Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549


Form 10-Q

xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2017
OR
oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________ to __________.
Commission File Number 001-31303
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2020
Black Hills Corporation
Incorporated in South DakotaIRS Identification Number 46-0458824
625 Ninth Street
Rapid City, South Dakota 57701
Registrant’s telephone number (605) 721-1700
Former name, former address, and former fiscal year if changed since last report
NONE
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________.

Commission File Number 001-31303

Black Hills Corporation

Incorporated in South Dakota IRS Identification Number 46-0458824

7001 Mount Rushmore Road
Rapid City, South Dakota 57702
Registrant’s telephone number (605) 721-1700

Former name, former address, and former fiscal year if changed since last report
NONE

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

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 during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files). Yes No
Yes x
No o


Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large Accelerated FilerxAccelerated Filer
Large accelerated filer x
Accelerated filer o
Non-accelerated FilerSmaller Reporting Company
Non-accelerated filer o
(Do not check if a smaller reporting company)
Emerging Growth Company
Smaller reporting company o
Emerging growth company o


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


Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
.Yes No
Securities registered pursuant to Section 12(b) of the Act:
Yes o
Title of each class
No x
Trading Symbol(s)
Name of each exchange on which registered
Common stock of $1.00 par valueBKHNew York Stock Exchange


Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.
ClassOutstanding at October 31, 2020
Common stock, $1.00 par value62,746,692 shