had occurred on January 1, 2015, and to reflect pro forma dilutive effects of the equity units issued. The pro forma results do not reflect any cost savings, (or associated costs to achieve such savings) from operating efficiencies or restructuring that could result from the acquisition, and exclude any unique one-time items resulting from the acquisition that are not expected to have a continuing impact on the combined consolidated results. Pro forma results for the year ended December 31, 2016 reflect unfavorable weather impacts resulting in lower gas usage by our customers than in the same periods of the prior year. In addition, we calculated the tax impact of these adjustments at an estimated combined federal and state income tax rate of 37%.

These pro forma results are for illustrative purposes only and do not purport to be indicative of the results that would have been obtained had the SourceGas Acquisition been completed on January 1, 2015, or that may be obtained in the future.

Seller’s noncontrolling interest

One of the sellers retained 0.5% of the outstanding equity interests of SourceGas under the terms of the purchase agreement. As part of the transaction, we entered into an associated option agreement with that holder of the retained interest. The terms of this agreement provide us a call option to purchase the remaining interest beginning 366 days after the initial close of the SourceGas Transaction. If we choose not to exercise this option during a ninety-day period, the seller may exercise the put option to sell us the retained interest. The value of this 0.5% equity interest is shown as Redeemable noncontrolling interest on the accompanying consolidatedConsolidated 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 sheets.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):


20162015Lives (in years)20192018Lives (in years)
Electric UtilitiesProperty, Plant and EquipmentWeighted Average Useful Life (in years)Property, Plant and EquipmentWeighted Average Useful Life (in years)MinimumMaximumProperty, Plant and EquipmentWeighted Average Useful Life (in years)
Property, Plant and Equipment (b)
Weighted Average Useful Life (in years)MinimumMaximum
        
Electric plant:        
Production$1,303,101
41$1,136,847
433063$1,348,049
41$1,318,643
413246
Electric transmission354,801
52280,257
504070483,640
51437,082
514354
Electric distribution712,575
48699,775
471575861,042
47793,725
484650
Plant acquisition adjustment (a)
4,870
324,870
324,870
324,870
32
General164,761
25159,496
24365259,266
28233,531
282633
Capital lease - plant in service (b)
261,441
20261,441
20
Total electric plant in service2,801,549
 2,542,686
 2,956,867
 2,787,851
 
Construction work in progress74,045
 96,501
 102,268
 60,480
 
Total electric plant2,875,594
 2,639,187
 3,059,135
 2,848,331
 
Less accumulated depreciation and amortization578,162
 526,954
 (670,861) (615,365) 
Electric plant net of accumulated depreciation and amortization (c)
$2,297,432
 $2,112,233
 
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 1411 years remaining.
(b)Capital lease -
Due to the changes in our segment disclosures discussed in Note 5, Total electric plant in service, represents the assets accounted forAccumulated depreciation and amortization, and Electric plant net of accumulated depreciation and amortization were revised as a capital lease under the PPA between Colorado Electric and Black Hills Colorado IPP. The capital lease ends in conjunction with the expiration of the PPA on December 31, 2031.
(c)Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported2018 which resulted in an increase (decrease) of ($261) million, $91 million and ($170) million, respectively. There was no impact on our Gas Utilities segment. Cheyenne Light’s gas utility net Property,consolidated Plant, property and Equipment of $117 million previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment.equipment.








20162015Lives (in years)20192018Lives (in years)
Gas UtilitiesProperty, Plant and EquipmentWeighted Average Useful Life (in years)Property, Plant and EquipmentWeighted Average Useful Life (in years)MinimumMaximumProperty, Plant and EquipmentWeighted Average Useful Life (in years)Property, Plant and EquipmentWeighted Average Useful Life (in years)MinimumMaximum
        
Gas plant:        
Production$10,821
35$13
301771$13,000
35$13,580
352471
Gas transmission338,729
4845,104
602270516,172
50423,873
482267
Gas distribution1,303,366
42692,800
4533471,857,233
431,595,644
423056
Cushion gas - depreciable (a)
3,539
28—
0283,539
283,539
28
Cushion gas - not depreciated (a)
47,055
0—
0
Cushion gas - not depreciable (a)
44,443
N/A46,369
N/A
Storage27,686
31—
0154846,977
3129,335
302749
General339,382
19122,109
22344437,054
20355,920
191024
Total gas plant in service2,070,578
 860,026
 2,918,418
 2,468,260
 
Construction work in progress28,446
 11,854
 63,080
 38,271
 
Total gas plant2,099,024
 871,880
 2,981,498
 2,506,531
 
Less accumulated depreciation and amortization194,585
 120,458
 (336,721) (279,580) 
Gas plant net of accumulated depreciation and amortization (b)
$1,904,439
 $751,422
 $2,644,777
 $2,226,951
 
_____________
(a)Cushion gas is the portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability. Depreciation of cushionCushion gas is determined by the respective regulatory jurisdiction in which the cushionCushion gas resides.
(b)Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility net Property, Plant and Equipment of $117 million previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment.


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


2016Lives (in years)
20182018Lives (in years)
Property, Plant and EquipmentConstruction Work in ProgressTotal Property Plant and EquipmentLess Accumulated Depreciation, Depletion and AmortizationNet Property, Plant and EquipmentWeighted Average Useful LifeMinimumMaximumProperty, 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)$161,430
$1,298
$162,728
$55,157
$107,571
33240$435,438
$11,796
$447,234
$(137,832)$309,402
31240
Mining151,709
4,642
156,351
105,219
51,132
13259$175,650
$—
$175,650
$(111,689)$63,961
13259
Oil and Gas (a)
1,101,106
—
1,101,106
1,016,226
84,880
25225
_____________
(a)
Due to the changes in our segment disclosures discussed in Note 5, Property, plant and equipment, Accumulated depreciation and amortization, and Net Property,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 includes full cost pool net assets of approximately $43 million.equipment.



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

2015Lives (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$156,721
$2,182
$158,903
$51,471
$107,432
33240
Mining154,630
3,649
158,279
97,663
60,616
13259
Oil and Gas1,132,776
—
1,132,776
925,908
206,868
24325


2016Lives (in years)
20182018Lives (in years)
Property, Plant and EquipmentConstruction Work in ProgressTotal Property Plant and Equipment
Less Accumulated Depreciation, Depletion and Amortization (a)
Net Property, Plant and EquipmentWeighted Average Useful LifeMinimumMaximumProperty, Plant and EquipmentConstruction Work in ProgressTotal Property Plant and EquipmentLess Accumulated Depreciation and AmortizationNet Property, Plant and EquipmentWeighted Average Useful LifeMinimumMaximum
Corporate(a)$5,446
$11,974
$17,420
$(6,115)$23,535
8330$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 depletion and amortization at Corporate reflects the eliminationand Net property, plant and equipment were revised as of the capital lease accumulated depreciation difference between Colorado ElectricDecember 31, 2018 which resulted in an increase (decrease) of ($18) million and Black Hills Colorado IPP.($18) million respectively. There was no impact on our consolidated Plant, property and equipment.



2015Lives (in years)
 Property, Plant and EquipmentConstruction Work in ProgressTotal Property Plant and Equipment
Less Accumulated Depreciation, Depletion and Amortization (a)
Net Property, Plant and EquipmentWeighted Average Useful LifeMinimumMaximum
Corporate$376
$15,377
$15,753
$(4,770)$20,523
10530
___________
(a)Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP.



(4)    JOINTLY OWNED FACILITIES

Utility Plant


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 (Loss).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 region and the MAPP region.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 coal-fired 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. We retainSouth Dakota Electric retains responsibility for plant operations. Our Mining subsidiary supplies coalfuel 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.


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 the Busch Ranch Wind FarmI while AltaGasBlack Hills Electric Generation owns the remaining undivided50% ownership interest andinterest. Each company is obligated to make payments for costs associated with their proportionate share of the costs of operating the wind farm forover the life of the facility. We retainOn 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.

Non-Regulated Plants

Our consolidated financial statements include our share of a jointly-owned non-regulated power generation facility We recorded this purchase as described below. Our share of direct expenses for the jointly-owned facility is included in the corresponding categories of operating expenses in the accompanying Consolidated Statements of Income (Loss). Eachan asset acquisition at fair value with $8.7 million of the respective owners is responsible for providing its own financing.

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 Wyoming owns 76.5% of the Wygen I plant while MEAN owns the remaining ownership percentage. MEAN is obligated to make payments forElectric Generation provides its share of energy from the costs associated with administrative services, plant operations and coal supply provided by our Mining subsidiary during the life of the facility. We retain responsibility for plant operations.
wind farm to Colorado Electric through a PPA, which expires in October 2037.


At December 31, 2016, our interests in jointly-owned generating facilities and transmission systems were (in thousands):
(5)    BUSINESS SEGMENT INFORMATION
 Plant in ServiceConstruction Work in ProgressAccumulated Depreciation
Wyodak Plant$113,611
$256
$55,878
Transmission Tie$19,978
$13
$5,793
Wygen I$109,412
$957
$37,156
Wygen III$138,261
$1,806
$17,635
Busch Ranch Wind Farm$18,899
$—
$3,102



(5)    BUSINESS SEGMENTS 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.

Segment information was as follows (in thousands):
Total Assets (net of inter-company eliminations) as of December 31,20162015
Electric (a) (d)
$2,859,559
$2,704,330
Gas (b) (d)
3,307,967
999,778
Power Generation (a)
73,445
60,864
Mining67,347
76,358
Oil and Gas96,435
208,956
Corporate (c)
110,691
576,357
Total assets$6,515,444
$4,626,643
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)The PPA under which Black Hills Colorado IPP provides generationDue to support Coloradothe changes in our segment disclosures, Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by ourUtilities and Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.
(b)Includes theTotal assets acquired in the SourceGas acquisition on February 12, 2016.
(c)Corporate assets atwere revised as of December 31, 2015 include proceeds received from the November 23, 2015 equity offerings. These proceeds were subsequently used2018 which resulted in an increase (decrease) of ($188) million and $188 million, respectively. There was no impact on February 12, 2016 to partially fund the SourceGas Acquisition.
(d)Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Assets of $135 million, previously reported in the Electric Utilities segment in 2015 are now presented in the Gas Utilities segment.consolidated Total assets.


Capital Expenditures and Asset Acquisitions (a) for the years ended December 31,
20162015
Capital Expenditures  
Electric Utilities (b)
$258,739
$171,897
Gas Utilities  (b)
173,930
99,674
Power Generation4,719
2,694
Mining5,709
5,767
Oil and Gas6,669
168,925
Corporate17,353
9,864
Total Capital Expenditures467,119
458,821
Asset Acquisitions  
Gas Utilities  (b) (c)
1,124,238
21,970
Total Capital Expenditures and Asset Acquisitions$1,591,357
$480,791
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.
(b)Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reportedequipment as disclosed in our Gas Utilities segment. Cheyenne Light’s gas utility property additions of $30 million previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment.
(c)SourceGas was acquired on February 12, 2016. Net cash paid of $1.124 billion was net of long-term debt assumed and working capital adjustments received. See Note 2. The 2015 acquisitions represent two acquisitions made by Wyoming Gas.17.




Property, Plant and Equipment as of December 31,2016201520192018
Electric Utilities (a) (b)
$2,875,594
$2,639,187
Gas Utilities (b) (c)
2,099,024
871,880
Electric Utilities (a)
$3,059,135
$2,848,331
Gas Utilities2,981,498
2,506,531
Power Generation (a)
162,728
158,903
534,518
447,234
Mining156,351
158,279
180,473
175,650
Oil and Gas1,101,106
1,132,776
Corporate17,420
15,753
Corporate and Other29,055
22,269
Total property, plant and equipment$6,412,223
$4,976,778
$6,784,679
$6,000,015
_______________
(a)The PPA under which Black Hills Colorado IPP provides generationDue to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.
(b)Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reportedchanges in our Gassegment disclosures, Electric Utilities segment. Cheyenne Light’s gas utilityand Power Generation Property, Plant and Equipment were revised as of $130December 31, 2018 which resulted in an increase (decrease) of ($261) million previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment.
(c)Includesand $261 million, respectively. There was no impact on our consolidated Property, Plant and Equipment acquired in the SourceGas acquisition on February 12, 2016.Equipment.



 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
 Consolidating Income Statement
Year ended December 31, 2016Electric UtilitiesGas UtilitiesPower GenerationMiningOil and GasCorporateInter-company EliminationsTotal
  
Revenue$664,330
$838,343
$7,176
$29,067
$34,058
$—
$—
$1,572,974
Inter-company revenue12,951
—
83,955
31,213
—
347,500
(475,619)—
Total revenue677,281
838,343
91,131
60,280
34,058
347,500
(475,619)1,572,974
         
Fuel, purchased power and cost of natural gas sold261,349
352,165
—
—
—
456
(114,838)499,132
Operations and maintenance158,134
245,826
32,636
39,576
32,158
373,773
(326,847)555,256
Depreciation, depletion and amortization84,645
78,335
4,104
9,346
13,902
22,538
(23,827)189,043
Impairment of long-lived assets(a)
—
—
—
—
106,957
—
—
106,957
Operating income (loss)173,153
162,017
54,391
11,358
(118,959)(49,267)(10,107)222,586
         
Interest expense(56,237)(76,586)(3,758)(401)(4,864)(109,035)115,469
(135,412)
Interest income5,946
1,573
1,983
24
—
97,147
(105,244)1,429
Other income (expense), net3,193
184
2
2,209
110
179,839
(181,034)4,503
Income tax benefit (expense)(40,228)(27,462)(17,129)(3,137)52,659
24,365
457
(10,475)
Net income (loss)85,827
59,726
35,489
10,053
(71,054)143,049
(180,459)82,631
Net income attributable to noncontrolling interest—
(102)(9,559)—
—
—
—
(9,661)
Net income (loss) available for common stock$85,827
$59,624
$25,930
$10,053
$(71,054)$143,049
$(180,459)$72,970

________________
(a)
Oil and Gas includesIn 2019 we recorded an impairment of our investment in equity securities of a privately held oil and gas property impairments (see company. See Note 13).1 for additional information.




 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
        
 Consolidating Income Statement
Year ended December 31, 2015Electric UtilitiesGas UtilitiesPower GenerationMiningOil and GasCorporateInter-company EliminationsTotal
  
Revenue$668,226
$551,300
$7,483
$34,313
$43,283
$—
$—
$1,304,605
Inter-company revenue 
11,617
—
83,307
30,753
—
227,708
(353,385)—
Total revenue679,843
551,300
90,790
65,066
43,283
227,708
(353,385)1,304,605
         
Fuel, purchased power and cost of natural gas sold269,409
299,645
—
—
—
122
(112,289)456,887
Operations and maintenance160,924
140,723
32,140
41,630
41,593
225,721
(229,786)412,945
Depreciation, depletion and amortization80,929
32,326
4,329
9,806
29,287
9,273
(10,580)155,370
Impairment of long-lived assets(a)
—
—
—
—
249,608
—
—
249,608
Operating income (loss)168,581
78,606
54,321
13,630
(277,205)(7,408)(730)29,795
         
Interest expense(55,159)(17,912)(4,218)(433)(2,726)(57,839)54,568
(83,719)
Interest income4,114
601
1,015
34
217
48,582
(52,942)1,621
Other income (expense), net1,216
315
71
2,247
(337)70,889
(71,964)2,437
Impairment of equity investments (a)
—
—
—
—
(4,405)—
—
(4,405)
Income tax benefit (expense)(41,173)(22,304)(18,539)(3,608)104,498
2,926
360
22,160
Net income (loss)77,579
39,306
32,650
11,870
(179,958)57,150
(70,708)(32,111)
Net income attributable to noncontrolling interest—
—
—
—
—
—
—
—
Net income (loss) available for common stock$77,579
$39,306
$32,650
$11,870
$(179,958)$57,150
$(70,708)$(32,111)

________________
(a)
Oil and GasIncome tax benefit (expense) includes ceiling test and equity investment impairments (see a tax benefit of $73 million resulting from legal entity restructuring. See Note 13)15.
(b)Due to changes in our segment disclosures, Adjusted operating income and related income statement accounts were revised for the year ended December 31, 2018, which resulted in an increase (decrease) as follows (in millions):
Year ended December 31, 2018Electric UtilitiesPower GenerationInter-Company EliminationsTotal
Inter-company operating revenue - Contracts with customers$—
$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)$—




 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

 Consolidating Income Statement
Year ended December 31, 2014Electric UtilitiesGas UtilitiesPower GenerationMiningOil and GasCorporateInter-company EliminationsTotal
  
Revenue$643,446
$657,523
$6,401
$31,086
$55,114
$—
$—
$1,393,570
Inter-company revenue 
14,110
—
81,157
32,272
—
222,460
(349,999)—
Total revenue657,556
657,523
87,558
63,358
55,114
222,460
(349,999)1,393,570
         
Fuel, purchased power and cost of natural gas sold291,644
403,781
—
—
—
116
(113,759)581,782
Operations and maintenance156,252
142,024
33,126
41,172
42,659
213,415
(225,473)403,175
Depreciation, depletion and amortization77,011
28,912
4,540
10,276
24,246
7,690
(7,930)144,745
Operating income (loss)132,649
82,806
49,892
11,910
(11,791)1,239
(2,837)263,868
         
Interest expense(51,640)(17,487)(4,351)(493)(2,603)(50,299)55,913
(70,960)
Interest income4,590
466
682
59
918
48,969
(53,759)1,925
Other income (expense), net1,074
124
(6)2,275
183
61,605
(62,574)2,681
Income tax benefit (expense)(29,403)(21,758)(17,701)(3,299)4,768
24
744
(66,625)
Net income (loss)57,270
44,151
28,516
10,452
(8,525)61,538
(62,513)130,889
Net income attributable to noncontrolling interest—
—
—
—
—
—
—
—
Net income (loss) available for common stock$57,270
$44,151
$28,516
$10,452
$(8,525)$61,538
$(62,513)$130,889
________________
(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)$—






(6)    LONG-TERM DEBT


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


Interest Rate at

Interest Rate atBalance Outstanding

Due DateDecember 31, 2016December 31, 2016December 31, 2015Due DateDecember 31, 2019December 31, 2019December 31, 2018
Corporate

  
Senior unsecured notes due 2023November 30, 20234.25%$525,000
$525,000
November 30, 20234.25%$525,000
$525,000
Senior unsecured notes due 2020July 15, 20205.88%200,000
200,000
July 15, 2020N/A—
200,000
Corporate term loan due 2017 (a)

—
300,000
Remarketable junior subordinated notes (b)
November 1, 20283.50%299,000
299,000
Senior unsecured notes due 2019January 11, 20192.50%250,000
—
Senior unsecured notes due 2026January 15, 20263.95%300,000
—
January 15, 20263.95%300,000
300,000
Senior unsecured notes due 2027January 15, 20273.15%400,000
—
January 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
—
September 15, 20464.20%300,000
300,000
Corporate term loan due 2019 (a)
August 9, 20191.74%400,000
—
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%24,406
—
June 7, 20212.32%7,178
12,921
Total Corporate Debt 2,698,406
1,324,000
Total Corporate debt 2,632,178
2,437,921
Less unamortized debt discount (4,413)(1,890) (6,462)(5,122)
Total Corporate Debt, Net
2,693,993
1,322,110
Total Corporate debt, net 2,625,716
2,432,799



  
Electric Utilities

First Mortgage Bonds due 2044October 20, 20444.43%85,000
85,000
First Mortgage Bonds due 2044October 20, 20444.53%75,000
75,000
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
August 15, 20327.23%75,000
75,000
First Mortgage Bonds due 2039November 1, 20396.13%180,000
180,000
November 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
November 20, 20376.67%110,000
110,000
Industrial development revenue bonds due 2021 (c)
September 1, 20210.72%7,000
7,000
Industrial development revenue bonds due 2027 (c)
March 1, 20270.72%10,000
10,000
Series 94A Debt, variable rate (c)
June 1, 20240.88%2,855
2,855
Total Electric Utilities Debt
544,855
544,855
First Mortgage Bonds due 2044October 20, 20444.53%75,000
75,000
Total Wyoming Electric debt 202,000
202,000
Less unamortized debt discount (94)(99) —
—
Total Electric Utilities Debt 544,761
544,756
Total Wyoming Electric debt, net 202,000
202,000



  
Total long-term debt
3,238,754
1,866,866
 3,170,489
2,977,568
Less current maturities
5,743
—
 5,743
5,743
Less deferred financing costs (d)
 21,822
13,184
Less unamortized deferred financing costs (b)
 24,650
20,990
Long-term debt, net of current maturities and deferred financing costs
$3,211,189
$1,853,682
 $3,140,096
$2,950,835
_______________
(a)Variable interest rate, based on LIBOR plus a spread.rate.
(b)
See Note 12 for RSN details.
(c)Variable interest rate.
(d)Includes deferred financing costs associated with our Revolving Credit Facility of $2.3$1.7 million and $1.7$2.3 million as of December 31, 20162019 and December 31, 2015,2018, respectively.


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

2017$5,743
2018$5,743
2019$655,742
2020$205,742
2021$8,436
Thereafter$2,361,855


Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2016.2019.


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. The first mortgage bonds issued by South Dakota Electric and Wyoming Electric are callable, but are subject to make-whole provisions which would eliminate any economic benefit for us to call the bonds.


Assumption of Long-Term Debt

At the closing of the SourceGas Acquisition on February 12, 2016, we assumed $760 million in long-term debt, consisting of the following:

$325 million, 5.9% senior unsecured notes with an original issue date of April 16, 2007, due April 1, 2017.

$95 million, 3.98% senior secured notes with an original issue date of September 29, 2014, due September 29, 2019.

$340 million unsecured corporate term loan due June 30, 2017. Interest under this term loan was LIBOR plus a margin of 0.875%.

The $760 million in long-term debt assumed in the SourceGas Acquisition was repaid in August 2016.

Debt Transactions


On August 19, 2016,October 3, 2019, we completed a public debt offering of $700 million principal amount ofin senior unsecured notes.noted. The debt offering consisted of $400 million of 3.15%3.05% 10-year senior notes due JanuaryOctober 15, 20272029 and $300 million of 4.20%3.875% 30-year senior notes due SeptemberOctober 15, 20462049 (together the “Notes”). The proceeds of the Notes were used for the following:


• Repay the $325$400 million 5.9% senior unsecured notes assumed in the SourceGas Acquisition;

Repay the $95 million, 3.98% senior secured notes assumed in the SourceGas Acquisition;

Repay the remaining $100 million on the $340 million unsecuredCorporate term loan assumed inunder the SourceGas Acquisition;Amended and Restated Credit Agreement due June 17, 2021;


Pay down $100• Retire the $200 million 5.875% senior notes due July 15, 2020; and

• Repay a portion of the $500 million three-year unsecuredshort-term debt.

On June 17, 2019, we amended our Corporate term loan discussed below;

Payment of $29 million for the settlement ofdue July 30, 2020. This amendment increased total commitments to $400 million notional interest rate swap;from $300 million, extended the term through June 17, 2021, and

Remainder was used for general corporate purposes.

On August 9, 2016, we entered into a $500 million, three-year, unsecured term loan expiring on August 9, 2019. The proceeds of this term loan were used to pay down $240 million of the $340 million unsecured term loan assumed in the SourceGas Acquisition and the $260 million term loan expiring on April 12, 2017. This new term loan has had substantially similar terms and covenants as the amended and restated Revolving Credit Facility.



In accordance with regulatory orders related to The net proceeds from the early termination and settlement of the gas supply contract describedincrease in Note 1, on June 7, 2016, we entered into a 2.32%, $29 million term loan, due June 7, 2021. Proceeds from this term loantotal commitments were used to financepay down short-term debt. Proceeds from the early termination of the gas supply contract, resulting in a regulatory asset. Principal and interest are payable quarterly at approximately $1.6 million, the first of which was paid on June 30, 2016.

On January 13, 2016, we completed aOctober 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 $550these 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 notes. The debt offering consisted ofterm loan due August 2019. This amended and restated term loan, with $300 million outstanding at December 31, 2018, had a maturity date of 3.95%, ten-year senior notes due 2026,July 30, 2020 and $250 million of 2.50%, three-year senior notes due 2019. After discountshad substantially similar terms and underwriter fees, netcovenants 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 offering totaled $546 million and were used as funding for the SourceGas Acquisition. The discounts are amortized over the life of each respective note.October 3, 2019 public debt offering.


Amortization Expense


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

 Deferred Financing Costs Remaining atAmortization Expense for the years ended December 31,
 December 31, 2016201620152014
Revolving Credit Facility$2,341
 $537
$504
$616
Senior unsecured notes due 20232,921
 494
494
653
Senior unsecured notes due 2019763
 643
—
—
Senior unsecured notes due 2020592
 167
167
167
Senior unsecured notes due 20262,318
 262
—
—
Senior unsecured notes due 20273,281
 121
—
—
Senior unsecured notes due 20463,193
 37
—
—
Corporate term loan due 2019287
 144
—
—
Bridge Term Loan—
 843
4,213
—
RSNs due 20281,449
 122
10
—
First mortgage bonds due 2044 (South Dakota Electric)663
 24
24
6
First mortgage bonds due 2044 (Wyoming Electric)613
 23
22
6
First mortgage bonds due 2032518
 33
33
33
First mortgage bonds due 20391,734
 76
76
76
First mortgage bonds due 2037643
 31
31
31
Other506
 304
43
53
Total$21,822
 $3,861
$5,617
$1,641


Dividend Restrictions


Our credit facility and other debt obligations contain restrictions on the payment of cash dividends when a default or event of default occurs. In addition, the agreements governing our equity units contain restrictions on the payment of cash dividends upon any time we have exercised our right to defer payment of contract adjustment payments under the purchase contracts or interest payments under the RSNs included in such equity units. As of December 31, 2016,2019, 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, 20162019:


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, 2016,2019, the restricted net assets at our Electric and Gas Utilities were approximately $257$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

Our Revolving Credit Facility and debt securities contain certain restrictive financial covenants. As of December 31, 2016, we were in compliance with all of these financial covenants.


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

 Balance Outstanding at
 December 31, 2016December 31, 2015
Revolving Credit Facility$96,600
$76,800
_______________
(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 August 9, 2016,July 30, 2018, we amended and restated our corporate Revolving Credit Facility, to increasemaintaining total commitments toof $750 million from $500 million and extendextending the term through August 9, 2021July 30, 2023 with two one-year2 one year extension options (subject to consent from the lenders). This facility is similar to the former agreement,revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, andthe issuing agents and subject to receipt of additional commitments from existingeach bank increasing or providing a new lenders,commitment, to increase total commitments of the facility up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our most favorable Corporate credit rating from either S&P, or Moody’sFitch, 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 0.250%0.125%, 1.250%1.125%, and 1.250%1.125%, respectively, at December 31, 20162019. A 0.200%Based on our credit ratings, a 0.175% commitment fee iswas charged on the unused amount of the Revolving Credit Facility.at December 31, 2019.


On December 22, 2016, we implementedWe 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. We did not borrow under the CP Program in 2016 and do not have any notes outstanding as

Our net short-term borrowings (payments) during 2019 were $164 million. As of December 31, 2016.2019, the weighted average interest rate on short-term borrowings was 2.03%.


As of December 31, 2016 and 2015, we had outstanding letters of credit totaling approximately $36 million and approximately $33 million, respectively.

DeferredTotal accumulated deferred financing costs on the facilityRevolving Credit Facility of $5.46.7 million are being amortized over theits estimated useful life of the Revolving Credit Facility and were included in Interest expense on the accompanying Consolidated Statements of Income (Loss). The deferred financing costs on the new facility are being amortized as follows (in thousands):Income. See Note 6 above for additional details.
 Deferred Financing Costs Remaining on Balance Sheet as ofAmortization Expense for the years ended December 31,
 December 31, 2016201620152014
Revolving Credit Facility$2,341
$537
$504
$616


Debt Covenants


On December 7, 2016, we amendedUnder our Revolving Credit Facility and term loan agreements, allowing the exclusion of the Remarketable Junior Subordinated Notes (RSNs) from our Consolidated Indebtedness to Capitalization Ratio covenant calculation. Under the amended and restated Revolving Credit Facility and term loan agreements we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.70 to 1.00 for the quarter ending December 31, 2016 and subsequently for future quarters beginning March 31, 2017, maintain the 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 and excludes RSNs by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interestsinterest in subsidiariessubsidiaries. 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 includes the aggregate outstanding amountaccelerate all principal and interest outstanding. As of the RSNs.



Our Revolving Credit Facility and our Term Loans requireDecember 31, 2019, we were in compliance with the following financial covenant at the end of each quarter:these covenants.

 At December 31, 2016 Covenant Requirement at December 31, 2016
Consolidated Indebtedness to Capitalization Ratio62% Less than70%


(8)    ASSET RETIREMENT OBLIGATIONS


We have identified legal retirement obligations related to plugging and abandonment of natural gas and oil wells in the Oil and Gas segment, reclamation of coal mining sites in the Mining segment and removal of fuel tanks, asbestos, transformers containing polychlorinated biphenyls, and an evaporation pond andat our Electric Utilities, wind turbines at the regulatedour Electric Utilities segment,and Power Generation segments, retirement of gas pipelines at our Gas Utilities and removal of asbestos at our regulated utilities segments.Electric and Gas Utilities. We periodically review and update estimated costs related to these asset retirement obligations.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 AROAROs which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands):
December 31, 2015Liabilities IncurredLiabilities SettledAccretion
Liabilities Acquired (a)
Revisions to Prior Estimates  (b)(c)
December 31, 2016December 31, 2018Liabilities IncurredLiabilities SettledAccretion
Revisions to Prior Estimates (a) (b)
December 31, 2019
Electric Utilities(c)$4,462
$—
$—
$191
$—
$8
$4,661
$6,258
$—
$—
$385
$2,686
$9,329
Gas Utilities136
—
—
791
22,412
6,436
29,775
34,627
—
—
1,458
—
36,085
Power Generation (c)
300
3,445
—
158
836
4,739
Mining18,633
—
(105)822
—
(6,910)12,440
15,615
—
(380)740
(1,923)14,052
Oil and Gas21,504
3
(2,049)1,382
—
1,923
22,763
Total$44,735
$3
$(2,154)$3,186
$22,412
$1,457
$69,639
$56,800
$3,445
$(380)$2,741
$1,599
$64,205



December 31, 2014Liabilities IncurredLiabilities SettledAccretionLiabilities Acquired
Revisions to Prior Estimates (c)
December 31, 2015December 31, 2017Liabilities IncurredLiabilities SettledAccretion
Revisions to Prior Estimates (b)
December 31, 2018
Electric Utilities$7,012
$—
$(2,733)$183
$—
$—
$4,462
$6,287
$—
$—
$269
$2
$6,558
Gas Utilities291
—
(168)13
—
—
136
33,238
152
—
1,237
—
34,627
Mining19,138
—
—
993
—
(1,498)18,633
12,499
—
(4)649
2,471
15,615
Oil and Gas20,945
828
(1,792)1,371
—
152
21,504
Total$47,386
$828
$(4,693)$2,560
$—
$(1,346)$44,735
$52,024
$152
$(4)$2,155
$2,473
$56,800
_____________________
(a)Represents our legal liability for retirement of gas pipelines, specificallyThe increase in Electric Utilities Revisions to purge and cap these lines in accordance with Federal regulations. Approximately $22 millionPrior Estimates was recorded withprimarily driven by an increase to the purchase price allocation of SourceGas.estimated cost to decommission certain regulated wind farm assets.
(b)The Gas Utilitieschanges in the Mining Revision to Prior Estimates represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lineswere primarily driven by changes in accordanceestimated costs associated with Federal regulations.back-filling the pit with overburden removed during the mining process.
(c)The 2016 Mining RevisionWe reclassified $0.3 million of ARO as of December 31, 2018 related to Prior Estimates reflects an approximately 33% reductionBusch 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 equipment costs as promulgated by the State of Wyoming. The 2015 Mining Revision to Prior Estimates reflects a changeBusch Ranch I. Additional liabilities were incurred in backfill yards and disturbed acreage used in calculating the estimated liability as well as changes in inflation rate assumptions.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 valueliability 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 rate. supply. We are exposed to the following market risks, including, but not limited to:


Commodity price risk associated with our natural long position of crude oil and natural gas reserves and production, our retail natural gas marketing activities and our fuel procurement for certainseveral of our gas-fired generation assets;assets, which include market fluctuations due to unpredictable factors such as 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.
Interest rate risk associated with our variable rate debt.


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.


As of Our credit exposure at December 31, 2016, our credit exposure included a $1.1 million exposure to a non-investment grade rural electric cooperative. The remainder of our credit exposure2019 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 (Loss) and Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 10.

Oil and Gas

We produce natural gas, NGLs and crude oil through our exploration and production activities. Our natural long positions, or unhedged open positions from these activities, result in commodity price risk and variability to our cash flows.

To mitigate commodity price risk and preserve cash flows, we primarily use exchange traded futures, swaps and options to hedge portions of our crude oil and natural gas production. Futures contracts provide the requirement to buy or sell the commodity at a fixed price in the future. Option contracts provide the right, but not the obligation to buy or sell the commodity at a fixed price. Swap contracts require receipt of payment based on the difference between the fixed price and the settled commodity market price on the settlement date. We elect hedge accounting on the swaps and futures contracts. These transactions were designated upon inception as cash flow hedges, documented under accounting standards for derivatives and hedging and initially met prospective effectiveness testing. Effectiveness of our hedging position is evaluated at least quarterly.

The derivatives were marked to fair value and recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets. The effective portion of the gain or loss on these derivatives for which we have elected cash flow hedge accounting is reported in AOCI in the accompanying Consolidated Balance Sheets and the ineffective portion, if any, is reported in Revenue on the accompanying Consolidated Statements of Income (Loss).



The contract or notional amounts and terms of our crude oil futures and options and natural gas futures held at our Oil and Gas segment are comprised of short positions. A short position is a contract to sell the commodity while a long position is a contract to purchase the commodity. We had the following short positions as of:
 December 31, 2016December 31, 2015
 
Crude oil futures and swaps (b)
Crude oil options
Natural gas futures and swaps (b)
Crude oil futures and swaps (b)
Natural gas futures and swaps (b)
Notional (a)
108,000
36,000
2,700,000
198,000
4,392,500
Maximum terms in months (c)
24
12
24
24
24
________________________
(a)Crude in Bbls, gas in MMBtus.
(b)These financial instruments were designated as cash flow hedges upon inception.
(c)Refers to the maximum forward period hedged.

Based on December 31, 2016 market prices, a $0.9 million loss would be reclassified from AOCI during 2017. Estimated and actual realized gains or losses will change during future periods as market prices fluctuate.

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’Utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Consolidated Balance Sheets in accordance with the state utility commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Consolidated Statements of Income (Loss), or the Consolidated Statements of Comprehensive Income (Loss).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 20172020 through April 2019.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
 December 31, 2016December 31, 2015
 Notional (MMBtus)
Maximum Term (months) (a)
Notional (MMBtus)
Maximum Term (months) (a)
Natural gas futures purchased14,770,000
4820,580,000
60
Natural gas options purchased, net (b)
3,020,000
52,620,000
3
Natural gas basis swaps purchased12,250,000
4818,150,000
60
Natural gas over-the-counter swaps, net (c)
4,622,302
28—
0
Natural gas physical commitments, net (d)
21,504,378
10—
0

__________
(a)Term reflects the maximum forward period hedged.
(b)Volumes purchased asAs of December 31, 2016 is net of 2,133,0002019, 1,415,000 MMBtus of collar options (call purchase and put sale) transactions.natural gas over-the-counter swaps purchased were designated as cash flow hedges.
(c)As of December 31, 2016, 2,138,300 MMBtus were designated as cash flow hedges for the natural gas over-the-counter swaps purchased.
(d)Volumes exclude contracts that qualify for normal purchase, normal sales exception.


Financing Activities

In October 2015 and January 2016, we entered into forward starting interest rate swaps with a notional value totaling $400 million to fix the Treasury yield component associated with the anticipated issuance of senior notes. These swaps were settled at a loss of $29 million in connection with the issuance of our $400 million of unsecured ten-year senior notes on August 10, 2016. The effective portion of the loss in the amount of $28 million was recognized as a component of AOCI and will be recognized as a component of interest expense over the ten-year life of the $400 million unsecured note issued on August 19, 2016. The ineffective portion of $1.0 million, related to the timing of the debt issuance, was recognized in earnings as a component of interest expense. The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Consolidated Balance Sheets were as follows (dollars in thousands) as of:
 December 31, 2016 December 31, 2015
 
Interest Rate Swaps (a)
 
Interest Rate Swaps (a)
Interest Rate Swaps (b)
Notional$50,000
 $75,000
$250,000
Weighted average fixed interest rate4.94% 4.97%2.29%
Maximum terms in months1
 13
16
Derivative assets, non-current$—
 $—
$3,441
Derivative liabilities, current$90
 $2,835
$—
Derivative liabilities, non-current$—
 $156
$—
___________________
(a)The $25 million in swaps expired in October 2016 and the $50 million in swaps expired in January 2017. These swaps were designated to borrowings on our Revolving Credit Facility and were priced using three-month LIBOR, matching the floating portion of the related borrowings.
(b)These swaps were settled on August 19, 2016.

Based on December 31, 2016 market interest rates and balances related to our designated interest rate swaps,2019 prices, a loss of approximately $2.9$0.5 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. This total includes the $28 million loss currently deferred in AOCI. EstimatedAs market prices fluctuate, estimated and actual realized gains or losses will change during future periods as market interest rates change.periods.




Cash Flow Hedges


The impact of cash flow hedges on our Consolidated Statements of Income (Loss) is presented below for the years ended December 31, 20162019, 2018 and 20152017 (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, 2016December 31, 2019
Derivatives in Cash Flow Hedging RelationshipsLocation of Reclassifications from AOCI into IncomeAmount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)Location of Reclassifications from AOCI into IncomeAmount of Gain/(Loss) Reclassified from AOCI into Income
      
Interest rate swapsInterest expense$(3,899)Interest expense$(953)Interest expense$(2,851)
Commodity derivativesRevenue11,019
 —
Fuel, purchased power and cost of natural gas sold417
Commodity derivativesFuel, purchased power and cost of natural gas sold(14) —
Total impact from cash flow hedges $7,106
 $(953) $(2,434)



December 31, 2015December 31, 2018
Derivatives in Cash Flow Hedging RelationshipsLocation of Reclassifications from AOCI into IncomeAmount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)Location of Reclassifications from AOCI into IncomeAmount of Gain/(Loss) Reclassified from AOCI into Income
      
Interest rate swapsInterest expense$(3,647) $—
Interest expense$(2,851)
Commodity derivativesRevenue14,460
 —
Fuel, purchased power and cost of natural gas sold(130)
Total $10,813
 $—
Total impact from cash flow hedges $(2,981)



December 31, 2014December 31, 2017
Derivatives in Cash Flow Hedging RelationshipsLocation of Reclassifications from AOCI into IncomeAmount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)Location of Reclassifications from AOCI into IncomeAmount of Gain/(Loss) Reclassified from AOCI into Income
      
Interest rate swapsInterest expense$(3,669) $—
Interest expense$(2,941)
Commodity derivativesRevenue(1,995) —
Net (loss) from discontinued operations913
Total $(5,664) $—
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, 2016, 20152019, 2018 and 2014. The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the Consolidated Statements of Net Income (Loss) as incurred.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

 December 31, 2016December 31, 2015December 31, 2014
 (In thousands)
Increase (decrease) in fair value:   
Interest rate swaps$(31,222)$2,888
$(536)
Forward commodity contracts(573)9,782
14,681
Recognition of (gains) losses in earnings due to settlements:   
Interest rate swaps3,899
3,647
3,669
Forward commodity contracts(11,005)(14,460)1,995
Total other comprehensive income (loss) from hedging$(38,901)$1,857
$19,809


Derivatives Not Designated as Hedge Instruments


The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income (Loss) for the years ended December 31, 2016, 20152019, 2018 and 20142017 (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)

  201620152014
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 derivativesRevenue$(50)$—
$—
Commodity derivativesFuel, purchased power and cost of natural gas sold940
—
—
  $890
$—
$—


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 $8.8$3.3 million and $24$6.2 million at December 31, 20162019 and 2015,2018, 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


There have been no significant transfers between Level 1 and Level 2 derivative balances during 2016 or 2015. 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 11.11. 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

 As of December 31, 2016
 Level 1Level 2Level 3 Cash Collateral and Counterparty NettingTotal
Assets:      
Commodity derivatives - Oil and Gas$—
$2,886
$—
 $(2,733)$153
Commodity derivatives - Utilities—
7,469
—
 (3,262)4,207
Interest rate swaps—
—
—
 —
—
Total$—
$10,355
$—
 $(5,995)$4,360
       
Liabilities:      
Commodity derivatives - Oil and Gas$—
$1,586
$—
 $—
$1,586
Commodity derivatives - Utilities—
12,201
—
 (11,144)1,057
Interest rate swaps—
90
—
 —
90
Total$—
$13,877
$—
 $(11,144)$2,733




 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

 As of December 31, 2015
 Level 1Level 2Level 3 Cash Collateral and Counterparty NettingTotal
Assets:      
Commodity derivatives - Oil and Gas$—
$10,644
$—
 $(10,644)$—
Commodity derivatives - Utilities—
2,293
—
 (2,293)—
Interest rate swaps—
3,441
—
 —
3,441
Total$—
$16,378
$—
 $(12,937)$3,441
       
Liabilities:      
Commodity derivatives - Oil and Gas$—
$556
$—
 $(556)$—
Commodity derivatives - Utilities—
24,585
—
 (24,585)—
Interest rate swaps—
2,991
—
 —
2,991
Total$—
$28,132
$—
 $(25,141)$2,991

     

   





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

  20162015
 Balance Sheet LocationFair Value of Asset DerivativesFair Value of Liability DerivativesFair Value of Asset DerivativesFair Value of Liability Derivatives
Derivatives designated as hedges:     
Commodity derivativesDerivative assets - current$1,161
$—
$9,981
$—
Commodity derivativesDerivative assets - non-current124
—
663
—
Interest rate swapsDerivative assets - non-current—
—
3,441
—
Commodity derivativesDerivative liabilities - current—
1,090
—
465
Commodity derivativesDerivative liabilities - non-current—
238
—
91
Interest rate swapsDerivative liabilities - current—
90
—
2,835
Interest rate swapsDerivative liabilities - non-current—
—
—
156
Total derivatives designated as hedges$1,285
$1,418
$14,085
$3,547
      
Derivatives not designated as hedges:    
Commodity derivativesDerivative assets - current$2,977
$—
$—
$—
Commodity derivativesDerivative assets - non-current98
—
—
—
Commodity derivativesDerivative liabilities - current—
1,279
—
9,586
Commodity derivativesDerivative liabilities - non-current—
36
—
12,706
Interest rate swapsDerivative liabilities - current—
—
—
—
Interest rate swapsDerivative liabilities - non-current—
—
—
—
Total derivatives not designated as hedges$3,075
$1,315
$—
$22,292




Derivatives Offsetting


It is our policy to offset, in our Consolidated Balance Sheets, contracts which provide for legally enforceable netting forof 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, 20162019 and December 31, 2015,2018, 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, 20162019 was as follows (in thousands):
Derivative AssetsGross Amounts of Derivative AssetsGross Amounts Offset on Consolidated Balance SheetsNet Amount of Total Derivative Assets on Consolidated Balance Sheets
Subject to master netting agreement or similar arrangement:   
Commodity derivative:   
Oil and Gas$2,886
$(2,733)$153
Utilities4,269
(3,262)1,007
Interest Rate Swaps—
—
—
Total derivative assets subject to a master netting agreement or similar arrangement7,155
(5,995)1,160
    
Not subject to a master netting agreement or similar arrangement:   
Commodity derivative:   
Oil and Gas—
—
—
Utilities3,200
—
3,200
Interest rate swaps—
—
—
Total derivative assets not subject to a master netting agreement or similar arrangement3,200
—
3,200
    
Total derivative assets$10,355
$(5,995)$4,360
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
Subject to a master netting agreement or similar arrangement:   
Commodity derivative:   
Oil and Gas$1,586
$—
$1,586
Utilities11,144
(11,144)—
Interest Rate Swaps—
—
—
Total derivative liabilities subject to a master netting agreement or similar arrangement12,730
(11,144)1,586
    
Not subject to a master netting agreement or similar arrangement:   
Commodity derivative:   
Oil and Gas—
—
—
Utilities1,057
—
1,057
Interest Rate Swaps90
—
90
Total derivative liabilities not subject to a master netting agreement or similar arrangement1,147
—
1,147
    
Total derivative liabilities$13,877
$(11,144)$2,733
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, 20152018 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
Subject to master netting agreement or similar arrangement:   
Commodity derivative:   
Oil and Gas$10,644
$(10,644)$—
Utilities2,293
(2,293)—
Interest rate swaps3,441
—
3,441
Total derivative assets subject to a master netting agreement or similar arrangement16,378
(12,937)3,441
    
Not subject to a master netting agreement or similar arrangement:   
Commodity derivative:   
Oil and Gas—
—
—
Utilities—
—
—
Interest rate swaps—
—
—
Total derivative assets not subject to a master netting agreement or similar arrangement—
—
—
    
Total derivative assets$16,378
$(12,937)$3,441
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





Derivative LiabilitiesGross Amounts of Derivative LiabilitiesGross Amounts Offset on Consolidated Balance SheetsNet Amount of Total Derivative Liabilities on Consolidated Balance Sheets
Subject to a master netting agreement or similar arrangement:   
Commodity derivative:   
Oil and Gas$556
$(556)$—
Utilities24,585
(24,585)—
Interest Rate Swaps2,991
—
2,991
Total derivative liabilities subject to a master netting agreement or similar arrangement28,132
(25,141)2,991
    
Not subject to a master netting agreement or similar arrangement:   
Commodity derivative:   
Oil and Gas—
—
—
Utilities—
—
—
Interest Rate Swaps—
—
—
Total derivative liabilities not subject to a master netting agreement or similar arrangement—
—
—
    
Total derivative liabilities$28,132
$(25,141)$2,991

(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
 20162015
 Carrying AmountFair ValueCarrying AmountFair Value
Cash and cash equivalents (a)
$13,580
$13,580
$440,861
$440,861
Restricted cash and equivalents (a)
$2,274
$2,274
$1,697
$1,697
Notes payable (b)
$96,600
$96,600
$76,800
$76,800
Long-term debt, including current maturities (c)
$3,216,932
$3,351,305
$1,853,682
$1,992,274

_______________
(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 borrowings on our Revolving Credit Facility.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, overnight repurchase agreement accounts, money market mutual funds, and term deposits.As part of our cash management process, excess operating cash is invested in overnight repurchase agreementsmoney market mutual funds with our bank.Repurchase agreements 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 7.7.





(12)    EQUITY
(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 unitsEquity Units for total gross proceeds of $299 million. Each Equity Unit hashad a stated amount of $50$50.00 and consistsconsisted of (i) a forward purchase contract to purchase the Company’s common stock and (ii) a 1/20, or 5%, undivided beneficial ownership interest in $1,000 principal amount of RSNs due 2028. The RSNs, a debt instrument, and


On October 29, 2018, we announced the forwardsettlement rate for the stock purchase contracts an equity instrument,that are deemedcomponents of the Equity Units issued on November 23, 2015. The settlement rate was based upon the minimum settlement rate, as adjusted to be separate instruments asaccount for past dividends, because the investor may tradeaverage of the RSNs separately from the forward purchase contract and may also settle the forward purchase contract separately.

The forward purchase contracts obligate the holders to purchase from the Companyclosing price per share of BHC common stock on the settlementNew 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 shall be no later than November 1, 2018, for a price of $50 in cash, the following number ofit holds, received 1.0655 shares of our common stock, subject to anti-dilution adjustments:

if the “Applicable Market Value” (AMV) of the Company’s common stock, which is the average volume-weighted average price of the Company’sBHC common stock for the trading days during the 20 consecutive scheduled trading day period ending on the third scheduled trading day immediately preceding the forward purchase contract settlement date, equals or exceeds $47.2938, 1.0572 shares of the Company’s common stock per Equity Unit;

if the AMV is less than $47.2938 but greater than $40.25, a number of shares of the Company’s common stock having a value, based on the AMV, equaleach such unit. The holders' obligations to $50; and

ifmake such payments were satisfied with proceeds generated by the AMV is less than or equal to $40.25, 1.2422 shares of the Company’s common stock.

The RSNs bear interest at a rate of 3.5% per year, payable quarterly, and mature on November 1, 2028. The RSNs will be remarketed in 2018. If this remarketing is successful, the interest rate on the RSNs will be reset, and thereafter interest will be payable semi-annually at the reset rate. If there is no successful remarketing the interest rate on the RSNs will not be reset, and the holdersAugust 17, 2018, of the RSNs will havethat formerly constituted a component of the right to put the RSNs toEquity Units. See Note 6 for additional information.

Upon settlement of all outstanding stock purchase obligations, the Company at a price equal to 100% of the principal amount, and thereceived gross proceeds of the put right will be deemed to have been applied against the holders’ obligation under the forward purchase contracts.

The Company will also pay the Equity Unit holders quarterly contract adjustment payments at a rate of 4.25% per year of the stated amount of $50 per Equity Unit, or $2.125 per year up to November 1, 2018. The present value of the future contract adjustment payments, $33 million, is recorded as a reduction of shareholders’ equity. Until settlement of the forward purchase contracts, the shares of stock underlying each forward purchase contract are not outstanding. The forward purchase contracts will only be included in the computation of diluted earnings per share to the extent they are dilutive. As of December 31, 2016, the forward purchase contracts were dilutive and therefore included in the computation of diluted earnings per share. Basic earnings per share will not be affected until the forward purchase contracts are settled and the holders thereof become stockholders.

Selected information about our equity units is presented below (in thousands except for percentages):
Issuance DateUnits IssuedTotal Net ProceedsTotal Long-term Debt (RSNs)RSN Interest Rate (annual)Stock Purchase Contract Rate (annual)Stock Purchase Contract Liability as of December 31, 2016
11/23/20155,980
$290,030
$299,000
3.50%4.25%$23,335

At-the-Market Equity Offering Program

On March 18, 2016, we implemented an ATM equity offering program allowing us to sell shares of our common stock with an aggregate value of up to $200 million. The shares may be offered from time to time pursuant to a sales agreement dated March 18, 2016. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. During the three months ended December 31, 2016, we issued 218,647 common shares for $13 million, net of $0.1approximately $299 million in commissions under the ATM equity offering program. Through December 31, 2016, we have sold and issued an aggregate of 1,968,738exchange for approximately 6.372 million shares of common stock under the ATM equity offering program for $119 million, net of $1.2 million in commissions. As of December 31, 2016, there were no shares sold that were not settled.



Common Stock Offering

On November 23, 2015, we issued 6.325 million shares of Common stock pursuant to a public offering at $40.25 per share. Net proceeds were $246 million. The proceeds from the offeringstock. Proceeds were used to partially fundpay down the purchase of SourceGas, which closed on February 12, 2016.$250 million senior unsecured notes due January 11, 2019, with the balance used to pay down short-term debt.


Equity Compensation PlansPlans`


Our 2015 Omnibus Incentive Plan allows for the granting of stock, restricted stock, restricted stock units, stock options and performance shares. We had 1,115,557672,049 shares available to grant at December 31, 2016.2019.


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, 2016,2019, total unrecognized compensation expense related to non-vested stock awards was approximately $13.5$12 million and is expected to be recognized over a weighted-average period of 2.02 years. Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income (Loss) was as follows for the years ended December 31 (in thousands):
 201620152014
Stock-based compensation expense$10,885
$4,076
$9,329
 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 119,41514,000 stock options outstanding at December 31, 2016.2019. The amount of stock options granted during the last three years, and related exercise activity and the number of stock options outstanding at December 31, 2016 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, 20162019, 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

 Restricted StockWeighted-Average Grant Date Fair Value
 (in thousands) 
Balance at beginning of period202
$48.96
Granted195
53.55
Vested(88)48.00
Forfeited(14)51.89
Balance at end of period295
$52.15


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, waswere 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

 Weighted-Average Grant Date Fair ValueTotal Fair Value of Shares Vested
  (in thousands)
2016$53.55
$4,602
2015$50.01
$6,009
2014$54.34
$6,114




As of December 31, 20162019, there was $10.39.0 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 $2.3$2.9 million at December 31, 20162019 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, 2014January 1, 2014 - December 31, 2016440%200%
January 1, 2015January 1, 2015 - December 31, 2017430%200%
January 1, 2016January 1, 2016 - December 31, 2018530%200%
   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 PortionEquity PortionLiability Portion
 
Weighted-Average Grant Date Fair Value (a)
 Weighted-Average Fair Value at 
Weighted-Average Grant Date Fair Value (a)
 Weighted-Average Fair Value at
SharesDecember 31, 2016SharesDecember 31, 2019
(in thousands) (in thousands) (in thousands) (in thousands) 
Performance Shares balance at beginning of period74
$47.21
74
 77
$57.66
77
 
Granted27
47.76
27
 20
68.72
20
 
Forfeited—
—
—
 (4)64.60
(4) 
Vested(30)35.86
(30) (26)47.76
(26) 
Performance Shares balance at end of period71
$52.29
71
$48.05
67
$64.32
67
$89.63
_____________________
(a)The grant date fair values for the performance shares granted in 2016, 20152019, 2018 and 20142017 were determined by Monte Carlo simulation using a blended volatility of 24%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.


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, 2016$47.76
December 31, 2015$54.92
December 31, 2014$55.18
 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 (dollars and shares in(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 —
—
—

Performance PeriodYear of PaymentShares IssuedCash PaidTotal Intrinsic Value
January 1, 2013 to December 31, 20152016—
$—
$—
January 1, 2012 to December 31, 2014201569
$3,657
$7,314
January 1, 2011 to December 31, 2013201459
$3,011
$6,020



On January 24, 2017,28, 2020, the Compensation Committee of our Board of Directors determined that the Company’s performance criteriatotal shareholder return for the January 1, 20142017 through December 31, 20162019 performance period was not met. Asat the 36.3 percentile of its peer group and confirmed a result, there will be no payout for this period.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, 20162019, there was $3.13.4 million of unrecognized compensation expense related to outstanding performance share plans that is expected to be recognized over a weighted-average period of 1.81.6 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 are currently issuingissued new shares.

A summary ofshares until March 1, 2018, after which we began purchasing shares on the DRSPP for the years endedopen market. At December 31, is as follows (shares in thousands):2019, there were 214,967 shares of unissued stock available for future offering under the plan.
 20162015
Shares Issued51
66
   
Weighted Average Price$58.24
$44.79
   
Unissued Shares Available356
408


Preferred Stock


Our articles of incorporation authorize the issuance of 25 million shares of preferred stock of which we had no0 shares of preferred stock outstanding.


Sale of Noncontrolling Interest in Subsidiary


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


ASC 810 requires theThe accounting for a partial sale of a subsidiary in which control is maintained and the subsidiary continues to be consolidated.consolidated, is specified under ASC 810. 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 yearyears ended December 31, 2016,2019, 2018 and 2017 was reduced by $9.6$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.




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


We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above as of December 31:31 (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):
 2016 2015
 (in thousands)
Assets   
Current assets$12,627
 $—
Property, plant and equipment of variable interest entities, net$218,798
 $—
    
Liabilities   
Current liabilities$4,342
 $—
 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.

Regulatory assets represent items we expect to recover from customers through probable future rates.
(13)    IMPAIRMENT OF ASSETS

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.
Long-lived assets

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.
Under the full cost method of accounting used
Gas Price Derivatives - Our regulated utilities, as allowed or required by our Oil and Gas segment to account for exploration, development and acquisition of crude oil andstate utility commissions, have entered into certain exchange-traded natural gas reserves, all costs attributablefutures and options to these activitiesreduce 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 capitalized. These capitalized costs, less accumulated amortization and relatedhedged 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 subject to a ceiling test that limitscosts 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 pooled costs toapplicable commission or board and therefore, the aggregaterecovery period is unknown.

Loss on Reacquired Debt - Loss on reacquired debt is recovered over the remaining life of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined byoriginal issue or, if refinanced, over the SEC plus the lower of cost or market value of unevaluated properties. Any costs in excesslife of the ceilingnew 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 written offrecovered 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 a non-cash charge.

the temporary differences reverse. As a result of continued low commoditythis 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.


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 throughout 2016,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 have recorded non-cash ceiling test impairments of oilexpect to refund to customers through probable future decreases in rates.

Deferred Energy and Gas Costs - Deferred energy costs and gas assetscosts 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 Oilregulated 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.


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.
Black Hills Wyoming and Wyoming Electric

Wygen 1 FERC Filing

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 continuing for an additional 20 years to December 31, 2042. On December 23, 2019, the Company filed a response to questions from the FERC and awaits a decision from FERC.

Wyoming Electric

Blockchain Tariff

On April 30, 2019, the WPSC approved Wyoming Electric’s application for a new Blockchain Interruptible Service Tariff. The utility has partnered with the economic development organization for City of Cheyenne and Laramie County to actively recruit blockchain customers to the state. This tariff is complementary to recently enacted Wyoming legislation supporting the development of blockchain within the state.

PCA Settlement

On October 31, 2018, Wyoming Electric received approval from the WPSC for a comprehensive, multi-year settlement regarding its PCA Application filed earlier in 2018. Wyoming Electric’s PCA permits the recovery of costs associated with fuel, purchased electricity and other specified costs, including the portion of the company’s energy that is delivered from the Wygen I PPA with Black Hills Wyoming. Wyoming Electric was to provide a total of $7.0 million in customer credits through the PCA mechanism in 2018, 2019 and 2020 to resolve all outstanding issues relating to its current and prior PCA filings. The settlement also stipulated the adjustment for the variable cost segment of the Wygen I PPA with Wyoming Electric will escalate by 3.0% annually through 2022, providing price certainty for Wyoming Electric and its customers.

Gas segment totalingUtilities Regulatory Activity

Arkansas Gas

Rate Review

On October 5, 2018, Arkansas Gas received approval from the APSC for a general rate increase. The new rates were to generate approximately $92$12 million of new annual revenue. The APSC’s approval also allowed Arkansas Gas to include $11 million of revenue that was being collected through certain rider mechanisms in the new base rates. The new revenue increase was based on a return on equity of 9.61% and a capital structure of 49.1% equity and 50.9% debt. New rates, inclusive of customer benefits related to the TCJA, were effective October 15, 2018.

Colorado Gas

Jurisdictional Consolidation and Rate Review

On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate rates, tariffs, and services of its 2 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.

Nebraska Gas

Jurisdictional Consolidation and Rate Review

On October 29, 2019, Nebraska Gas received approval from the NPSC to merge its 2 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.

SSIR

On June 1, 2018, Nebraska Gas Distribution filed an application with the NPSC requesting a continuation of the SSIR beyond the expiration date of October 31, 2019. On September 5, 2018, the NPSC approved continuation of the SSIR tariff to December 31, 2020. The SSIR provides approximately $6.0 million of revenue annually on investments made prior to January 1, 2018, with investments after that date to be recovered through other methods. If a base rate review is filed prior to expiration of the rider, that rate request will include the remaining investment to be recovered.

On October 2, 2017, Nebraska Gas Distribution filed with the NPSC requesting recovery of $6.8 million, which includes $0.3 million of increased annual revenue related to system safety and integrity expenditures on projects for the period of 2012 through 2017. This SSIR tariff was approved by the NPSC in January 2018, and went into effect on February 1, 2018.

Wyoming Gas

Jurisdictional Consolidation and Rate Review

On December 11, 2019, Wyoming Gas received approval from the WPSC to consolidate the rates, tariffs and services of its 4 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.


(14)    LEASES

Lessee
We lease from third parties certain office and operation center facilities, communication tower sites, equipment, and materials storage. Our leases have remaining terms ranging from less than 1 year to 36 years, including options to extend that are reasonably certain to be exercised.

The components of lease expense for the year ended December 31 2016. In determining the ceiling value of our assets, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. For natural gas, the average NYMEX price was $2.48 per Mcf, adjustedwere as follows (in thousands) :
 Income Statement Location2019
Operating lease costOperations and maintenance$1,456
Finance lease cost:  
Amortization of right-of-use assetDepreciation, depletion and amortization100
Interest on lease liabilitiesInterest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)19
Total lease cost $1,575


Supplemental balance sheet information related to $2.25 per Mcf at the wellhead; for crude oil, the average NYMEX price was $42.75 per barrel, adjusted to $37.35 per barrel at the wellhead.

In 2015, we recorded a non-cash ceiling test impairment of oil and gas assets included in the Oil and Gas segment totaling approximately $250 million for the year ended December 31, 2015. In determining the ceiling value of our assets, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. For natural gas, the average NYMEX price was $2.59 per Mcf, adjusted to $1.27 per Mcf at the wellhead; for crude oil, the average NYMEX price was $50.28 per barrel, adjusted to $44.72 per barrel at the wellhead.

During the second quarter of 2016, we advanced our Oil and Gas strategy, identifying certain non-core assets which may be sold as they are not expected to be utilized in the Cost of Service Gas Program. We assessed these assets for impairment in accordance with ASC 360. We valued the assets applying a market method approach utilizing assumptions consistent with similar known and measurable transactions and determined that the carrying amount exceeded the fair value. As a result, we recorded a pre-tax impairment of depreciable properties at June 30, 2016 of $14 million, in addition to the impairments noted above. The remaining book value of these depreciable assets is approximately $23 millionleases as of December 31 2016.was as follows (in thousands):

 Balance Sheet Location2019
Assets:  
Operating lease assetsOther assets, non-current$4,629
Finance lease assetsOther assets, non-current465
Total lease assets $5,094
   
Liabilities:  
Current:  
Operating leasesAccrued liabilities$1,179
Finance leaseAccrued liabilities109
   
Noncurrent:  
Operating leasesOther deferred credits and other liabilities3,821
Finance leaseOther deferred credits and other liabilities364
Total lease liabilities $5,473




Equity investments in unconsolidated subsidiaries

Our Oil and Gas segment owned a 25% interest in a pipeline and gathering system, accounted for under the equity method of accounting. During the second quarter of 2015, dueSupplemental cash flow information related to sustained low commodity prices, recurring operating losses and future expectations we reviewed this investment interest for impairment utilizing the other-than-temporary impairment model under ASC 820, Fair Value Measurements. We valued the investment applying a market method approach utilizing assumptions consistent with similar known and measurable transactions. The carrying amount of this equity method investment exceeded the fair value, and we concluded the decline was considered to be other than temporary. As a result, we recorded a pre-tax impairment loss at June 30, 2015 of $5.2 million, the difference between the carrying amount and the fair value of the investment. In December of 2015, we sold our 25% interest in this pipeline and gathering system.

(14)    OPERATING LEASES

We have entered into lease agreements for vehicles, equipment and office facilities. Rental expense incurred under these operating leases, including month to month leases for the yearsyear ended December 31 was as follows (in thousands):
 2019
Cash paid included in the measurement of lease liabilities: 
Operating cash flows from operating leases$1,263
Operating cash flows from finance lease$19
Financing cash flows from finance lease$93
Right-of-use assets obtained in exchange for lease obligations: 
Operating leases$2,801
Finance lease$67

 201620152014
Rent expense$9,568
$7,177
$6,932


The following is a scheduleWeighted average remaining terms and discount rates related to leases as of December 31 were as follows:
2019
Weighted average remaining lease term (years):
Operating leases8 years
Finance lease4 years
Weighted average discount rate:
Operating leases4.27%
Finance lease4.19%


As of December 31, 2019, scheduled maturities of lease liabilities for future years were as follows (in thousands):
 Operating LeasesFinance LeaseTotal
20201,018
126
1,144
2021865
126
991
2022743
126
869
2023718
126
844
2024714
10
724
Thereafter2,009
—
2,009
Total lease payments (a)
$6,067
$514
$6,581
Less imputed interest1,067
41
1,108
Present value of lease liabilities$5,000
$473
$5,473
_______________
(a)Lease payments exclude payments to landlords for common area maintenance, real estate taxes, and insurance.


As previously disclosed in Note 14 of the Notes to the Consolidated Financial Statements in our 2018 Annual Report on Form 10-K, prior to the adoption of ASU 2016-02, Leases (Topic 842), the future minimum payments required under the operating lease agreements as of December 31, 2018 were as follows (in thousands):
 Operating Leases
2019$1,052
2020464
2021344
2022224
2023216
Thereafter1,776
Total lease payments 
$4,076


Lessor

We lease to third parties certain generating station ground leases, communication tower sites, and a natural gas pipeline. These leases have remaining terms ranging from less than one year to 35 years.

The components of lease revenue for the year ended December 31 were as follows (in thousands):
 Income Statement Location2019
Operating lease incomeRevenue$2,306

2017$6,739
2018$5,564
2019$4,441
2020$2,639
2021$1,652
Thereafter$6,245


As of December 31, 2019, scheduled maturities of operating lease payments to be received in future years were as follows (in thousands):
 Operating Leases
20202,227
20211,857
20221,793
20231,799
20241,743
Thereafter53,739
Total lease receivables$63,158



(15)    INCOME TAXES

TCJA

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. As such, the Company remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017. The entities subject to regulatory construct have made their best estimate regarding the probability of settlements of net regulatory liabilities established pursuant to the TCJA. The amount of the settlements may change based on decisions and actions by the federal and state utility commissions, which could have a material impact on the Company’s future results of operations, cash flows or financial position. As a result of the revaluation at December 31, 2017, deferred tax assets and liabilities were reduced by approximately $309 million. Of the $309 million, approximately $301 million is related to our regulated utilities and is reclassified to a regulatory liability. During the year ended December 31, 2018 we recorded approximately $11 million of additional regulatory liability associated with TCJA related items primarily related to property, completing the revaluation of deferred taxes pursuant to the TCJA. A majority of the excess deferred taxes are subject to the average rate assumption method, as prescribed by the IRS, and will generally be amortized as a reduction of customer rates over the remaining lives of the related assets. As of December 31, 2019, the Company has amortized $6.5 million of the regulatory liability. 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.

Tax benefit related to legal entity restructuring

As part of the Company’s ongoing efforts to continue to integrate the legal entities that the Company has acquired in recent years, certain legal entity restructuring transactions occurred on March 31, 2018 and December 31, 2018.  As a result of these transactions, additional deferred income tax assets of $73 million, related to goodwill that is amortizable for tax purposes, were recorded and deferred tax benefits of $73 million were recorded to income tax benefit (expense) on the Consolidated Statements of Income. Due to this being a common control transaction, it had no effect on the other assets and liabilities of these entities.

Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands):
 201920182017
Current:   
Federal$(8,578)$325
$(6,193)
State138
247
(1,432)
 (8,440)572
(7,625)
Deferred:   
Federal34,551
(25,022)76,522
State3,469
783
4,470
 38,020
(24,239)80,992
    
 $29,580
$(23,667)$73,367

 201620152014
Current:   
Federal$(23,820)$2,549
$(2,319)
State(1,922)1,319
(1,288)
 (25,742)3,868
(3,607)
Deferred:   
Federal36,012
(23,592)64,780
State257
(2,323)5,658
Tax credit amortization(52)(113)(206)
 36,217
(26,028)70,232
    
 $10,475
$(22,160)$66,625


Included in discontinued operations is a tax benefit of $2.6 million and $8.4 million for 2018 and 2017, respectively.



The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands):
2016201520192018
Deferred tax assets:  
Regulatory liabilities$58,200
$43,586
$89,754
$92,966
Employee benefits29,638
26,400
State tax credits23,261
20,466
Federal net operating loss252,780
217,922
120,624
139,371
State net operating loss13,537
16,647
Partnership14,030
16,032
Credit Carryovers27,139
23,124
Other deferred tax assets(a)
83,485
85,907
33,395
39,349
Less: Valuation allowance(9,263)(4,304)(12,063)(11,809)
Total deferred tax assets414,840
369,511
309,677
336,146
  
Deferred tax liabilities:  
Accelerated depreciation, amortization and other property-related differences(b)
(820,111)(711,293)
Accelerated depreciation, amortization and other property-related differences(533,292)(529,338)
Regulatory assets(49,471)(29,092)(23,586)(32,324)
Goodwill (b)
(15,875)(602)
State deferred tax liability(47,987)(35,065)(72,911)(64,095)
Deferred costs(18,551)(26,121)
Other deferred tax liabilities(14,326)(18,519)(24,732)(21,118)
Total deferred tax liabilities(950,446)(820,090)(670,396)(647,477)
  
Net deferred tax liability$(535,606)$(450,579)$(360,719)$(311,331)
_______________

(a)Other deferred tax assets consist primarily of state tax credits, state net operating loss, alternative minimum tax credit and federal research and development credits. No single item exceeds 5% of the total net deferred tax liability.
(b)To conform with the 2016 presentation of accelerated depreciation, amortization and other property-related differences, 2015 is net of deferred tax assets of $182 million, previously presented as an asset impairment and includes $184 million of a liability previously presented as mining development and oil exploration.Legal entity restructuring - see above.







The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:
 201620152014
Federal statutory rate (e)
35.0 %35.0 %35.0 %
State income tax (net of federal tax effect)0.2
1.0
1.1
Amortization of excess deferred income taxes and investment tax credits(0.1)0.2
(0.1)
Percentage depletion (a)
(8.2)3.5
(1.0)
Non-controlling interest(d)
(3.6)—
—
Equity AFUDC(1.1)0.3
(0.1)
Tax credits(1.5)0.5
(0.1)
Transaction costs1.1
—
—
Accounting for uncertain tax positions adjustment(b)
(6.0)(3.5)(0.1)
Flow-through adjustments (c)
(5.1)3.8
(0.9)
Other tax differences0.6
—
(0.1)
 11.3 %40.8 %33.7 %
 201920182017
Federal statutory rate21.0 %21.0 %35.0 %
State income tax (net of federal tax effect)1.5
2.3
0.9
Non-controlling interest (a)
(1.2)(1.3)(1.8)
Tax credits(3.9)(2.0)(1.7)
Flow-through adjustments (b)
(2.4)(1.6)(1.1)
Jurisdictional consolidation project (d)
—
(28.5)—
Other tax differences(1.6)(0.1)(2.6)
TCJA corporate rate reduction (c)
—
1.6
(2.7)
Amortization of excess deferred income tax expense (e)
(1.2)(0.7)—
 12.2 %(9.3)%26.0 %
_________________________
(a)The effective tax benefit includes additional percentage depletion deductions that were claimed with respectrate reflects the income attributable to the oil and gas properties involving priornoncontrolling interest in Black Hills Colorado IPP for which a tax years. Such deductions were primarily the result of a change in the application of the maximum daily limitation of 1,000 barrels of oil equivalent as allowed under the Internal Revenue Code.provision was not recorded.
(b)The tax benefit relates to the release of after-tax interest expense that was previously accrued with respect to the liability for uncertain tax positions involving the like-kind exchange transaction effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. In addition, the tax benefit includes the release of reserves involving research and development credits and deductions. Both adjustments are the result of a re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016.
(c)The flow-throughFlow-through adjustments related primarily to an accounting method changechanges for tax purposes that allowsallow us to take a current tax deduction for repair costs that continue to be capitalized for book purposes. In addition, flow-through adjustments were recorded related to an accounting method change for tax purposes that allows us to take a current tax deduction forand certain indirect costs that continue to be capitalized for book purposes.costs. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and flowed the tax benefit through to tax expense. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record tax benefits consistent with the flow-through method.
(d)(c)Black Hills Colorado IPP wentOn December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from a single member LLC, wholly-owned by Black Hills Electric Generation,35% to a partnership as a result of the sale of 49.9% of its membership interest in April 2016.21% effective January 1, 2018. The 2017 effective tax rate reduction reflects the revaluation of deferred income attributable totaxes associated with non-regulated operations required by the noncontrolling interest for which achange. During the year ended December 31, 2018, we recorded $4.0 million of additional tax provision was not recorded.expense associated with changes in the prior estimated impacts of TCJA related items. During the year ended December 31, 2017, we recorded $7.6 million of tax benefit resulting from revaluation of net deferred tax liabilities in accordance with ASC 740 and the enactment of the TCJA on December 22, 2017.
(d)Legal entity restructuring - see above.
(e)The effective tax rate for the year ended December 31, 2015 represents a tax benefit due to the pre-tax net loss.Primarily TCJA - see above.


At December 31, 20162019, we have federal and gross state NOL carryforwards that will expire at various dates as follows (in thousands):
  Amounts Expiration Dates
Federal Net Operating Loss Carryforward $575,457
 2022to2037
       
State Net Operating Loss Carryforward (a)
 $224,716
 2020to2040

  Amounts Expiration Dates
Federal Net Operating Loss Carryforward $721,075
 2019to2036
       
State Net Operating Loss Carryforward $616,524
 2017to2036
_________________________
(a)The carryforward balance is reflected on the basis of apportioned tax losses to jurisdictions imposing state income taxes.


As of December 31, 20162019, we had a $0.9$0.5 million valuation allowance against the state NOL carryforwards. Our 20162019 analysis of the ability to utilize such NOLs resulted in a slightno increase ofin the valuation allowance of approximately $0.1 million, which resulted in an increase to tax expense. The valuation allowance adjustment was primarily attributable to a projected decrease in state taxable income for years beyond 2016. Such a decrease impacted the utilization of NOL carryforward in those states where the carryforward period is significantly shorter than the federal carryforward period of 20 years. In certain states, the carryforward period is limited to 5 years. Ultimate usage of these NOLs depends upon our future tax filings.allowance. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the NOLs, the offsetting amount will affect tax expense.




The following table reconciles the total amounts of unrecognized tax benefits, without interest, at the beginning and end of the period included in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets (in thousands):
 Changes in Uncertain Tax Positions
Beginning balance at January 1, 2017$3,592
Additions for prior year tax positions358
Reductions for prior year tax positions(5,713)
Additions for current year tax positions5,026
Settlements—
Ending balance at December 31, 20173,263
Additions for prior year tax positions251
Reductions for prior year tax positions(417)
Additions for current year tax positions486
Settlements—
Ending balance at December 31, 20183,583
Additions for prior year tax positions446
Reductions for prior year tax positions(862)
Additions for current year tax positions998
Settlements—
Ending balance at December 31, 2019$4,165

 Changes in Uncertain Tax Positions
Beginning balance at January 1, 2014$37,631
Additions for prior year tax positions1,253
Reductions for prior year tax positions(6,692)
Additions for current year tax positions—
Settlements—
Ending balance at December 31, 201432,192
Additions for prior year tax positions3,285
Reductions for prior year tax positions(3,491)
Additions for current year tax positions—
Settlements—
Ending balance at December 31, 201531,986
Additions for prior year tax positions2,423
Reductions for prior year tax positions(19,174)
Additions for current year tax positions—
Settlements(11,643)
Ending balance at December 31, 2016$3,592


The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $0.7 million.$0.3 million.


As a result of an agreement in principle that was reached with IRS Appeals in the first quarter of 2016, weWe recognized no0 interest expense for the year ended December 31, 2016, and approximately $1.8 million and $1.6 millionassociated with income taxes for the years ended December 31, 20152019, December 31, 2018 and 2014, respectively.

December 31, 2017. We had no0 accrued interest (before tax effect) associated with income taxes at December 31, 2016,2019 and approximately $13.3 million accrued at December 31, 2015.2018.


We fileThe Company is subject to federal income tax returns with the IRS andas well as income tax in various state and local jurisdictions. We receivedBlack Hills Gas, Inc. and subsidiaries, which filed a 30-day Letter along with a Revenue Agent’s Reportseparate consolidated tax return from the IRS in regards to the audit of the 2007 to 2009 tax years. A protest was timely filed with the IRS in August 2014 related to the like-kind exchange transaction described belowBHC and research and development (“R&D”) credits and deductions claimed with respect to certain costs and projects. A settlement in principle was reached with IRS Appeals in the first quarter of 2016. We are also currentlysubsidiaries through March 31, 2018, is under examination by the IRS for the 20102014. BHC is no longer subject to 2012examination for tax years. We received a 30-day letter along with Revenue Agent’s Report from the IRS in regardyears prior to the audit of the 2010 to 2012 tax years. A protest was timely filed with IRS Appeals in the second quarter of 2016 related to R&D credits and deductions claimed with respect to certain costs and projects.2016.

We have deferred a substantial amount of tax payments through various tax planning strategies including the deferral of approximately $125 million in income taxes attributable to the like-kind exchange effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. The IRS had challenged our position with respect to the like-kind exchange. In the first quarter of 2016, we reached a settlement agreement in principle with IRS Appeals related to both the like-kind exchange transaction in addition to the R&D credits and deductions issues. The settlement resulted in a reduction to the liability for unrecognized tax benefits of approximately $29 million excluding interest. Approximately $17 million of the reduction was to restore accumulated deferred income taxes and the remaining portion of approximately $12 million was reclassified to current taxes payable.


As of December 31, 2016,2019, we do not have any tax positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease on or before December 31, 2017.2020.


Excess foreign tax credits have been generated and are available to offset United States federal income taxes. At December 31, 2016, we had foreign tax credit carryforwards of approximately $2.3 million, which expire in 2017.



We had a $1.7 million and $0.5 million valuation allowance against the foreign tax credit carryforwards as of December 31, 2016 and 2015 respectively. Approximately $1.8 million of foreign tax credits was previously reflected as an offset to liabilities for unrecognized tax benefits in recognition of the estimated impact the resolution of material uncertain tax positions could have with respect to utilization. Subsequent to the settlement agreement in principle that was reached with IRS Appeals in the first quarter of 2016, it has been determined to be more beneficial to deduct the $1.8 million of foreign tax credits. In determining the valuation allowance amount, we compared the tax benefit associated with either deducting foreign taxes or claiming them as credits. The tax benefit of being able to deduct such foreign tax credits is approximately $0.6 million resulting in an increase to the valuation allowance of approximately $1.2 million.

State tax credits have been generated and are available to offset future state income taxes. At December 31, 20162019, we had the following state tax credit carryforwards (in thousands):
State Tax Credit CarryforwardsExpiration Year
ITC$23,060
2023to2041
Research and development$201
No expiration

State Tax Credit CarryforwardsExpiration Year
Investment tax credit$19,765
2023to2036
Research and development$167
No expiration


As of December 31, 2016,2019, we had a $6.6$9 million valuation allowance against the state tax credit carryforwards. The re-evaluation of our ability to utilize such credits resulted in an increase of the valuation allowance of approximately $3.6 million of which approximately $1.9 million resulted in an increase to tax expense. The remaining $1.7 million increase is attributable to our regulated business and is being accounted for under the deferral method whereby the credits are amortized to tax expense over the estimated useful life of the underlying asset that generated the credit. The valuation allowance adjustment was primarily attributable to the impact of lower projected apportionment factors resulting in decreased state taxable income in years beyond 2016. Ultimate usage of these credits depends upon our future tax filings. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the state tax credit carryforwards, the offsetting amount will affect tax expense.





(16)    OTHER COMPREHENSIVE INCOME


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


The following table details reclassifications out of AOCI and into net income. The amounts in parentheses below indicate decreases to net income in the Consolidated Statements of Income (Loss) for the period, net of tax (in thousands):
 Location on the Consolidated Statements of IncomeAmount Reclassified from AOCI
December 31, 2019December 31, 2018
Gains and (losses) on cash flow hedges:   
Interest rate swapsInterest expense$(2,851)$(2,851)
Commodity contractsFuel, purchased power and cost of natural gas sold417
(130)
  (2,434)(2,981)
Income taxIncome tax benefit (expense)611
630
Total reclassification adjustments related to cash flow hedges, net of tax $(1,823)$(2,351)
    
Amortization of components of defined benefit plans:   
Prior service costOperations and maintenance$77
$178
    
Actuarial gain (loss)Operations and maintenance(745)(2,487)
  (668)(2,309)
Income taxIncome tax benefit (expense)(453)543
Total reclassification adjustments related to defined benefit plans, net of tax $(1,121)$(1,766)
    
Total reclassifications $(2,944)$(4,117)

 Location on the Consolidated Statements of Income (Loss)Amount Reclassified from AOCI
December 31, 2016December 31, 2015
Gains and (losses) on cash flow hedges:   
Interest rate swapsInterest expense$(3,899)$(3,647)
Commodity contractsRevenue11,019
14,460
Commodity contracts
Fuel, purchased power and cost of natural gas sold

(14)—
  7,106
10,813
Income taxIncome tax benefit (expense)(2,702)(4,271)
Total reclassification adjustments related to cash flow hedges, net of tax $4,404
$6,542
    
Amortization of components of defined benefit plans:   
Prior service costOperations and maintenance$221
$238
Actuarial gain (loss)Operations and maintenance(1,978)(2,822)
  (1,757)(2,584)
Income taxIncome tax benefit (expense)533
884
Total reclassification adjustments related to defined benefit plans, net of tax $(1,224)$(1,700)
Total reclassifications $3,180
$4,842






Balances by classification included within AOCI, net of tax on the accompanying Consolidated Balance Sheets were as follows (in thousands):
 Derivatives Designated as Cash Flow Hedges  
 Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
As of December 31, 2018$(17,307)$328
$(9,937)$(26,916)
Other comprehensive income (loss)    
before reclassifications—
(422)(6,261)(6,683)
Amounts reclassified from AOCI2,185
(362)1,121
2,944
As of December 31, 2019$(15,122)$(456)$(15,077)$(30,655)
     
 Derivatives Designated as Cash Flow Hedges  
 Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
As of December 31, 2017$(19,581)$(518)$(21,103)$(41,202)
Other comprehensive income (loss)    
before reclassifications—
755
2,155
2,910
Amounts reclassified from AOCI2,252
99
1,766
4,117
Reclassification to regulatory asset—
—
6,519
6,519
Reclassification of certain tax effects from AOCI22
(8)726
740
As of December 31, 2018$(17,307)$328
$(9,937)$(26,916)

 Derivatives Designated as Cash Flow Hedges  
 Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
As of December 31, 2015$(341)$7,066
$(15,780)$(9,055)
Other comprehensive income (loss)    
before reclassifications(20,302)(361)(1,985)(22,648)
Amounts reclassified from AOCI2,534
(6,938)1,224
(3,180)
As of December 31, 2016$(18,109)$(233)$(16,541)$(34,883)
     
 Derivatives Designated as Cash Flow Hedges  
 Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
As of December 31, 2014$(4,930)$10,023
$(20,137)$(15,044)
Other comprehensive income (loss)    
before reclassifications2,290
5,884
2,657
10,831
Amounts reclassified from AOCI2,299
(8,841)1,700
(4,842)
As of December 31, 2015$(341)$7,066
$(15,780)$(9,055)



(17)    SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION


Years ended December 31,2019 2018 2017
 (in thousands)
Non-cash investing activities and financing from continuing operations -     
Accrued property, plant and equipment purchases at December 31$91,491
 $69,017
 $28,191
Increase (decrease) in capitalized assets associated with asset retirement obligations$5,044
 $2,625
 $3,198
      
Cash (paid) refunded during the period for continuing operations-     
Interest (net of amounts capitalized)$(131,774) $(137,965) $(132,428)
Income taxes (paid) refunded$4,682
 $(14,730) $1,775

Years ended December 31,2016 2015 2014
 (in thousands)
Non-cash investing activities and financing from continuing operations -     
Property, plant and equipment acquired with accrued liabilities$29,082
 $40,250
 $52,584
Increase (decrease) in capitalized assets associated with asset retirement obligations$8,577
 $(518) $(5,634)
      
Cash (paid) refunded during the period for continuing operations-     
Interest (net of amount capitalized)$(112,925) $(77,810) $(69,239)
Income taxes, net$(1,156) $(1,202) $(413)





(18)    EMPLOYEE BENEFIT PLANS

On February 12, 2016, as disclosed in Note 2, we completed the acquisition of SourceGas, adding an additional defined benefit pension plan, two additional defined benefit healthcare postretirement plans and a 401K retirement savings plan to cover employees of the utilities acquired. Benefits under these plans are determined based on each employee’s compensation, years of service, and/or age at retirement, among other factors.

In accordance with accounting standards, the SourceGas benefit liabilities were re-measured as of February 11, 2016. In addition, prior service costs not previously expensed were reclassified to a Regulatory asset and will be amortized over the average remaining service life of the plans.

Amounts recognized in the Condensed Consolidated Balance Sheets upon the February 12, 2016 acquisition are (in thousands):

 Defined Benefit Pension PlanNon-Pension Defined Benefit Postretirement Plans
   
Postretirement benefit obligation$22,187
$11,751


Defined Contribution Plans


We sponsor a 401(k) retirement savings plansplan (the 401(k) Plans)Plan). Participants in the 401(k) PlansPlan may elect to invest a portion of their eligible compensation toin the 401(k) Plan up to the maximum amounts established by the IRS. The 401(k) Plans providePlan provides employees the opportunity to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis.

The 401(k) Plans providePlan provides a Company Matching Contributionmatching contribution for all eligible participants and for certainparticipants. Certain eligible participants who are not currently accruing a benefit in the Pension Plan also receive a Company Retirement Contributionretirement contribution based on the participant’s age and years of service. Vesting of all Company and matching contributions ranges from immediate vesting to graduated vestingoccurs at 20% per year with 100% vesting when the participant has 5 years of service with the Company.


Defined Benefit Pension Plans (Pension Plans)Plan


During 2016 we maintained threeWe have one defined benefit pension plans, BHC Pension Plan, Black Hills Utility Holding, Inc. Pension Plan and SourceGas Retirement Plan that as of December 31, 2016 were merged into one single plan, the Black Hills Retirement Plan.Plan (Pension Plan). The Pension Plans coverPlan covers certain eligible employees of the Company. The benefits for the Pension PlansPlan are based on years of service and calculations of average earnings during a specific time period prior to retirement. All threeThe Pension Plans have beenPlan is closed to new employees and frozen for certain employees who did not meet age and service based criteria.


Black Hills RetirementThe Pension Plan assets are held in a Master Trust. Due to the plan merger on December 31, 2016, reporting beginning in 2017 will no longer represent an undivided interest in the Master Trust. Our Board of Directors has approved the Plans’Pension Plan’s investment policy. The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of our obligations to the Pension Plans’Plan’s beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a portfolio strategy that will provide liquidity to meet the Plans’Pension Plan’s benefit payment obligations. The Pension Plans’Plan’s assets consist primarily of equity, fixed income and hedged investments.


The expected rate of return on pension planthe Pension Plan assets is determined by reviewing the historical and expected returns of both equity and fixed income markets, taking into account asset allocation, the correlation between asset class returns, and the mix of active and passive investments. The Pension Plan utilizes a dynamic asset allocation where the target range to return-seeking and liability-hedging assets is determined based on a targeted asset allocation range determined by the funded ratiostatus of the plan.Plan. As of December 31, 2016,2019, the expected rate of return on pension plan assets iswas based on the targeted asset allocation range of 40% 29%to 50% equity securities37% return-seeking assets and 50%63% to 60% fixed-income securities and the expected rate of return from these asset categories. The expected rate of return on other postretirement plan assets is based on the targeted asset allocation range of 30% to 40% equity securities and 60% to 70% fixed-income securities and the expected rate of return from these asset categories. The expected return on plan assets for other postretirement benefits reflects insurance-related investment costs.71% liability-hedging assets.


The expected long-term rate of return for investments was 6.75% for the BHC Pension Plan and Black Hills Utility Holding, Inc. Plan 2016 and 2015 plan years and 7.5% for the SourceGas Retirement Plan 2016 plan year. Our Pension Plan is funded in compliance with the federal government’s funding requirements.




Plan Assets


The percentages of total plan asset fair value by investment category for our Pension PlansPlan at December 31 were as follows:
 20192018
Equity20%17%
Real estate34
Fixed income7171
Cash13
Hedge funds55
Total100%100%

 20162015
Equity28%26%
Real estate55
Fixed income5759
Cash21
Hedge funds89
Total100%100%


Supplemental Non-qualified Defined Benefit Plans


We have various supplemental retirement plans for key executives of the Company. The plans are non-qualified defined benefit and defined contribution plans (Supplemental Plans). The Supplemental Plans are subject to various vesting schedules and are not funded by the Company.

Plan Assets

We do not fund our Supplemental Plans. We fund on a cash basis as benefits are paid.


Non-pension Defined Benefit Postretirement Healthcare PlansPlan


With the addition of the two SourceGas Postretirement Healthcare Plans, BHC now sponsors fivea retiree healthcare plansplan (Healthcare Plans)Plan) for employees who meet certain age and service requirements at retirement. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. A portion of the Healthcare Plans isPlan for participating business units are pre-funded via VEBAs andVEBA trusts. Pre-65 retirees as well as a Grantor Trust. Effective January 1, 2014, health caregrandfathered group of post-65 retirees receive their retiree medical benefits through the Black Hills self-insured retiree medical plans. Healthcare coverage for Medicare-eligible retirees is provided through an individual market healthcare exchange for BHC and Black Hills Utility Holdings retirees. SourceGas retirees do not participate in the individual market healthcare exchange; therefore, all permissible health claims are paid under the self-insured plan.exchange.


Plan Assets


We fund the Healthcare PlansPlan on a cash basis as benefits are paid. The Black Hills Utility Holding and SourceGas Postretirement - AWG PlansCorporation Retiree Medical Plan provides for partial pre-funding via VEBAs and a Grantor Trust.VEBA trusts. Assets related to this pre-funding are held in trust and are for the benefit of the union and non-union employees located in the states of Arkansas, KansasIowa and Iowa.Kansas. We do not pre-fund the Healthcare PlansPlan for those employees outside Arkansas, KansasIowa and Iowa.Kansas.




Plan Contributions


Contributions to the Pension PlansPlan are cash contributions made directly to the Master Trust. Healthcare and Supplemental Plan contributions are made in the form of benefit payments. Healthcare benefits include company and participant paid premiums. Contributions for the years ended December 31 were as follows (in thousands):
 20162015
Defined Contribution Plan  
Company Retirement Contribution$9,632
$5,564
Matching contributions$9,645
$9,616
 20192018
Defined Contribution Plan  
Company retirement contributions$9,714
$8,766
Company matching contributions$14,558
$13,559


2016201520192018
Defined Benefit Plans  
Defined Benefit Pension Plans$14,200
$10,200
Non-Pension Defined Benefit Postretirement Healthcare Plans$4,965
$3,771
Defined Benefit Pension Plan$12,700
$12,700
Non-Pension Defined Benefit Postretirement Healthcare Plan$7,033
$5,298
Supplemental Non-Qualified Defined Benefit Plans$1,565
$1,564
$2,344
$2,073


While we do not have required contributions, we expect to make approximately $10$13 million in contributions to our Defined Benefit Pension PlansPlan in 2017.2020.


Fair Value Measurements


Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect their placement within the fair value hierarchy levels.


The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands):
Defined Benefit Pension PlansDecember 31, 2016
Pension PlanDecember 31, 2019
Level 1 Level 2 Level 3 
NAV (a)
 TotalLevel 1 Level 2 Level 3 Total Investments Measured at Fair Value 
NAV (a)
 Total Investments
AXA Equitable General Fixed Income$—
 $1,325
 $—
 —
 $1,325
$—
 $60
 $—
 $60
 $—
 $60
Common Collective Trust - Cash and Cash Equivalents—
 5,307
 —
 —
 5,307
—
 7,054
 —
 7,054
 —
 7,054
Common Collective Trust - Equity—
 101,020
 —
 —
 101,020
—
 87,106
 —
 87,106
 —
 87,106
Common Collective Trust - Fixed Income—
 209,815
 —
 —
 209,815
—
 306,275
 —
 306,275
 —
 306,275
Common Collective Trust - Real Estate—
 2,349
 —
 15,563
 17,912
—
 —
 —
 —
 14,239
 14,239
Hedge Funds—
 —
 —
 29,316
 29,316
—
 —
 —
 —
 19,550
 19,550
Total investments measured at fair value$—
 $319,816
 $—
 $44,879
 $364,695
$—
 $400,495
 $—
 $400,495
 $33,789
 $434,284




Pension PlanDecember 31, 2018
 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value 
NAV (a)
 Total Investments
AXA Equitable General Fixed Income$—
 $1,867
 $—
 $1,867
 $—
 $1,867
Common Collective Trust - Cash and Cash Equivalents—
 9,923
 —
 9,923
 —
 9,923
Common Collective Trust - Equity—
 67,457
 —
 67,457
 —
 67,457
Common Collective Trust - Fixed Income—
 279,148
 —
 279,148
 —
 279,148
Common Collective Trust - Real Estate—
 67
 —
 67
 13,551
 13,618
Hedge Funds—
 —
 —
 —
 18,783
 18,783
Total investments measured at fair value$—
 $358,462
 $—
 $358,462
 $32,334
 $390,796
Defined Benefit Pension PlansDecember 31, 2015
 Level 1 Level 2 Level 3 
NAV (a)
 Total
AXA Equitable General Fixed Income$—
 $1,072
 $—
 $—
 $1,072
Common Collective Trust - Cash and Cash Equivalents—
 1,556
 —
 —
 1,556
Common Collective Trust - Equity—
 74,885
 —
 —
 74,885
Common Collective Trust - Fixed Income—
 172,016
 —
 —
 172,016
Common Collective Trust - Real Estate—
 2,204
 —
 11,143
 13,347
Hedge Funds—
 —
 —
 25,746
 25,746
Total investments measured at fair value$—
 $251,733
 $—
 $36,889
 $288,622

_____________
(a)Certain investments that are measured at fair value using Net Asset Value “NAV”NAV per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plans’plan’s benefit obligations and fair value of plan assets above.


Non-pension Defined Benefit Postretirement Healthcare PlansDecember 31, 2016
 Level 1 Level 2 Level 3 Total
Cash and Cash Equivalents$111
 $—
 $—
 $111
Equity Securities1,154
 —
 —
 1,154
Registered Investment Company Trust - Money Market Mutual Fund—
 4,732
 —
 4,732
Intermediate-term Bond—
 2,473
 —
 2,473
Total investments measured at fair value$1,265
 $7,205
 $—
 $8,470
Non-pension Defined Benefit Postretirement Healthcare PlanDecember 31, 2019
 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value Total Investments
Cash and Cash Equivalents$8,305
 $—
 $—
 $8,305
 $8,305
Total investments measured at fair value$8,305
 $—
 $—
 $8,305
 $8,305


Non-pension Defined Benefit Postretirement Healthcare PlanDecember 31, 2018
 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value Total Investments
Cash and Cash Equivalents$4,873
 $—
 $—
 $4,873
 $4,873
Equity Securities1,005
 —
 —
 1,005
 1,005
Intermediate-term Bond—
 2,284
 —
 2,284
 2,284
Total investments measured at fair value$5,878
 $2,284
 $—
 $8,162
 $8,162

Non-pension Defined Benefit Postretirement Healthcare PlansDecember 31, 2015
 Level 1 Level 2 Level 3 Total
Registered Investment Company Trust - Money Market Mutual Fund$—
 $4,681
 $—
 $4,681
Total investments measured at fair value$—
 $4,681
 $—
 $4,681



Additional information about assets of the Benefit Plans,benefit plans, including methods and assumptions used to estimate the fair value of these assets, is as follows:


Cash and Cash Equivalents: This represents an investment in Invesco Treasury Portfolio, which is a short-term investment trust, as well as an investment in Northern Institutional Government Assets Portfolio, which is described as a government money market fund. As shares held reflect quoted prices in an active market, they are categorized as Level 1.

Equity Securities: These represent investments in a combination of equity positions for mainly large cap core allocation and Exchange Trade Funds (EFTs) for diversification into the other sectors of the economy. EFTs are a basket of securities traded like individual stocks on the exchange. Value of equity securities held at year end are based on published market quotations of active markets. The ETF funds can be redeemed on a daily basis at their market price and have no redemption restrictions. As shares held reflect quoted prices in an active market, they are categorized as Level 1.

Intermediate-term bond: This is comprised of a diversified pool of high quality, individual municipal bonds. Pricing is evaluated using multi-dimensional relational models, as well as a series of matrices using Standard Inputs, including Municipal Securities Rule Making Board (MSRB) reported trades and material event notices, plus Municipal Market Data (MMD) benchmark yields and new issue data. As the models use observable inputs and standard data, the investments are categorized as Level 2.



AXA Equitable General Fixed Income Fund: This fund is a diversified portfolio, primarily composed of fixed income instruments. Assets are invested in long-term holdings, such as commercial, agricultural and residential mortgages, publicly traded and privately placeplaced bonds and real estate as well as short-term bonds. Fair values of mortgage loans are measured by discounting future contractual cash flows to be received on the mortgage loans using interest rates at whichof loans with similar characteristics have.characteristics. The discount rate is derived from taking the appropriate U.S. Treasury rate with a like term. The fair value of public fixed maturity securities are generally based on prices obtained from independent valuation service providers with reasonableness prices compared with directly observable market trades. The fair value of privately placed securities are determined using a discounted cash flow model. These models use observable inputs with a discount rate based upon the average of spread surveys collected from private market intermediaries and industry sector of the issuer. The Plan’s investments in the AXA Equitable General Fixed Income Fund are categorized as Level 2.


Common Collective Trust Funds: These funds are valued based upon the redemption price of units held by the Plan, which is based on the current fair value of the common collective trust funds’ underlying assets. Unit values are determined by the financial institution sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the valuation dates. The Plan’s investments in common collective trust funds, with the exception of shares of the common collective trust-real estate are categorized as Level 2.
Common Collective Trust-Real Estate Fund: This fund is valued based on various factors of the underlying real estate properties, including market rent, market rent growth, occupancy levels, etc. As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the trustee, along with the annual schedule of investments and rely on these reports for pricing the units of the fund. TheSome of the funds without participant withdrawal limitations are categorized as Level 2.
The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance.guidance:
Common Collective Trust-Real Estate Fund: This is the same fund is valued based on various factors of the underlying real estate properties, including market rent, market rent growth, occupancy levels, etc. As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisersas above except that are members of the Appraisal Institute, with professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the trustee, along with the annual schedule of investments, and rely on these reports for pricing the units of the fund. Certaincertain of the funds’ assets contain participant withdrawal policy.policies with restrictions on redemption and are therefore not included in the fair value hierarchy.
Hedge Funds: HedgeThese funds represent investments in other investment funds that seek a return utilizing a number of diverse investment strategies. The strategies, when combined, aim to reduce volatility and risk while attempting to deliver positive returns under all market conditions. Amounts are reported on a one-month lag. The fair value of hedge funds is determined using net asset value per share based on the fair value of the hedge fund’s underlying investments. Generally,20% of the shares may be redeemed at the end of each month with a 10-day notice and full redemptions are available at the end of each quarter with a 65 day30-day notice and areis limited to a percentage of the total net assetassets value of the fund. The net asset values are based on the fair value of each fund’s underlying investments. There are no unfunded commitments related to these hedge funds.
Cash and Cash Equivalents: This represents an investment in Invesco Treasury Portfolio, which is a short-term investment trust, as well as an investment in Northern Institutional Government Assets Portfolio, which is a government money market fund. As shares held reflect quoted prices in an active market, they are categorized as Level 1.



Equity Securities: These represent investments in a combination of equity positions for mainly large cap core allocation and Exchange Trade Funds (ETFs) for diversification into the other sectors of the economy. ETFs are a basket of securities traded like individual stocks on the exchange. Value of equity securities held at year end are based on published market quotations of active markets. The ETF funds can be redeemed on a daily basis at their market price and have no redemption restrictions. As shares held reflect quoted prices in an active market, they are categorized as Level 1.

Intermediate-term Bond: This is comprised of a diversified pool of high quality, individual municipal bonds. Pricing is evaluated using multi-dimensional relational models, as well as a series of matrices using Standard Inputs, including Municipal Securities Rule Making Board (MSRB) reported trades and material event notices, plus Municipal Market Data (MMD) benchmark yields and new issue data. As the models use observable inputs and standard data, the investments are categorized as Level 2.
Other Plan Information


The following tables provide a reconciliation of the employee benefit plan obligations, fair value of assets and amounts recognized in the statement of financial position,Consolidated Balance Sheets, components of the net periodic expense and elements of AOCI (in thousands):AOCI:


Benefit Obligations
 Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan
As of December 31 (in thousands),20192018 20192018 20192018
Change in benefit obligation:        
Projected benefit obligation at beginning of year$445,381
$474,725
 $43,010
$45,112
 $60,817
$69,339
Service cost5,383
6,834
 4,995
1,764
 1,815
2,291
Interest cost17,374
15,470
 1,295
1,170
 2,247
2,085
Actuarial (gain) loss56,384
(31,340) 7,132
(2,963) 5,976
(9,045)
Benefits paid(39,146)(20,308) (2,344)(2,073) (7,033)(5,298)
Plan participants’ contributions—
—
 —
—
 1,455
1,445
Projected benefit obligation at end of year$485,376
$445,381
 $54,088
$43,010
 $65,277
$60,817

 Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Retirement Plans Non-pension Defined Benefit Postretirement Plans
 20162015 20162015 20162015
Change in benefit obligation:        
Projected benefit obligation at beginning of year$356,575
$377,772
 $40,219
$41,211
 $48,077
$49,042
Transfer from SourceGas Acquisition75,254
—
 —
—
 15,091
—
Service cost7,619
6,093
 2,099
1,300
 1,757
1,808
Interest cost15,743
15,522
 1,257
1,455
 1,942
1,801
Actuarial (gain) loss (a)
7,001
(28,229) 2,049
(2,072) 2,808
(1,206)
Amendments—
—
 —
—
 2,203
—
Benefits paid(22,013)(14,583) (1,755)(1,675) (4,965)(3,771)
Medicare Part D accrued—
—
 —
—
 —
(178)
Plan participants’ contributions—
—
 —
—
 1,110
581
Projected benefit obligation at end of year$440,179
$356,575
 $43,869
$40,219
 $68,023
$48,077

____________________
(a)Change from 2015 reflects a decrease in the discount rate offset by increased asset returns and a change in the mortality tables used in employee benefit plan estimates.

Employee Benefit Plan Assets
Defined Benefit
Pension Plans
 Supplemental Non-qualified Defined Benefit Retirement Plans 
Non-pension Defined Benefit Postretirement Plans (a)
Defined Benefit
Pension Plan
 Supplemental Non-qualified Defined Benefit Plans 
Non-pension Defined Benefit Postretirement Healthcare Plan (a)
20162015 20162015 20162015
     
As of December 31 (in thousands),20192018 20192018 20192018
Change in fair value of plan assets:     
Beginning fair value of plan assets$288,622
$299,533
 $—
$—
 $4,681
$4,705
$390,796
$416,343
 $—
$—
 $8,162
$8,621
Transfer from SourceGas Acquisition53,067
—
 —
—
 3,340
—
Investment income (loss)30,819
(6,528) —
—
 256
(9)69,934
(17,939) —
—
 260
(149)
Employer contributions14,200
10,200
 —
—
 4,048
3,175
12,700
12,700
 2,344
2,073
 5,461
3,543
Retiree contributions—
—
 —
—
 1,110
581
—
—
 —
—
 1,455
1,445
Benefits paid(22,013)(14,583) —
—
 (4,965)(3,771)(39,146)(20,308) (2,344)(2,073) (7,033)(5,298)
Plan administrative expenses—
—
 —
—
 —
—
Ending fair value of plan assets$364,695
$288,622
 $—
$—
 $8,470
$4,681
$434,284
$390,796
 $—
$—
 $8,305
$8,162
____________________
(a)Assets of VEBAs and Grantor Trust.VEBA trusts.




The funded status of the plans and the amounts recognized in the Consolidated Balance Sheets at December 31 consist of (in thousands):
 
Defined Benefit
Pension Plan
 
Supplemental
Non-qualified Defined Benefit Plans
Non-pension Defined Benefit Postretirement Healthcare Plan
 20192018 20192018 20192018
Regulatory assets$88,471
$82,919
 $—
$—
 $11,670
$6,655
Current liabilities$—
$—
 $1,420
$1,463
 $4,802
$3,885
Non-current assets$—
$—
 $—
$—
 $—
$249
Non-current liabilities$51,093
$54,585
 $51,243
$41,547
 $52,136
$49,015
Regulatory liabilities$3,524
$4,620
 $—
$—
 $4,088
$5,207

 
Defined Benefit
Pension Plans
 
Supplemental
Non-qualified Defined Benefit Plans
Non-pension Defined Benefit Postretirement Healthcare Plans
 20162015 20162015 20162015
Regulatory assets$66,640
$68,915
 $—
$—
 $11,401
$6,464
Current liabilities$—
$—
 $1,583
$1,568
 $4,360
$3,543
Non-current assets$—
$—
 $—
$—
 $21
$23
Non-current liabilities$75,484
$67,953
 $42,286
$38,651
 $55,214
$39,855
Regulatory liabilities$5,195
$—
 $—
$—
 $3,419
$3,209


Accumulated Benefit Obligation

(in thousands)
Defined Benefit
Pension Plans
 
Supplemental
Non-qualified Defined Benefit Plans
Non-pension Defined Benefit Postretirement Healthcare Plans
20162015 20162015 20162015
Defined Benefit
Pension Plan
 
Supplemental
Non-qualified Defined Benefit Plans
Non-pension Defined Benefit Postretirement Healthcare Plan
As of December 31 (in thousands)20192018 20192018 20192018
Accumulated Benefit Obligation(a)
$416,786
$334,923
 $32,090
$30,558
 $68,023
$48,077
$470,615
$428,851
 $49,241
$40,530
 $65,277
$60,817

____________________
(a)The Defined Benefit Pension Plans Accumulated Benefit Obligation for 2016 represents the obligation for the merged Black Hills Retirement Plan. The 2015 obligation represents the BHC Pension Plan and Black Hills Utility Holding, Inc. Pension Plan and has been combined for presentation purposes to conform to the 2016 merged plan. The Non-pension Defined Benefit Retirement Healthcare Plans Accumulated Benefit Obligation for 2016 represents that obligation for the five postretirement plans maintained by BHC. The 2015 obligation represents the three postretirement plans maintained by BHC.

Components of Net Periodic Expense

(in thousands)
Defined Benefit
Pension Plans
 
Supplemental
Non-qualified Defined Benefit Plans
 Non-pension Defined Benefit Postretirement Healthcare Plans
 201620152014 201620152014 201620152014
Service cost$7,619
$6,093
$5,448
 $1,335
$1,380
$1,498
 $1,757
$1,808
$1,700
Interest cost15,743
15,522
15,852
 1,257
1,455
1,447
 1,942
1,801
1,919
Expected return on assets(23,062)(19,470)(18,065) —
—
—
 (279)(131)(85)
Net amortization of prior service cost58
58
62
 2
2
2
 (428)(428)(428)
Recognized net actuarial loss (gain)7,173
11,037
4,806
 829
1,081
498
 335
408
160
Settlement Expense(a)
10
—
—
 —
—
—
 —
—
—
Net periodic expense$7,541
$13,240
$8,103
 $3,423
$3,918
$3,445
 $3,327
$3,458
$3,266
Net periodic expense consisted of the following for the year ended December 31 (in thousands):
____________________
 
Defined Benefit
Pension Plan
 
Supplemental
Non-qualified Defined Benefit Plans
 Non-pension Defined Benefit Postretirement Healthcare Plan
 201920182017 201920182017 201920182017
Service cost$5,383
$6,834
$7,034
 $4,995
$1,764
$1,546
 $1,815
$2,291
$2,300
Interest cost17,374
15,470
15,520
 1,295
1,170
1,276
 2,247
2,085
2,141
Expected return on assets(24,401)(24,741)(24,517) —
—
—
 (230)(315)(315)
Net amortization of prior service cost26
58
58
 2
2
2
 (398)(398)(411)
Recognized net actuarial loss (gain)3,763
8,632
4,007
 535
1,000
1,001
 —
216
499
Net periodic expense$2,145
$6,253
$2,102
 $6,827
$3,936
$3,825
 $3,434
$3,879
$4,214
(a)Settlement expense is the result of lump-sum payments on the SourceGas Retirement Plan in excess of interest and service costs for the year.





For the years ended December 31, 2019 and 2018, service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other expense on the Consolidated Statements of Income. For the year ended December 31, 2017, service costs and non-service costs were recorded in Operations and maintenance expense. Because non-service costs were not considered material for the year ended December 31, 2017, they were not reclassified on the Consolidated Statements of Income.


AOCI


For defined benefit plans, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands):
 
Defined Benefit
Pension Plan
 
Supplemental
Non-qualified Defined Benefit Plans
Non-pension Defined Benefit Postretirement Healthcare Plan
 20192018 20192018 20192018
Net (gain) loss$5,322
$11,967
 $9,893
$4,668
 $90
$860
Prior service cost (gain)—
1
 2
3
 (230)(317)
Reclassification of certain tax effects from AOCI—
(594) —
(87) —
(45)
Reclassification to regulatory asset—
(5,600) —
—
 —
(919)
Total AOCI$5,322
$5,774
 $9,895
$4,584
 $(140)$(421)

 
Defined Benefit
Pension Plans
 
Supplemental
Non-qualified Defined Benefit Plans
Non-pension Defined Benefit Postretirement Healthcare Plans
 20162015 20162015 20162015
Net (gain) loss$8,472
$8,777
 $7,132
$6,339
 $1,595
$1,704
Prior service cost (gain)31
41
 5
6
 (694)(1,087)
Total AOCI$8,503
$8,818
 $7,137
$6,345
 $901
$617

The amounts in AOCI, Regulatory assets or Regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2017 are as follows (in thousands):
 Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans
Net loss$2,604
 $572
 $325
Prior service cost (credit)38
 1
 (368)
Total net periodic benefit cost expected to be recognized during calendar year 2017$2,642
 $573
 $(43)


Assumptions
Defined Benefit
Pension Plans
 
Supplemental
Non-qualified Defined Benefit Plans
 Non-pension Defined Benefit Postretirement Healthcare Plans
Defined Benefit
Pension Plan
 
Supplemental
Non-qualified Defined Benefit Plans
 Non-pension Defined Benefit Postretirement Healthcare Plan
Weighted-average assumptions used to determine benefit obligations:201620152014 201620152014 201620152014201920182017 201920182017 201920182017
          
Discount rate4.27%4.58%4.19% 4.02%4.28%4.19% 3.96%4.17%3.82%3.27%4.40%3.71% 3.14%4.34%3.56% 3.15%4.28%3.60%
Rate of increase in compensation levels3.47%3.51%3.76% 5.00%5.00%5.00% N/A
N/A
N/A
3.49%3.52%3.43% 5.00%5.00%5.00% N/A
N/A
N/A


Defined Benefit
Pension Plans
 
Supplemental
Non-qualified Defined Benefit Plans
 Non-pension Defined Benefit Postretirement Healthcare Plans
Defined Benefit
Pension Plan
 
Supplemental
Non-qualified Defined Benefit Plans
 Non-pension Defined Benefit Postretirement Healthcare Plan
Weighted-average assumptions used to determine net periodic benefit cost for plan year:201620152014 201620152014 201620152014201920182017 201920182017 201920182017
          
Discount rate (a)
4.50%4.19%5.04% 4.28%4.19%5.03% 4.18%3.82%4.46%4.40%3.71%4.27% 4.34%3.67%4.02% 4.28%3.60%4.05%
Expected long-term rate of return on assets (b)
6.87%6.75%6.75% N/A
N/A
N/A
 3.83%3.00%2.00%6.00%6.25%6.75% N/A
N/A
N/A
 3.00%3.93%3.88%
Rate of increase in compensation levels3.42%3.76%3.76% 5.00%5.00%5.00% N/A
N/A
N/A
3.52%3.43%3.47% 5.00%5.00%5.00% N/A
N/A
N/A
_____________________________
(a)The estimated discount rate for the merged Black Hills RetirementDefined Benefit Pension Plan is 4.27%3.27% for the calculation of the 20172020 net periodic pension costs.
(b)
The expected rate of return on plan assets is 6.75%5.25% for the calculation of the 20172020 net periodic pension cost.



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

 20192018
Trend Rate - Medical  
Pre-65 for next year - All Plans6.40%6.70%
Pre-65 Ultimate trend rate - Black Hills Corp4.50%4.50%
Trend Year20272027
   
Post-65 for next year - All Plans4.92%4.94%
Post-65 Ultimate trend rate - Black Hills Corp4.50%4.50%
Trend Year20282026

 
2016 (a)
2015
Trend Rate - Medical  
Pre-65 for next year - All Plans6.10%6.35%
Pre-65 Ultimate trend rate - Black Hills Corp4.50%4.50%
Trend Year20242024
   
Post-65 for next year - All Plans5.10%5.20%
Post-65 Ultimate trend rate - Black Hills Corp4.50%4.50%
Trend Year20232023
_____________________________
(a)The 2016 Medical Trend Rates include the two additional non-pension defined benefit postretirement plans from SourceGas.

We do not pre-fund our supplemental plans or three of the five healthcare plans. The table below shows the expected impacts of an increase or decrease to our healthcare trend rate for our Healthcare Plans (in thousands):
Change in Assumed Trend Rate 
Impact on December 31, 2016 Accumulated Postretirement
Benefit Obligation
 
Impact on 2017 Service
and Interest Cost
Increase 1% $2,569
 $156
Decrease 1% $(2,191) $(131)

Beginning in 2016, the Company changed the method used to estimate the service and interest cost components of the net periodic pension, supplemental non-qualified defined benefit and other postretirement benefit costs. The new method uses the spot yield curve approach to estimate the service and interest costs by applying the specific spot rates along the yield curve used to determine the benefit obligations to relevant projected cash outflows. Previously, those costs were determined using a single weighted-average discount rate. The change does not affect the measurement of the total benefit obligations as the change in service and interest costs offsets the actuarial gains and losses recorded in other comprehensive income. The new method provides a more precise measure of interest and service costs by improving the correlation between the projected benefit cash flows and the discrete spot yield curve rates. The Company accounted for this change as a change in estimate prospectively beginning in the first quarter of 2016. See “Pension and Postretirement Benefit Obligations” within our Critical Accounting Policies in Item 7 on Form 10-K for additional details.


The following benefit payments to employees, which reflect future service, are expected to be paid (in thousands):
 Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan
2020$24,586
 $1,420
 $5,919
2021$25,774
 $1,786
 $5,974
2022$26,728
 $2,167
 $5,790
2023$27,795
 $2,223
 $5,521
2024$28,547
 $2,412
 $5,329
2025-2029$145,426
 $14,689
 $23,030

 Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-Pension Defined Benefit Postretirement Healthcare Plans
2017$21,355
 $1,583
 $5,504
2018$21,566
 $1,809
 $5,779
2019$23,010
 $1,921
 $5,886
2020$27,028
 $1,634
 $5,983
2021$27,614
 $1,836
 $5,931
2022-2026$149,893
 $11,009
 $27,585





(19)    COMMITMENTS AND CONTINGENCIES


Power Purchase and Transmission Services Agreements


Through our subsidiaries, we have the following significant long-term power purchase contracts with non-affiliated third-parties:

•
Colorado Electric’s PPA with PRPA to purchase up to 60 MW of wind energy upon construction of a new wind project, which is expected in mid-2020. This agreement will expire May 31, 2030.

Colorado Electric’s PPA with PRPA to purchase 25 MW of unit contingent energy. This agreement will expire June 30, 2024.

South Dakota Electric’s PPA with PacifiCorp, expiring December 31, 2023, for the purchase of 50 MW of electric capacity and energy from PacifiCorp’s system. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants.

South Dakota Electric’s firm point-to-point transmission service agreement with PacifiCorp expiring December 31, 2023. The agreement provides 50 MW of capacity and energy to be transmitted annually by PacifiCorp.

South Dakota Electric’s PPA with PRPA to purchase up to 12 MW of wind energy through PRPA’s agreement with Silver Sage. This agreement will expire September 30, 2029.

Wyoming Electric’s PPA with Happy Jack, expiring September 3, 2028, provides up to 30 MW of wind energy. Under a separate intercompany agreement, Wyoming Electric sells 50% of the facility output to South Dakota Electric.

Wyoming Electric’s PPA with Silver Sage, expiring September 30, 2029, provides up to 30 MW of wind energy. Under a separate intercompany agreement, Wyoming Electric sells 20 MW of energy from Silver Sage to South Dakota Electric.


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

South Dakota Electric’s PPA with PacifiCorp, expiring December 31, 2023, for the purchase of 50 MW of electric capacity and energy from PacifiCorp’s system. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants.

South Dakota Electric has a firm point-to-point transmission service agreement with PacifiCorp that expires December 31, 2023. The agreement provides 50 MW of capacity and energy to be transmitted annually by PacifiCorp.

Wyoming Electric’s PPA with Duke Energy’s Happy Jack wind site, expiring September 3, 2028, provides up to 30 MW of wind energy from Happy Jack to Wyoming Electric. Under a separate inter-company agreement, Wyoming Electric sells 50% of the facility output to South Dakota Electric.

Wyoming Electric’s PPA with Duke Energy’s Silver Sage wind site, expiring September 30, 2029, provides up to 30 MW of wind energy. Under a separate inter-company agreement, Wyoming Electric has agreed to sell 20 MW of energy from Silver Sage to South Dakota Electric.

Colorado Electric’s REPA with AltaGas expiring October 16, 2037, provides up to 14.5 MW of wind energy from the Busch Ranch Wind Farm in which Colorado Electric owns a 50% undivided ownership interest.


Costs under these power purchase contracts for the years ended December 31 were as follows (in thousands):
 201920182017
Colorado Electric PPA with PRPA - Unit Contingent Energy$1,802
$—
$—
Colorado Electric PPA Busch Ranch I (a)
$—
$—
$1,966
South Dakota Electric PPA with PacifiCorp$7,477
$13,681
$13,218
South Dakota Electric Transmission services agreement with PacifiCorp$1,741
$1,742
$1,671
South Dakota Electric PPA with PRPA$688
$223
$—
Wyoming Electric PPA with Happy Jack$3,936
$3,884
$3,846
Wyoming Electric PPA with Silver Sage$5,366
$5,376
$4,934
 201620152014
PPA with PacifiCorp$12,221
$13,990
$13,943
Transmission services agreement with PacifiCorp$1,428
$1,213
$1,227
PPA with Happy Jack$3,836
$3,155
$3,919
PPA with Silver Sage$4,949
$4,107
$4,798
Busch Ranch Wind Farm$2,071
$1,734
$1,998
PPAs with Cargill (a)
$10,995
$16,112
$9,286

________________
(a)PPAs with Cargill expired onOn December 31, 2016.11, 2018, Black Hills Electric Generation purchased a 50% ownership interest of the Busch Ranch I. Black Hills Electric Generation and Colorado Electric now collectively own 100% of the wind farm.


Power Purchase Agreements - Related Party

On November 26, 2019, Black Hills Electric Generation completed and placed in service Busch Ranch II. Black Hills Electric Generation provides the wind energy generated from Busch Ranch II to Colorado Electric under a new PPA, which expires in November 2044.

On December 11, 2018, Black Hills Electric Generation purchased a 50% ownership interest in Busch Ranch I. Black Hills Electric Generation provides its 14.5 MW share of energy from the wind farm to Colorado Electric through a PPA, which expires in October 2037.

Colorado Electric’s PPA with Black Hills Colorado IPP expiring on December 31, 2031, provides 200 MW of power to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines. Effective January 1, 2019, we changed how we account for this PPA at the segment level and now recognize on an accrual basis, rather than a finance lease. See Note 5 for additional information.

Other Gas Supply Agreements


Our Utilities also purchase natural gas, including transportation and storage capacity to meet customers’ needs, under short-term and long-term purchase contracts. These contracts extend to 2044.


Natural Gas Delivery Commitment

In 2012, we entered into a ten-year gas gathering and processing contract for natural gas production from our properties in the Piceance Basin in Colorado, under which we pay a gathering fee per Mcf. This take or pay contract requires us to pay the fee on a minimum of 20,000 Mcf per day, regardless of the volume delivered. The 10 year agreement expiring in 2024 became effective in first quarter of 2014 upon completion of the processing infrastructure capable of handling the committed volumes.



Purchase Commitments


We maintain natural gas supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated baseload gas volumes are established prior to the beginning of the month under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month based on requirements in accordance with the terms of the individual contract.


Our Gas Utilities segment has commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. A portion of our gas purchases are purchased under evergreen contracts and are therefore, for purposes of this disclosure, carried out for 60 days. At December 31, 2016,2019, the long-term commitments to purchase quantities of natural gas under contracts indexed to the following forward indices were as follows (in MMBtus):


 NNG-VenturaNWPL-Wyoming
20203,660,0001,520,000
20213,650,0001,510,000
20221,810,0001,510,000
202301,510,000
20240910,000
Thereafter00

 CIG RockiesEnable-EastNWPL-WyomingSSTAR-TEXOKOther
20175,549,427
620,300
1,208,000
457,399
44,913
2018—
584,000
1,208,000
—
—
2019—
584,000
720,000
—
—
2020—
585,600
—
—
—
2021—
388,800
—
—
—


Purchases under these contracts totaled $31$6.7 million, $48$27 million and $31$65 million for 2016, 20152019, 2018 and 2014,2017, respectively.


The following is a schedule of unconditional purchase obligations required under the power purchase, transmission services gathering commitments, coal and natural gas transportation and storage agreements (in thousands):
 Power purchase and transmission services agreementsNatural gas transportation and storage agreements
2020$25,476
$156,297
2021$11,678
$148,149
2022$11,678
$122,340
2023$11,678
$93,905
2024$2,738
$51,360
Thereafter$—
$126,147

 Power Purchase AgreementsTransportation, storage, gathering and coal agreements
2017$26,690
$136,607
2018$8,934
$120,123
2019$6,388
$87,210
2020$6,388
$82,247
2021$5,755
$75,424
Thereafter$11,509
$225,765


Future Purchase Agreement - Related Party


Wyoming Electric’sElectric has a PPA forwith Black Hills Wyoming expiring on December 31, 2022, which provides 60 MW of unit-contingent capacity and energy from Black Hills Wyoming’s Wygen I generating facility expiringfacility. 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, includes an option for2022. If approved, Black Hills Wyoming will continue to deliver 60 MW of energy to Wyoming Electric to purchase Black Hills Wyoming’s ownership in thefrom its Wygen I facility. The purchase price related to the option is $2.6 million per MW which is the equivalent per MW of the pre-construction estimated cost of the Wygen IIIpower plant which was completed in April 2010. This option purchase price is adjusted for capital additions and reduced by an amount equal to annual depreciation based on a 35-year life starting January 1, 2009. The purchase option would be subject2023, and continuing for an additional 20 years to WPSCDecember 31, 2042. On December 23, 2019, the Company filed a response to questions from the FERC and FERC approval in order to obtain regulatory treatment.awaits a decision from FERC.


Power Sales Agreements


Through our subsidiaries, we have the following significant long-term power sales contracts with non-affiliated third-parties:


•
During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, South Dakota Electric will provide MDU with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU. This agreement expires January 31, 2023.
During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, MDU will be provided with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU.


South Dakota Electric has an agreement to serveprovide MDU capacity and energy up to a maximum of 50 MW in excess of Wygen III ownership. This agreement expires December 31, 2023.




During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, weSouth Dakota Electric will provide the City of Gillette with its first 23 MW from our other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement which is renewed annually on September 3, South Dakota Electric will also provide the City of Gillette their operating component of spinning reserves.

South Dakota Electric has an amended agreement, effective January 1, 2019, to supply up to 20 MW of energy and capacity to MEAN under a PPA with MEAN expiring contract that expires May 31, 2023.2028. The contract terms are from June 1 through May 31 for each interval listed below. This contract is unit-contingent on up to 10 MW from Neil Simpson II and up to 10 MW from Wygen III based on the availability of these plants. Theour Neil Simpson II and Wygen III plants, with decreasing capacity purchase requirements decreasepurchased over the term of the agreement.
The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows:

Contract YearsTotal Contract Capacity Contingent Capacity Amounts on Wygen III Contingent Capacity Amounts on Neil Simpson II
2019-202015
MW 10
MW 5
MW
2020-202215
MW 7
MW 8
MW
2022-202315
MW 8
MW 7
MW
2023-202810
MW 5
MW 5
MW

Related Party Lease

Colorado Electric’s PPA with Black Hills Colorado IPP expiring on South Dakota Electric has an agreement that expires December 31, 2031, provides 2002021 to provide 50 MW of powerenergy to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines. This PPA is accounted for as a capital lease whereby Colorado Electric, as lessee, has included the combined-cycle turbines as property, plantMacquarie Energy, LLC during heavy and equipment along with the related lease obligation and Black Hills Colorado IPP, as lessor, has recorded a lease receivable. Segment revenue and expenses associated with the PPA have been impacted by the lease accounting. The effect of the lease accounting is eliminated in corporate consolidations.light load timing intervals.


Reimbursement Agreement


We have a reimbursement agreement in place with Wells Fargo on behalf of Wyoming Electric for the 2009A bonds of $10 million due in 2027 and the 2009B bonds of $7.0 million due in 2021. In the case of default, we hold the assumption of liability for drawings on Wyoming Electric’s Letter of Credit attached to these bonds.


Environmental Matters


We are subject to costs resulting from a number of federal, state and local laws and regulations which affect future planning and existing operations. TheyLaws and regulations can result in increased capital expenditures, operating and other costs as a result of compliance, remediation and monitoring obligations. Due to the environmental issues discussed below, we may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies.


Air

Our generation facilities are subject to federal, state and local laws and regulations relating to the protection of air quality. These laws and regulations cover, among other pollutants, carbon monoxide, SO2, NOx, mercury, hazardous air pollutants, particulate matter and GHG. Power generating facilities burning fossil fuels emit each of the foregoing pollutants and, therefore, are subject to substantial regulation and enforcement oversight by various governmental agencies.

Title IV of the Clean Air Act applies to several of our generation facilities, including the Neil Simpson II, Neil Simpson CT, Lange CT, Wygen I, Wygen II, Wygen III, Wyodak and Pueblo Airport Generating Station plants. Title IV of the Clean Air Act created an SO2 allowance trading program as part of the federal acid rain program. Without purchasing additional allowances, we currently hold sufficient allowances to satisfy Title IV at all such plants through 2046.

The EPA issued the Industrial and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants, with updates which imposed emission limits, fuel requirements and monitoring requirements. The rule had a compliance deadline of March 21, 2014. In anticipation of this rule we suspended operations at the Osage plant in October 2010 and as a result of this rule, we suspended operations at the Ben French facility on August 31, 2012. We permanently retired Ben French, Osage and Neil Simpson I on March 21, 2014. In conjunction with the Colorado Clean Air Clean Jobs Act, the CPUC issued an order approving the closure of the W.N. Clark facility no later than December 31, 2013. This facility suspended operations December 31, 2012 and was retired on December 31, 2013. The net book value of these plants was allowed regulatory accounting treatment and is recorded as a Regulatory Asset on the Consolidated Balance Sheet. The CPUC also approved a CPCN for the retirement of Pueblo Units #5 and #6 effective December 31, 2013.



Solid Waste Disposal

Various materials used at our facilities are subject to disposal regulations. Our Osage plant, permanently retired on March 21, 2014, had an on-site ash impoundment that was near capacity. An application to close the impoundment was approved on April 13, 2012. Site closure work was completed in 2013 with the state providing closure certification in 2014. Post closure monitoring activities will continue for 30 years following the closure certification date.

In September 2013, Osage also received a permit to close the small industrial rubble landfill. Site work was completed with the state providing closure certification in 2014. Post closure monitoring will continue for 30 years following the closure certification date.

Our W.N. Clark plant, which has been retired, previously delivered coal ash to a permitted, privately-owned landfill. While we do not believe that any substances from our solid waste disposal activities will pollute underground water, we can provide no assurance that pollution will not occur over time. In this event, we could incur material costs to mitigate any resulting damages.

Reclamation Liability


For our Pueblo Airport Generation site, we posted a bond of $4.1 million with the State of Colorado to cover the costs of remediation for a waste water containment pond permitted to provide wastewater storage and processing for this zero discharge facility. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.


Under itsour land leaseleases for Busch Ranch, Colorado Electric isour wind generation facilities, we are required to reclaim all land where it haswe have placed wind turbines. The reclamation liability isliabilities are recorded at the present value of the estimated future cost to reclaim the land.


Under its mining permit, WRDC is required to reclaim all land where it has mined coal reserves. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.


See Note 8 for additional information.


Manufactured Gas Processing


As a result of the Aquila Transaction,In 2008, we acquired whole and partial liabilities for several former manufactured gas processing sites in Nebraska and Iowa which were previously used to convert coal to natural gas. The acquisition provided for an insurance recovery, now valued at $1.5$1.1 million recorded in Other assets, non-current on our Consolidated Balance Sheets, which will be used to help offset remediation costs. We also have a $1.5 million regulatory asset for manufactured gas processing sites; see Note 13 for additional information.


As of December 31, 2019, our estimated liabilities for Iowa’s manufactured gas processing site currently range from approximately $2.6 million to $10 million for which we had $2.6 million accrued for remediation of the site as of December 31, 2019 included in Other deferred credits and other liabilities on our Consolidated Balance Sheets. The remediation cost estimate could change materially due to results of further investigations, actions of environmental agencies or the financial viability of other responsible parties.


In March 2011, Nebraska Gas executed an Allocation, Indemnification and Access Agreement with the successor to the former operatorFor additional information, see Environmental Matters in Item 1 of the Nebraska MGPs. Under this agreement, Nebraska Gas agreed to remediate the Blair and Plattsmouth sites in Nebraska. Subsequent to this transaction, Nebraska Gas enrolled Blair and Plattsmouth in Nebraska's Voluntary Cleanup Program. Site remediation was completed in September 2012. However, there was a potential for additional minimal remediation work at Plattsmouth where monitoring was required until 2015. Both Nebraska sites were required to monitor groundwater quality for a minimum two year period, ending in 2015. In late 2015, groundwater concentrations were proposed and approved by the Nebraska Department of Environmental Quality as meeting steady or declining pollution levels. We assembled our final removal action completion reports to formally close the site, and submitted reports to the Nebraska Department of Environmental Quality in December 2015. In 2016, we received state approval for “no further action” at both sites.Annual Report on Form 10-K.

As of December 31, 2016, our estimated liabilities for Iowa’s MGP sites currently range from approximately $2.6 million to $6.1 million for which we had $2.6 million accrued for remediation of sites as of December 31, 2016 included in Other deferred credits and other liabilities on our Consolidated Balance Sheets.

Prior to Black Hills Corporation's ownership, Aquila received rate orders that enabled recovery of environmental cleanup costs in certain jurisdictions. We anticipate recovery of these current and future costs would be allowed. Additionally, we may pursue recovery or agreements with other potentially responsible parties when and where permitted.



As a result of the SourceGas Transaction, we acquired potential liability for at least one former MGP site in McCook, Nebraska. The Nebraska Department of Environmental Quality conducted a limited assessment in 2012 which documented soil and groundwater impacts. However, there has been no directive from the state to pursue either remediation or further assessment. We are currently evaluating the potential for other Potential Responsible Parties and future comprehensive analysis to fully determine and delineate the extent of contamination. The assigned liability for this site cannot be determined at this time. However, based on the state’s assessment, we anticipate costs will be less than $1.0 million.


Legal Proceedings


In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in the consolidated financial statements to satisfy alleged liabilities are adequate in light of the probable and estimable contingencies. However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed, and to comply with applicable laws and regulations will not exceed the amounts reflected in the consolidated financial statements.


In the normal course of business, we enter into agreements that include indemnification in favor of third parties, such as information technology agreements, purchase and sale agreements and lease contracts.  We have also agreed to indemnify our directors, officers and employees in accordance with our articles of incorporation, as amended.  Certain agreements do not contain any limits on our liability and therefore, it is not possible to estimate our potential liability under these indemnifications.  In certain cases, we have recourse against third parties with respect to these indemnities.  Further, we maintain insurance policies that may provide coverage against certain claims under these indemnities.



(20)    GUARANTEES


We have entered into various agreements providing financial or performance assurance to third parties on behalf of certain of our subsidiaries. The agreements include indemnification for reclamation and surety bonds and a contract performance guarantee.


We had the following guarantees in place as of (in thousands):
Maximum Exposure at Maximum Exposure at 
Nature of GuaranteeDecember 31, 2016ExpirationDecember 31, 2019Expiration
Indemnification for subsidiary reclamation/surety bonds (a)
$57,105
Ongoing$55,527
Ongoing
Contract performance guarantee (b)
46,831
May 2020
$57,105
 $102,358
 
_______________________
(a)We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets.




(21)    OIL AND GAS RESERVES(Unaudited)

BHEP has operating and non-operating interests in 713 gross developed oil and gas wells in 9 states and holds leases on approximately 127,919 net acres.

Costs Incurred

Following is a summary of costs incurred in oil and gas property acquisition, exploration and development during the years ended December 31 (in thousands):
 201620152014
Acquisition of properties:   
Proved$—
$1,407
$4,881
Unproved910
669
5,056
Exploration costs1,102
35,434
54,355
Development costs4,657
128,998
52,262
Asset retirement obligations incurred—
566
68
Total costs incurred$6,669
$167,074
$116,622

Reserves

The following table summarizes BHEP’s quantities of proved developed and undeveloped oil, natural gas and NGL reserves, estimated using SEC-defined product prices, as of December 31, 2016, 2015 and 2014 and a reconciliation of the changes between these dates. These estimates are based on reserve reports by CG&A. Such reserve estimates are inherently imprecise and may be subject to revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.



Minor differences in amounts may result in the following tables relating to oil and gas reserves due to rounding.
 2016 2015 2014 
 OilGasNGL OilGasNGL OilGasNGL 
 (in Mbbls of oil and NGL, and MMcf of gas) 
Proved developed and undeveloped reserves:            
Balance at beginning of year3,450
73,412
1,752
 4,276
65,440
1,720
 3,921
63,190
—
 
Production (a)
(319)(9,430)(133) (371)(10,058)(102) (337)(7,156)(135) 
Sales(570)(1,291)(17) (11)(828)—
 (40)(61)—
 
Additions - extensions and discoveries3
52
—
 199
24,462
232
 733
11,003
182
 
Revisions to previous estimates(322)(8,173)110
 (643)(5,604)(98) (1)(1,536)1,673
 
Balance at end of year2,242
54,570
1,712
 3,450
73,412
1,752
 4,276
65,440
1,720
 
             
Proved developed reserves at end of year included above2,242
54,570
1,712
 3,436
73,390
1,752
 3,780
57,427
1,530
 
             
Proved undeveloped reserves at the end of year included in above—
—
—
 14
22
—
 496
8,013
191
 
             
NYMEX prices$42.75
$2.48
$—
(b) 
$50.28
$2.59
$—
(b) 
$94.99
$4.35
$—
(b) 
             
Well-head reserve prices(c)
$37.35
$2.25
$11.92
 $44.72
$1.27
$18.96
 $85.80
$3.33
$34.81
 
________________________
(a)Production for reserve calculations does not include volumes for natural gas liquids (NGLs) for historical periods.
(b)A specific NYMEX priceBHC has guaranteed the full and complete payment and performance on behalf of Black Hills Electric Generation for NGL is not available. Market pricesconstruction of Busch Ranch II. The guarantee terminates when BHC or Black Hills Electric Generation has paid for NGL are broken down by various liquid components, including ethane, propane, isobutane, normal butane, and natural gasoline. Each of these components is traded as an index. Presently, ethane is not being recovered at any of the facilities that process our natural gas production.
(c)For reserves purposes, costs to gather gas previously netted from the gas price were reclassified into operating expenses in 2016, with approximate rates of $1.54/Mcf for Piceance, $0.92/Mcf for San Juan and $0.53/Mcf forperformed all others. For accounting purposes, consistent with prior years, the sales price for natural gas is adjusted for transportation costs and other related deductions when applicable, as further described in Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.guaranteed obligations.


Reserve additions for 2016 totaled 0.1 Bcfe, replacing 0% of annual production. Reserve additions in 2016 were minimal due to continued poor economic conditions and our focus on supporting utility Cost of Service Gas Programs, which together, limited any further drilling. Capital spending in 2016 was primarily for existing infrastructure and acquiring right-aways. Future capital spending rates will be dependent on product prices, processing availability and support of our Cost of Service Gas program.

(21)    DISCONTINUED OPERATIONS

Results of operations for discontinued operations were classified as Net (loss) from discontinued operations in the accompanying Consolidated Statements of Income. Prior periods relating to our discontinued operations were reclassified to reflect consistency within our consolidated financial statements.

Oil and Gas Segment

On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture in 2018.

In 2016,2017, we had negative revisions of (9.4 Bcfe) to previous reserve estimates. Mostperformed a fair value assessment of the negative revisionassets and liabilities classified as held for sale. We evaluated our disposal groups classified as held for sale based on the lower of carrying value or fair value less cost to sell. The market approach was based on our fourth quarter 2017 sale of our Powder River Basin assets and pending sale transactions of our other properties. We believe that the resultestimates used in calculating the fair value of lower equivalent prices of oil, liquidsour assets and gas received atliabilities held for sale were reasonable based on the wellhead of (12.3 Bcfe), partially offset by improved wellhead performance of 3.5 Bcfe.

SEC regulations requireinformation that PUD locations meetwas known when the test of being developed within five years of being categorized as proved. In 2016, we had no PUD locations thatestimates were required to be dropped because of the five year rule.



Companies are required to include a narrative disclosure of the total quantity of PUD locations at year end, any material changes in PUD locations during the year and investment and progress made in converting the PUD locations to proved developed during the year.

We have no PUDs atmade. At December 31, 2016, and due to economic conditions in 2016, no new gross PUD locations were added for future drilling in2017, the Piceance Mancos or Powder River Basin.

The number of locations and reconciliationfair value of our proved undeveloped reserve and future development costs inheld for sale assets was less than our year-end proved undeveloped reserves ascarrying value, which required a pre-tax write down of December 31, 2016 were:
$20 million. There were no adjustments made to the fair value of our held for sale liabilities.

 
Proved Reserves
(in Bcfe)
Gross PUD LocationsFuture Development Costs (in millions)
    
Existing 2015:   
Williston0.1
6
$0.5
Piceance—
—
$(0.1)
Powder River—
—
$—
Year End Total 20150.1
6
$0.4
    
Dropped 2016:   
Williston(0.1)(6)$(0.5)
Piceance—
—
$0.1
 (0.1)(6)$(0.4)
    
Drilled in 2016:   
 —
—
$—
    
Revisions:—
—
$—
    
Added in 2016:—
—
$—
    
Total Proved Undeveloped—
—
$—




Capitalized Costs

Following is information concerning capitalized costs forFor the yearsyear ended December 31, (in thousands):
 201620152014
Unproved oil and gas properties$18,547
$47,254
$75,329
Proved oil and gas properties1,043,558
1,008,466
807,518
Gross capitalized costs1,062,105
1,055,720
882,847
    
Accumulated depreciation, depletion and amortization and valuation allowances(1,000,091)(888,775)(612,012)
Net capitalized costs$62,014
$166,945
$270,835

Results2018, we recorded $3.3 million of Operations

Following is a summaryexpenses comprised of resultsroyalty payments and reclamation costs related to final closing on the sale of operations for producing activities for the years ended December 31 (in thousands):
 201620152014
Revenue$34,058
$43,283
$55,114
    
Production costs17,231
19,762
22,155
Depreciation, depletion and amortization12,574
28,062
23,288
Impairment of long-lived assets106,957
249,608
—
Total costs136,762
297,432
45,443
Results of operations from producing activities before tax(102,704)(254,149)9,671
    
Income tax benefit (expense)37,916
93,743
(3,415)
Results of operations from producing activities (excluding general and administrative costs and interest costs)$(64,788)$(160,406)$6,256

Unproved Properties

Unproved properties not subject to amortization at December 31, 2016, relate primarily to direct purchase leasehold and work-in-progress projects. Unproved properties not subject to amortization at December 31, 2015 and 2014 consisted mainly of exploration costs on various existing work-in-progress projects as well as leasehold acquired through significant natural gas and oil property acquisitions and through direct purchases of leasehold. We capitalized approximately $0.9 million, $1.0 million and $1.0 million of interest during 2016, 2015 and 2014, respectively, on significant investments in unproved properties that were not yet included in the amortization base of the full-cost pool. We will continue to evaluate our unevaluated properties. However, the timing of the ultimate evaluation and disposition of the properties has not been determined.
The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2016 and notes the year in which the associated costs were incurred (in thousands):

 201620152014PriorTotal
Leasehold acquisition cost$963
$—
$—
$9,278
$10,241
Exploration cost532
441
6,443
—
7,416
Capitalized interest50
23
335
482
890
Total$1,545
$464
$6,778
$9,760
$18,547



Standardized Measure of Discounted Future Net Cash Flows

Following is a summary of the standardized measure of discounted future net cash flows and changes relating to proved oil and gas reserves forassets.

Operating results of the years ended December 31Oil and Gas segment included in Discontinued operations on the accompanying Consolidated Statements of Income were as follows (in thousands):
 For the Years Ended
 December 31, 2018December 31, 2017
   
Revenue$5,897
$25,382
   
Operations and maintenance11,014
22,872
Loss on sale of assets3,259
—
Depreciation, depletion and amortization1,300
7,521
Impairment of long-lived assets—
20,385
Total operating expenses15,573
50,778
   
Operating (loss)(9,676)(25,396)
   
Interest income (expense), net(19)181
Other income (expense), net190
(297)
Income tax benefit2,618
8,413
   
Net (loss) from discontinued operations$(6,887)$(17,099)


 201620152014
Future cash inflows$246,221
$295,173
$675,973
Future production costs(166,248)(146,552)(245,180)
Future development costs, including plugging and abandonment(18,333)(24,833)(45,123)
Future income tax expense—
—
(29,523)
Future net cash flows61,640
123,788
356,147
10% annual discount for estimated timing of cash flows(26,574)(44,760)(173,125)
Standardized measure of discounted future net cash flows$35,066
$79,028
$183,022


The following are the principal sources of change in the standardized measure of discounted future net cash flows during the years ended December 31 (in thousands):
 201620152014
Standardized measure - beginning of year$79,028
$183,022
$159,425
Sales and transfers of oil and gas produced, net of production costs(4,314)(29,948)(32,139)
Net changes in prices and production costs(32,698)(127,199)(28,544)
Extensions, discoveries and improved recovery, less related costs—
15,718
17,582
Changes in future development costs1,825
(7,387)3,195
Development costs incurred during the period—
27,211
2,079
Revisions of previous quantity estimates(7,477)(6,941)23,722
Accretion of discount7,903
18,870
18,437
Net change in income taxes—
5,682
19,265
Purchases of reserves—
—
—
Sales of reserves(9,201)—
—
Standardized measure - end of year$35,066
$79,028
$183,022

Changes in the standardized measure from “revisions of previous quantity estimates” are driven by reserve revisions, modifications of production profiles and timing of future development. For all years presented, we had minimal net reserve revisions to prior estimates due to performance. Production forecast modifications are generally made at the well level each year through the reserve review process. These production profile modifications are based on incorporation of the most recent production information and applicable technical studies. Timing of future development investments are reviewed each year and are often modified in response to current market conditions for items such as permitting and service availability.




(22)    QUARTERLY HISTORICAL DATA(Unaudited)


The Company operates on a calendar year basis. The following tables set forth select unaudited historical operating results and market data for each quarter of 20162019 and 2015.2018.
 First QuarterSecond Quarter
Third
Quarter
Fourth Quarter
 (in thousands, except per share amounts, dividends and common stock prices)
2016    
Revenue$449,959
$325,441
$333,786
$463,788
Operating income (loss)
$73,590
$35,298
$58,409
$55,289
Net Income (loss)$40,050
$3,283
$17,884
$21,414
Net income (loss) available for common stock$40,002
$669
$14,131
$18,168
     
Earnings (loss) per share - Basic$0.78
$0.01
$0.27
$0.34
     
Earnings (loss) per share - Diluted$0.77
$0.01
$0.26
$0.33
     
Dividends paid per share$0.420
$0.420
$0.420
$0.420
     
Common stock prices - High$61.13
$63.53
$64.58
$62.83
Common stock prices - Low$44.65
$56.16
$56.86
$54.76
 First QuarterSecond Quarter
Third
Quarter
Fourth Quarter
 (in thousands, except per share amounts, dividends and common stock prices)
2019    
Revenue$597,810
$333,888
$325,548
$477,654
Operating income$160,131
$54,001
$70,551
$121,359
Income from continuing operations$107,362
$17,693
$15,395
$72,872
(Loss) from discontinued operations$—
$—
$—
$—
Net income attributable to noncontrolling interest$(3,554)$(3,110)$(3,655)$(3,693)
Net income available for common stock$103,808
$14,583
$11,740
$69,179
     
Amounts attributable to common shareholders:    
Net income from continuing operations$103,808
$14,583
$11,740
$69,179
Net (loss) from discontinued operations—
—
—
—
Net income available for common stock$103,808
$14,583
$11,740
$69,179
     
Income per share for continuing operations - Basic$1.73
$0.24
$0.19
$1.13
(Loss) per share for discontinued operations - Basic—
—
—
—
Earnings per share - Basic$1.73
$0.24
$0.19
$1.13
     
Income per share for continuing operations - Diluted$1.73
$0.24
$0.19
$1.13
(Loss) per share for discontinued operations - Diluted—
—
—
—
Earnings per share - Diluted$1.73
$0.24
$0.19
$1.13


All quartersIncluded within the Income (loss) from continuing operations in the third quarter of 2016 included2019 is $15 million non-cash impairmentsafter-tax impairment of our investment in equity securities of a privately held oil and gas properties and external incremental acquisition and transaction costs. We recorded after-tax impairments of oil and gas properties of $8.8 million during the first quarter, $16 million during the second quarter, $7.9 million during the third quarter and $34 million during the fourth quarter. We incurred after-tax external incremental acquisition and transaction expenses of $15 million during the first quarter, $4.1 million during the second quarter, $4.1 million during the third quarter and $5.5 million during the fourth quarter.company.

 First QuarterSecond Quarter
Third
Quarter
Fourth
Quarter
 (in thousands, except per share amounts, dividends and common stock prices)
2018    
Revenue$575,389
$355,704
$321,979
$501,196
Operating income$148,274
$69,551
$65,085
$114,127
Income from continuing operations$138,977
$27,167
$21,801
$91,604
(Loss) from discontinued operations$(2,343)$(2,427)$(857)$(1,260)
Net income attributable to noncontrolling interest$(3,630)$(2,823)$(3,994)$(3,773)
Net income available for common stock$133,004
$21,917
$16,950
$86,571
     
Amounts attributable to common shareholders:    
Net income from continuing operations$135,347
$24,344
$17,807
$87,831
Net (loss) from discontinued operations(2,343)(2,427)(857)(1,260)
Net income available for common stock$133,004
$21,917
$16,950
$86,571
     
Income per share for continuing operations - Basic$2.54
$0.46
$0.33
$1.52
(Loss) per share for discontinued operations - Basic(0.05)(0.05)(0.02)(0.02)
Earnings per share - Basic$2.49
$0.41
$0.32
$1.50
     
Income per share for continuing operations - Diluted$2.50
$0.45
$0.32
$1.51
(Loss) per share for discontinued operations - Diluted(0.04)(0.05)(0.02)(0.02)
Earnings per share - Diluted$2.46
$0.40
$0.31
$1.49

 First QuarterSecond Quarter
Third
Quarter
Fourth
Quarter
 (in thousands, except per share amounts, dividends and common stock prices)
2015    
Revenue$441,987
$272,254
$272,105
$318,259
Operating income (loss)$70,500
$(38,858)$(2,044)$197
Net Income (loss)$33,850
$(41,842)$(9,943)$(14,176)
Net income (loss) available for common stock$33,850
$(41,842)$(9,943)$(14,176)
     
Earnings (loss) per share - Basic$0.76
$(0.94)$(0.22)$(0.30)
     
Earnings (loss) per share - Diluted$0.76
$(0.94)$(0.22)$(0.30)
     
Dividends paid per share$0.405
$0.405
$0.405
$0.405
     
Common stock prices - High$53.37
$52.96
$47.27
$47.51
Common stock prices - Low$47.88
$43.48
$36.81
$40.00




AllIncluded within the Income (loss) from continuing operations in the first and fourth quarters of 2015 included non-cash impairments2018 are tax benefits of oil$49 million and gas properties. We incurred external incremental acquisition and transaction costs during the second, third and fourth quarters. We recorded after-tax impairments of oil and gas properties of $14$23 million, during the first quarter, $66 million during the second quarter, $36 million during the third quarter and $44 million during the fourth quarter. We incurred after-tax external incremental acquisition and transaction expenses of $0.5 million during the second quarter, $2.8 million during the third quarter and $3.7 million during the fourth quarter.respectively, related to goodwill that is amortizable for tax purposes which resulted from legal entity restructuring.





(23)    SUBSEQUENT EVENTS

None.

ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE


None.


ITEM 9A.CONTROLS AND PROCEDURES


Disclosure Controls and Procedures


Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of December 31, 20162019. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.


Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Security Exchange Act of 1934, as amended, is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.


Changes in Internal Control over Financial Reporting


During the yearquarter ended December 31, 2016, the Company completed the acquisition of SourceGas, which is integrated within the Company’s Gas Utilities operations. As part of our ongoing integration activities, we are continuing to incorporate our controls and procedures into SourceGas and to implement company-wide controls over its operations. Other than the changes due to the SourceGas acquisition,2019, there were no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.


Management’s Report on Internal Control over Financial Reporting is presented on Page 12373 of this Annual Report on Form 10-K.


ITEM 9B.OTHER INFORMATION


None.




PART III


ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE


Information required under this item with respect to directors and information required by Items 401, 405, 406, 407(c)(3), 407(d)(4) and 407(d)(5) of Regulation S-K, is set forth in the Proxy Statement for our 20172020 Annual Meeting of Shareholders, which is incorporated herein by reference.

Information about our Executive Officers is reported in Part 1 of this Annual Report on Form 10-K.

David R. Emery, age 54, has been Chairman and Chief Executive Officer since January 2016 and Chairman, President and Chief Executive Officer from 2005 through 2015. Prior to that, he held various positions with the Company, including President and Chief Executive Officer and member of the Board of Directors from 2004 to 2005, President and Chief Operating Officer — Retail Business Segment from 2003 to 2004 and Vice President — Fuel Resources from 1997 to 2003. Mr. Emery has 27 years of experience with the Company.

Scott A. Buchholz, age 55, 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 36 years of experience with the Company, including 28 years with Aquila.

Linden R. Evans, age 54, has been President and Chief Operating Officer of the Company since January 2016 and President and Chief Operating Officer — Utilities from 2004 through 2015. Mr. Evans served as the Vice President and General Manager of our former communication subsidiary in 2003 and 2004, and served as our Associate Counsel from 2001 to 2003. Mr. Evans has 15 years of experience with the Company.

Brian G. Iverson, age 54, has been Senior Vice President, General Counsel and Chief Compliance Officer since April 2016. He served as Senior Vice President - Regulatory and Governmental Affairs and Assistant General Counsel from 2014 to April 2016, Vice President and Treasurer from 2011 to 2014, Vice President - Electric Regulatory Services from 2008 to 2011 and as Corporate Counsel from 2004 to 2008. Mr. Iverson has 13 years of experience with the Company.

Richard W. Kinzley, age 51, has been Senior Vice President and Chief Financial Officer since January 2015. He served as Vice President - Corporate Controller from 2013 to 2014, Vice President - Strategic Planning and Development from 2008 to 2013, and as Director of Corporate Development from 2000 to 2008. Mr. Kinzley has 17 years of experience with the Company.

Jennifer C. Landis, age 42, 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 March 2013 to April 2016, and Director of Organization Development from October 2008 to February 2013. Ms. Landis has 15 years of experience with the Company.

Robert A. Myers, age 59, has been Senior Vice President since February 1, 2017. He served as our Senior Vice President — Chief Human Resource Officer from 2009 to February 2017 and served as our Interim Human Resources Executive in 2008. He was a partner with Strategic Talent Solutions, a human resources consulting firm, from 2006 until 2008, Senior Vice President — Chief Human Resource Officer for Devon Energy in 2006, and Senior Vice President and Chief Human Resource Officer at Reebok International, Ltd from 2003 until 2006. He has over 35 years of service in key human resources leadership roles. Mr. Myers has 8 years of experience with the Company and plans to retire effective April 1, 2017.


ITEM 11.EXECUTIVE COMPENSATION


Information required under this item is set forth in the Proxy Statement for our 20172020 Annual Meeting of Shareholders, which is incorporated herein by reference.




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


Information regarding the security ownership of certain beneficial owners and management is set forth in the Proxy Statement for our 20172020 Annual Meeting of Shareholders, which is incorporated herein by reference.


EQUITY COMPENSATION PLAN INFORMATION


The following table includes information as of December 31, 20162019 with respect to our equity compensation plans. These plans include the 2005 Omnibus Incentive planPlan and 2015 Omnibus Incentive plan.Plan.
Equity Compensation Plan Information
Plan categoryNumber of securities to be issued upon exercise of outstanding options, warrants and rightsWeighted-average exercise price of outstanding options, warrants and rightsNumber of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))Number of securities to be issued upon exercise of outstanding options, warrants and rightsWeighted-average exercise price of outstanding options, warrants and rightsNumber of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
(a)(b)(c)(a)(b)(c)
Equity compensation plans approved by security holders255,065
(1) 
 $45.51
(1) 
1,115,557
(2) 
160,179
(1) 
 $39.99
(1) 
672,049
(2) 
Equity compensation plans not approved by security holders—
 $—
 —
 —
 $—
 —
 
Total255,065
 $45.51
 1,115,557
 160,179
 $39.99
 672,049
 
_________________________
(1)
Includes 135,650146,179 full value awards outstanding as of December 31, 20162019, comprised of restricted stock units, performance shares, short-term incentive plan (STIP) units and Director common stock units. The weighted average exercise price does not include the restricted stock units, performance shares, STIP or common stock units. In addition, 293,095192,120 shares of unvested restricted stock were outstanding as of December 31, 2016,2019, which are not included in the above table because they have already been issued.
(2)Shares available for issuance are from the 2015 Omnibus Incentive Plan. The 2015 Omnibus Incentive Plan permits the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock based awards.


ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE


Information regarding certain relationships and related transactions and director independence is set forth in the Proxy Statement for our 20172020 Annual Meeting of Shareholders, which is incorporated herein by reference.


ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES


Information regarding principal accounting fees and services is set forth in the Proxy Statement for our 20172020 Annual Meeting to Shareholders, which is incorporated herein by reference.




PART IV


ITEM 15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES


(a)1.Consolidated Financial Statements
   
  Financial statements required under this item are included in Item 8 of Part II
   
 2.Schedules
   
  Schedule II — Consolidated Valuation and Qualifying Accounts for the years ended December 31, 2016, 20152019, 2018 and 20142017
3.Exhibits
   
  All other schedules have been omitted because of the absence of the conditions under which they are required or because the required information is included in our consolidated financial statements and notes thereto.
3.Exhibits




SCHEDULE II

BLACK HILLS CORPORATION
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2016, 2015 AND 2014
 
Description Balance at Beginning of Year 
Adjustments (a)
 Additions Charged to Costs and Expenses Recoveries and Other Additions Write-offs and Other Deductions Balance at End of Year
  (in thousands)
Allowance for doubtful accounts:          
2016 $1,741
 $2,158
 $2,704
 $4,915
 $(9,126) $2,392
2015 $1,516
 $—
 $3,860
 $4,132
 $(7,767) $1,741
2014 $1,237
 $—
 $4,470
 $4,233
 $(8,424) $1,516
Consolidated valuation and qualifying accounts are detailed within Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
__________________
(a)Represents allowance balances added with the SourceGas acquisition.



3.Exhibits


Exhibit NumberDescription
  
2.1*
Purchase and Sale Agreement by and among Alinda Gas Delaware LLC, Alinda Infrastructure Fund I, L.P. and Aircraft Services Corporation, as Sellers, and Black Hills Utility Holdings, Inc., as Buyer, dated as of July 12, 2015 (filed as Exhibit 2.1 to the Registrant'sRegistrant’s Form 8-K filed on July 14, 2015).
  
2.2*
First Amendment to Purchase and Sale Agreement effective December 10, 2015, by and among, Alinda Gas Delaware LLC, Alinda Infrastructure Fund I, L.P. and Aircraft Services Corporation, as Sellers, and Black Hills Utility Holdings, Inc., as Buyer (filed as Exhibit 2.2 to the Registrant’s Form 10-K for 2015).
  
2.3*
Option Agreement, by and among, Aircraft Services Corporation, as ASC, SourceGas Holdings LLC, as the Company and Black Hills Utility Holdings, Inc., as Buyer (filed as Exhibit 2.2 to the Registrant'sRegistrant’s Form 8-K filed on July 14, 2015).
2.4*Guaranty of Black Hills Corporation in favor of Alinda Gas Delaware LLC, Alinda Infrastructure Fund I, L.P. and Aircraft Services Corporation, dated as of July 12, 2015 (filed as Exhibit 2.3 to the Registrant's Form 8-K filed on July 14, 2015).
  
3.1*
Restated Articles of Incorporation of the Registrant (filed as Exhibit 3 to the Registrant’s Form 10-K for 2004)8-K filed on February 5, 2018).
  
3.2*
Amended and Restated Bylaws of the Registrant dated January 28, 2010April 24, 2017 (filed as Exhibit 3 to the Registrant’s Form 8-K filed on February 3, 2010)April 28, 2017).
  
4.1*
Indenture dated as of May 21, 2003 between the Registrant and Wells Fargo Bank, National Association (as successor to LaSalle Bank National Association), as Trustee (filed as Exhibit 4.1 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003).
First Supplemental Indenture dated as of May 21, 2003 (filed as Exhibit 4.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003).
Second Supplemental Indenture dated as of May 14, 2009 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on May 14, 2009).
Third Supplemental Indenture dated as of July 16, 2010 (filed as Exhibit 4 to Registrant’s Form 8-K filed on July 15, 2010).

Fourth Supplemental Indenture dated as of November 19, 2013 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on November 18, 2013).
Fifth Supplemental Indenture dated as of January 13, 2016 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on January 13, 2016).
Sixth Supplemental Indenture dated as of August 19, 2016 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on August 19, 2016).
Seventh Supplemental Indenture dated as of August 17, 2018 (filed as Exhibit 4.2 to the Registrant’s Form 8-K filed on August 17, 2018).
Eighth Supplemental Indenture dated as of October 3, 2019 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on October 4, 2019).
  
4.2*
Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)).
First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S‑3 (No. 333‑150669)).
Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registrant’s Post-Effective Amendment No. 2 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)).
Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014).
  
4.3*
Restated Indenture of Mortgage, Deed of Trust, Security Agreement and Financing Statement, amended and restated as of November 20, 2007, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on October 2, 2014).
First Supplemental Indenture, dated as of September 3, 2009, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.3 to the Registrant’s Form 8-K filed on October 2, 2014).
Second Supplemental Indenture, dated as of October 1, 2014, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.4 to the Registrant’s Form 8-K filed on October 2, 2014).
  
4.4*Junior Subordinated Indenture dated as of November 23, 2015 between Black Hills Corporation and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on November 23, 2015). First Supplemental Indenture dated as of November 23, 2015 (filed as Exhibit 4.2 to the Registrant’s Form 8-K filed on November 23, 2015).


4.5*Purchase Contract and Pledge Agreement dated as of November 23, 2015 between Black Hills Corporation and U.S. Bank National Association, as purchase contract agent, collateral agent, custodial agent and securities intermediary (filed as Exhibit 4.4 to the Registrant’s Form 8-K filed on November 23, 2015).
4.6*Indenture dated as of April 16, 2007 between SourceGas LLC and U.S. Bank National Association, as Trustee (relating to $325 million, 5.90% Senior Notes due 2017 - $0 balance remaining at 12/31/2016) (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on March 18, 2016).
4.7*Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the Registrant’s Form 10-K for 2000).
4.5
Description of Securities
  
10.1*†
Amended and Restated Pension Equalization Plan of Black Hills Corporation dated November 6, 2001 (filed as Exhibit 10.11 to the Registrant’s Form 10-K/A for 2001).
First Amendment to Pension Equalization Plan (filed as Exhibit 10.10 to the Registrant’s Form 10-K for 2002).
Grandfather Amendment to the Amended and Restated Pension Equalization Plan of Black Hills Corporation (filed as Exhibit 10.2 to the Registrant’s Form 10-K for 2008).
  
10.2*†
2005 Pension Equalization Plan of Black Hills Corporation (filed as Exhibit 10.3 to the Registrant’s Form 10-K for 2008).
  
10.3*†
Restoration Plan of Black Hills Corporation (filed as Exhibit 10.5 to the Registrant’s Form 10-K for 2008).
First Amendment to the Restoration Plan of Black Hills Corporation dated July 24, 2011 (filed as Exhibit 10.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2011).
  
10.4*†
Black Hills Corporation Non-qualified Deferred Compensation Plan as Amended and Restated effective January 1, 2011 (filed as Exhibit 10.4 to the Registrant’s Form 10-K for 2010).
  
10.5*†
First Amendment to the Black Hills Corporation Nonqualified Deferred Compensation Plan as Amended and Restated effective January 1, 2011 (filed as Exhibit 10.5 to the Registrant’s Form 10-K for 2018).
10.6*†
Black Hills Corporation Post-2018 Nonqualified Deferred Compensation Plan (filed as Exhibit 10.6 to the Registrant’s Form 10-K for 2018).

10.7*†
Black Hills Corporation 2005 Omnibus Incentive Plan (”Omnibus Plan”) (filed as Appendix A to the Registrant’s Proxy Statement filed April 13, 2005).
First Amendment to the Omnibus Plan (filed as Exhibit 10.11 to the Registrant’s Form 10-K for 2008).
Second Amendment to the Omnibus Plan (filed as Exhibit 10 to the Registrant’s Form 8-K filed on May 26, 2010).
  
10.6*10.8*†
Black Hills Corporation 2015 Omnibus Incentive Plan (filed as Appendix B to the Registrant’s Proxy Statement filed March 19, 2015).
  
10.7*10.9*†
Form of Stock Option Agreement for Omnibus Plan effective for awards granted on or after January 1, 2014 (filed as Exhibit 10.7 to the Registrant’s Form 10-K for 2013).
Form of Stock Option Agreement effective for awards granted on or after April 28, 2015 (filed as Exhibit 10.8 to Registrant’s Form 10-K for 2015).
  
10.8*10.10*†Form of Restricted Stock Award for Omnibus Plan effective for awards granted on or after January 1, 2014 (filed as Exhibit 10.9 to the Registrant’s Form 10-K for 2013).
Form of Restricted Stock Award Agreement effective for awards granted on or after April 28, 2015 (filed as Exhibit 10.10 to Registrant’s Form 10-K for 2015).
  
10.9*10.11*†Form of Restricted Stock Unit Award Agreement for Omnibus Plan effective for awards granted on or after January 1, 2014 (filed as Exhibit 10.10 to the Registrant’s Form 10-K for 2013).
Form of Restricted Stock Unit Award Agreement for 2015 Omnibus Plan effective for awards granted on or after April 28, 2015 (filed as Exhibit 10.12 to the Registrant’s Form 10-K for 2015).
  
10.10*†10.12†Form of Performance Share Award Agreement for Omnibus Plan effective for awards granted on or after January 1, 2014 (filed as Exhibit 10.12 to the Registrant’s Form 10-K for 2013). Form of Performance Share Award Agreement effective for awards granted on or after January 1, 2015 (filed as Exhibit 10.11 to the Registrant’s Form 10-K for 2014).
Form of Performance Share Award Agreement effective for awards granted on or after January 1, 2016 (filed as Exhibit 10.6 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2016).
Form of Performance Share Award Agreement effective for awards granted on or after January 1, 2017.
  
10.11*10.13*†
Form of Short-term Incentive effective for awards granted on or after January 1, 2016 (filed as Exhibit 10.7 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2016).
  
10.12*10.14*†
Form of Indemnification Agreement (filed as Exhibit 10.5 to the Registrant’s Form 8-K filed on September 3, 2004).


  
10.13*†10.15†
Change in Control Agreement dated November 15, 20162019 between Black Hills Corporation and DavidLinden R. Emery (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on November 16, 2016).Evans.
  
10.14*†10.16†Form of
Change in Control Agreements between Black Hills Corporation and its non-CEO Senior Executive Officers (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on November 16, 2016).Officers.
  
10.15*10.17*†
Outside Directors Stock Based Compensation Plan as Amended and Restated effective January 1, 2009 (filed as Exhibit 10.23 to the Registrant’s Form 10-K for 2008).
First Amendment to the Outside Directors Stock Based Compensation Plan effective January 1, 2011 (filed as Exhibit 10.16 to the Registrant’s Form 10-K for 2010).
Second Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2013 (filed as Exhibit 10.15 to the Registrant’s Form 10-K for 2012).
Third Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2015 (filed as Exhibit 10.16 to the Registrant’s Form 10-K for 2014).
Fourth Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2017 (filed as Exhibit 10.4 to the Registrant’s Form 10-Q for the quarterly period ended September 30, 2016).
Fifth Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2018 (filed as Exhibit 10.16 to the Registrant’s Form 10-K for 2017).
  
10.16*10.18*†
Sixth Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2019 (filed as Exhibit 10.18 to the Registrant’s Form 10-K for 2018).
10.19*†
Form of Non-Disclosure and Non-Solicitation Agreement for Certain Employees (filed as Exhibit 10.8 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2016).
  
10.17*10.20
Equity Distribution Sales Agreement dated March 18, 2016August 4, 2017 among Black Hills Corporation and the several Agents named therein (filed as Exhibit 1.1 to the Registrant’s Form 8-K filed on March 18, 2016)August 4, 2017).
 
10.18*Bond Purchase Agreement dated as of June 30, 2014 by and among Black Hills Power, Inc., New York Life Insurance Company, New York Life Insurance and Annuity Corporation, Teachers Insurance and Annuity Association of America, John Hancock Life Insurance Company (U.S.A.), John Hancock Life & Health Insurance Company, John Hancock Life Insurance Company of New York and United of Omaha Life Insurance Company (filed as Exhibit 10.1
First Amendment to the Registrant’s Form 8-K filed on July 2, 2014).
10.19*Bond Purchase Agreement dated as of June 30, 2014 by and among Cheyenne Light Fuel and Power Company, New York Life Insurance Company, New York Life Insurance and Annuity Corporation, Teachers Insurance and Annuity Association of America, John Hancock Life Insurance Company (U.S.A.), John Hancock Life & Health Insurance Company, John Hancock Life Insurance Company of New York, Mutual of Omaha Insurance Company, United of Omaha Life Insurance Company and American Equity Investment Life Insurance Company (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on July 2, 2014).
10.20*Third Amended and Restated Term Loan Credit Agreement, dated August 9, 2016 (relating to $340 million SourceGas Acquisition Credit Agreement - $0 balance at 12/31/2016) among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and J.P. Morgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.3 to the Registrant’s Form 8-K filed on August 10, 2016).Distribution Sales Agreement.
  
10.21*Second
Third Amended and Restated Credit Agreement dated August 9, 2016as of July 30, 2018 (relating to $750 million Revolving Credit Facility), among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and U.S. Bank, National Association, as Administrative Agent (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on August 10, 2016)July 31, 2018).

  
10.2210.22*Amendment No. 1 to Second
Amended and Restated Credit Agreement dated as of December 7, 2016 (relating to $750 million Revolving Credit Facility).
10.23*Credit Agreement dated April 13, 2015July 30, 2018 (relating to $300 million, two-year term loan - $0 balance at 12/31/2016), among Black Hills Corporation, as Borrower, JPMorgan Chase Bank, N. A., in its capacity as administrative agent for the Banks under the Credit Agreement, and as a Bank, and the other Banks party thereto (filed as Exhibit 10 to the Registrant’s Form 8-K filed on April 14, 2015). First Amendment dated August 6, 2015 (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on August 12, 2015).
10.24*Credit Agreement dated August 9, 2016 (relating to $500 million, three-year term loan - $400 million balance at 12/31/2016)loan), among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on August 10, 2016)July 31, 2018).
 
10.25
First Amendment No. 1dated as of June 17, 2019 to Amended and Restated Credit Agreement dated as of December 7, 2016 (relating to $500 million, three-year term loan - $400 million balance as of 12/31/2016).


10.26*Note Purchase Agreement dated September 29, 2014 among SourceGas Holdings LLC and the purchasers party thereto (relating to $95 million 3.98% Senior Secured Notes due 2019 - $0 balance at 12/31/2016) (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on March 18, 2016).
10.27*Commitment Letter by and among Black Hills Corporation and Credit Suisse Securities (USA) LLC and Credit Suisse AG dated as of July 12, 2015 (filed as Exhibit 10.1 to the Registrant's Form 8-K filed on July 14, 2015).
10.28*Bridge Term Loan Agreement dated as of August 6, 2015 (relating to Bridge Term Loan Credit Agreement - $0 balance at 12/31/2016)30, 2018, among Black Hills Corporation, as Borrower, the Financial Institutionsfinancial institutions party thereto, as Banks, and Credit Suisse AG, Cayman Island Branch,JPMorgan Chase Bank, N.A., as administrative agent, and Credit Suisse Securities (USA) LLC, as Sole Lead Arranger and Sole BookrunnerAdministrative Agent (filed as Exhibit 10.1 to the Registrant’s Form 8-K8–K filed on August 12, 2015)June 17, 2019).
  
10.29*10.23*
Coal Leases between WRDC and the Federal Government
     -Dated May 1, 1959 (filed as Exhibit 5(i) to the Registrant’s Form S‑7, File No. 2‑60755)
        -Modified January 22, 1990 (filed as Exhibit 10(h) to the Registrant’s Form 10‑K for 1989)
     -Dated April 1, 1961 (filed as Exhibit 5(j) to the Registrant’s Form S‑7, File No. 2‑60755)
        -Modified January 22, 1990 (filed as Exhibit 10(i) to Registrant’s Form 10‑K for 1989)
     -Dated October 1, 1965 (filed as Exhibit 5(k) to the Registrant’s Form S‑7, File No. 2‑60755)
        -Modified January 22, 1990 (filed as Exhibit 10(j) to the Registrant’s Form 10‑K for 1989).
  
10.30*10.24*Assignment of Mining Leases and Related Agreement effective May 27, 1997, between WRDC and Kerr-McGee Coal Corporation (filed as Exhibit 10(u) to the Registrant’s Form 10-K for 1997).
  
21
List of Subsidiaries of Black Hills Corporation.
  
23.1
Consent of Independent Registered Public Accounting Firm.
23.2Consent of Petroleum Engineer and Geologist.
  
31.1
Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
  
31.2
Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
  
32.1
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
  
32.2
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
  
95
Mine Safety and Health Administration Safety Data
  
99101.INSReport of Cawley, Gillespie & Associates, Inc.XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCHXBRL Taxonomy Extension Schema Document
101.CALXBRL Taxonomy Extension Calculation Linkbase Document
101.DEFXBRL Taxonomy Extension Definition Linkbase Document
101.LABXBRL Taxonomy Extension Label Linkbase Document
101.PREXBRL Taxonomy Extension Presentation Linkbase Document
  
101104Financial StatementsCover Page Interactive Data File (formatted as inline XBRL and contained in XBRL FormatExhibit 101)
________________________
*Previously filed as part of the filing indicated and incorporated by reference herein.
†Indicates a board of director or management compensatory plan.
(a)See (a) 3. Exhibits above.
(b)See (a) 2. Schedules above.





ITEM 16.FORM 10-K SUMMARY


None.




SIGNATURES


Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
  BLACK HILLS CORPORATION
   
  By:/S/ DAVIDLINDEN R. EMERYEVANS
  DavidLinden R. Emery, ChairmanEvans, President and Chief Executive Officer
Dated:February 24, 201714, 2020 


Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.


/S/ DAVIDLINDEN R. EMERYEVANSDirector andFebruary 24, 201714, 2020
DavidLinden R. Emery, ChairmanEvans, PresidentPrincipal Executive Officer 
and Chief Executive Officer  
   
/S/ RICHARD W. KINZLEYPrincipal Financial andFebruary 24, 201714, 2020
Richard W. Kinzley, Senior Vice PresidentAccounting Officer 
and Chief Financial Officer  
   
/S/ DAVID R. EMERYDirector andFebruary 14, 2020
David R. Emery, Executive ChairmanExecutive Chairman
/S/ TONY A. JENSENDirectorFebruary 14, 2020
Tony A. Jensen
/S/ MICHAEL H. MADISONDirectorFebruary 24, 201714, 2020
Michael H. Madison  
   
/S/ LINDA K. MASSMANKATHLEEN S. MCALLISTERDirectorFebruary 24, 201714, 2020
Linda K. MassmanKathleen S. McAllister  
   
/S/ STEVEN R. MILLSDirectorFebruary 24, 201714, 2020
Steven R. Mills  
   
/S/ ROBERT P. OTTODirectorFebruary 24, 201714, 2020
Robert P. Otto  
   
/S/ REBECCA B. ROBERTSDirectorFebruary 24, 201714, 2020
Rebecca B. Roberts  
   
/S/ MARK A. SCHOBERDirectorFebruary 24, 201714, 2020
Mark A. Schober  
   
/S/ TERESA A. TAYLORDirectorFebruary 24, 201714, 2020
Teresa A. Taylor  
   
/S/ JOHN B. VERINGDirectorFebruary 24, 201714, 2020
John B. Vering  
   
/S/ THOMAS J. ZELLERDirectorFebruary 24, 201714, 2020
Thomas J. Zeller  


INDEX TO EXHIBITS


149
Exhibit NumberDescription
2.1*Purchase and Sale Agreement by and among Alinda Gas Delaware LLC, Alinda Infrastructure Fund I, L.P. and Aircraft Services Corporation, as Sellers, and Black Hills Utility Holdings, Inc., as Buyer, dated as of July 12, 2015 (filed as Exhibit 2.1 to the Registrant's Form 8-K filed on July 14, 2015).
2.2*First Amendment to Purchase and Sale Agreement effective December 10, 2015, by and among, Alinda Gas Delaware LLC, Alinda Infrastructure Fund I, L.P. and Aircraft Services Corporation, as Sellers, and Black Hills Utility Holdings, Inc., as Buyer (filed as Exhibit 2.2 to the Registrant’s Form 10-K for 2015).
2.3*Option Agreement, by and among, Aircraft Services Corporation, as ASC, SourceGas Holdings LLC, as the Company and Black Hills Utility Holdings, Inc., as Buyer (filed as Exhibit 2.2 to the Registrant's Form 8-K filed on July 14, 2015).
2.4*Guaranty of Black Hills Corporation in favor of Alinda Gas Delaware LLC, Alinda Infrastructure Fund I, L.P. and Aircraft Services Corporation, dated as of July 12, 2015 (filed as Exhibit 2.3 to the Registrant's Form 8-K filed on July 14, 2015).
3.1*Restated Articles of Incorporation of the Registrant (filed as Exhibit 3 to the Registrant’s Form 10-K for 2004).
3.2*Amended and Restated Bylaws of the Registrant dated January 28, 2010 (filed as Exhibit 3 to the Registrant’s Form 8-K filed on February 3, 2010).
4.1*Indenture dated as of May 21, 2003 between the Registrant and Wells Fargo Bank, National Association (as successor to LaSalle Bank National Association), as Trustee (filed as Exhibit 4.1 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003). First Supplemental Indenture dated as of May 21, 2003 (filed as Exhibit 4.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003). Second Supplemental Indenture dated as of May 14, 2009 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on May 14, 2009). Third Supplemental Indenture dated as of July 16, 2010 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on July 15, 2010). Fourth Supplemental Indenture dated as of November 19, 2013 (filed as Exhibit 4 to the Registrants’ Form 8-K filed on November 18, 2013). Fifth Supplemental Indenture dated as of January 13, 2016 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on January 13, 2016).
4.2*Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S‑3 (No. 333‑150669)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registrant’s Post-Effective Amendment No. 2 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)). Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014).
4.3*Restated Indenture of Mortgage, Deed of Trust, Security Agreement and Financing Statement, amended and restated as of November 20, 2007, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on October 2, 2014). First Supplemental Indenture, dated as of September 3, 2009, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.3 to the Registrant’s Form 8-K filed on October 2, 2014). Second Supplemental Indenture, dated as of October 1, 2014, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.4 to the Registrant’s Form 8-K filed on October 2, 2014).
4.4*Junior Subordinated Indenture dated as of November 23, 2015 between Black Hills Corporation and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on November 23, 2015). First Supplemental Indenture dated as of November 23, 2015 (filed as Exhibit 4.2 to the Registrant’s Form 8-K filed on November 23, 2015).


4.5*Purchase Contract and Pledge Agreement dated as of November 23, 2015 between Black Hills Corporation and U.S. Bank National Association, as purchase contract agent, collateral agent, custodial agent and securities intermediary (filed as Exhibit 4.4 to the Registrant’s Form 8-K filed on November 23, 2015).
4.6*Indenture dated as of April 16, 2007 between SourceGas LLC and U.S. Bank National Association, as Trustee (relating to $325 million, 5.90% Senior Notes due 2017 - $0 balance remaining at 12/31/2016) (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on March 18, 2016).
4.7*Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the Registrant’s Form 10-K for 2000).
10.1*†Amended and Restated Pension Equalization Plan of Black Hills Corporation dated November 6, 2001 (filed as Exhibit 10.11 to the Registrant’s Form 10-K/A for 2001). First Amendment to Pension Equalization Plan (filed as Exhibit 10.10 to the Registrant’s Form 10-K for 2002). Grandfather Amendment to the Amended and Restated Pension Equalization Plan of Black Hills Corporation (filed as Exhibit 10.2 to the Registrant’s Form 10-K for 2008).
10.2*†2005 Pension Equalization Plan of Black Hills Corporation (filed as Exhibit 10.3 to the Registrant’s Form 10-K for 2008).
10.3*†Restoration Plan of Black Hills Corporation (filed as Exhibit 10.5 to the Registrant’s Form 10-K for 2008). First Amendment to the Restoration Plan of Black Hills Corporation dated July 24, 2011 (filed as Exhibit 10.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2011).
10.4*†Black Hills Corporation Non-qualified Deferred Compensation Plan as Amended and Restated effective January 1, 2011 (filed as Exhibit 10.4 to the Registrant’s Form 10-K for 2010).
10.5*†Black Hills Corporation 2005 Omnibus Incentive Plan (”Omnibus Plan”) (filed as Appendix A to the Registrant’s Proxy Statement filed April 13, 2005). First Amendment to the Omnibus Plan (filed as Exhibit 10.11 to the Registrant’s Form 10-K for 2008). Second Amendment to the Omnibus Plan (filed as Exhibit 10 to the Registrant’s Form 8-K filed on May 26, 2010).
10.6*†Black Hills Corporation 2015 Omnibus Incentive Plan (filed as Appendix B to the Registrant’s Proxy Statement filed March 19, 2015).
10.7*†Form of Stock Option Agreement for Omnibus Plan effective for awards granted on or after January 1, 2014 (filed as Exhibit 10.7 to the Registrant’s Form 10-K for 2013). Form of Stock Option Agreement effective for awards granted on or after April 28, 2015 (filed as Exhibit 10.8 to Registrant’s Form 10-K for 2015).
10.8*†Form of Restricted Stock Award for Omnibus Plan effective for awards granted on or after January 1, 2014 (filed as Exhibit 10.9 to the Registrant’s Form 10-K for 2013). Form of Restricted Stock Award Agreement effective for awards granted on or after April 28, 2015 (filed as Exhibit 10.10 to Registrant’s Form 10-K for 2015).
10.9*†Form of Restricted Stock Unit Award Agreement for Omnibus Plan effective for awards granted on or after January 1, 2014 (filed as Exhibit 10.10 to the Registrant’s Form 10-K for 2013). Form of Restricted Stock Unit Award Agreement for 2015 Omnibus Plan effective for awards granted on or after April 28, 2015 (filed as Exhibit 10.12 to the Registrant’s Form 10-K for 2015).
10.10*†Form of Performance Share Award Agreement for Omnibus Plan effective for awards granted on or after January 1, 2014 (filed as Exhibit 10.12 to the Registrant’s Form 10-K for 2013). Form of Performance Share Award Agreement effective for awards granted on or after January 1, 2015 (filed as Exhibit 10.11 to the Registrant’s Form 10-K for 2014). Form of Performance Share Award Agreement effective for awards granted on or after January 1, 2016 (filed as Exhibit 10.6 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2016).
10.11*†Form of Short-Term Incentive effective for awards granted on or after January 1, 2016 (filed as Exhibit 10.7 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2016).
10.12*†Form of Indemnification Agreement (filed as Exhibit 10.5 to the Registrant’s Form 8-K filed on September 3, 2004).


10.13*†Change in Control Agreement dated November 15, 2016 between Black Hills Corporation and David R. Emery (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on November 16, 2016).
10.14*†Form of Change in Control Agreements between Black Hills Corporation and its non-CEO Senior Executive Officers (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on November 16, 2016).
10.15*†Outside Directors Stock Based Compensation Plan as Amended and Restated effective January 1, 2009 (filed as Exhibit 10.23 to the Registrant’s Form 10-K for 2008). First Amendment to the Outside Directors Stock Based Compensation Plan effective January 1, 2011 (filed as Exhibit 10.16 to the Registrant’s Form 10-K for 2010). Second Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2013 (filed as Exhibit 10.15 to the Registrant’s Form 10-K for 2012). Third Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2015 (filed as Exhibit 10.16 to the Registrant’s Form 10-K for 2014). Fourth Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2017 (filed as Exhibit 10.4 to the Registrant’s Form 10-Q for the quarterly period ended September 30, 2016).
10.16*†Form of Non-Disclosure and Non-Solicitation Agreement for Certain Employees (filed as Exhibit 10.8 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2016).
10.17*Equity Distribution Sales Agreement dated March 18, 2016 among Black Hills Corporation and the several Agents named therein (filed as Exhibit 1.1 to the Registrant’s Form 8-K filed on March 18, 2016).
10.18*Bond Purchase Agreement dated as of June 30, 2014 by and among Black Hills Power, Inc., New York Life Insurance Company, New York Life Insurance and Annuity Corporation, Teachers Insurance and Annuity Association of America, John Hancock Life Insurance Company (U.S.A.), John Hancock Life & Health Insurance Company, John Hancock Life Insurance Company of New York and United of Omaha Life Insurance Company (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on July 2, 2014).
10.19*Bond Purchase Agreement dated as of June 30, 2014 by and among Cheyenne Light Fuel and Power Company, New York Life Insurance Company, New York Life Insurance and Annuity Corporation, Teachers Insurance and Annuity Association of America, John Hancock Life Insurance Company (U.S.A.), John Hancock Life & Health Insurance Company, John Hancock Life Insurance Company of New York, Mutual of Omaha Insurance Company, United of Omaha Life Insurance Company and American Equity Investment Life Insurance Company (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on July 2, 2014).
10.20*Third Amended and Restated Term Loan Credit Agreement, dated August 9, 2016 (relating to $340 million SourceGas Acquisition Credit Agreement - $0 balance at 12/31/2016) among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and J.P. Morgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.3 to the Registrant’s Form 8-K filed on August 10, 2016).
10.21*Second Amended and Restated Credit Agreement, dated August 9, 2016 (relating to $750 million Revolving Credit Facility), among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and U.S. Bank, National Association, as Administrative Agent (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on August 10, 2016).
10.22Amendment No. 1 to Second Amended and Restated Credit Agreement dated as of December 7, 2016 (relating to $750 million Revolving Credit Facility).
10.23*Credit Agreement dated April 13, 2015 (relating to $300 million, two-year term loan - $0 balance at 12/31/2016), among Black Hills Corporation, as Borrower, JPMorgan Chase Bank, N. A., in its capacity as administrative agent for the Banks under the Credit Agreement, and as a Bank, and the other Banks party thereto (filed as Exhibit 10 to the Registrant’s Form 8-K filed on April 14, 2015). First Amendment dated August 6, 2015 (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on August 12, 2015).
10.24*Credit Agreement dated August 9, 2016 (relating to $500 million, three-year term loan - $400 million balance at 12/31/2016), among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on August 10, 2016).
10.25Amendment No. 1 to Credit Agreement dated as of December 7, 2016 (relating to $500 million, three-year term loan - $400 million balance as of 12/31/2016).


10.26*Note Purchase Agreement dated September 29, 2014 among SourceGas Holdings LLC and the purchasers party thereto (relating to $95 million 3.98% Senior Secured Notes due 2019 - $0 balance at 12/31/2016) (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on March 18, 2016).
10.27*Commitment Letter by and among Black Hills Corporation and Credit Suisse Securities (USA) LLC and Credit Suisse AG dated as of July 12, 2015 (filed as Exhibit 10.1 to the Registrant's Form 8-K filed on July 14, 2015).
10.28*Bridge Term Loan Agreement dated as of August 6, 2015 (relating to Bridge Term Loan Credit Agreement - $0 balance at 12/31/2016) among Black Hills Corporation, as Borrower, the Financial Institutions party thereto, as Banks, and Credit Suisse AG, Cayman Island Branch, as administrative agent, and Credit Suisse Securities (USA) LLC, as Sole Lead Arranger and Sole Bookrunner (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on August 12, 2015).
10.29*
Coal Leases between WRDC and the Federal Government
-Dated May 1, 1959 (filed as Exhibit 5(i) to the Registrant’s Form S-7, File No. 2-60755)
-Modified January 22, 1990 (filed as Exhibit 10(h) to the Registrant’s Form 10-K for 1989)
-Dated April 1, 1961 (filed as Exhibit 5(j) to the Registrant’s Form S-7, File No. 2-60755)
-Modified January 22, 1990 (filed as Exhibit 10(i) to Registrant’s Form 10-K for 1989)
-Dated October 1, 1965 (filed as Exhibit 5(k) to the Registrant’s Form S-7, File No. 2-60755)
-Modified January 22, 1990 (filed as Exhibit 10(j) to the Registrant’s Form 10-K for 1989).
10.30*Assignment of Mining Leases and Related Agreement effective May 27, 1997, between WRDC and Kerr-McGee Coal Corporation (filed as Exhibit 10(u) to the Registrant’s Form 10-K for 1997).
21List of Subsidiaries of Black Hills Corporation.
23.1Consent of Independent Registered Public Accounting Firm.
23.2Consent of Petroleum Engineer and Geologist.
31.1Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
31.2Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
32.1Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
95Mine Safety and Health Administration Safety Data
99Report of Cawley, Gillespie & Associates, Inc.
101Financial Statements in XBRL Format
__________________________
*Previously filed as part of the filing indicated and incorporated by reference herein.
†Indicates a board of director or management compensatory plan.

217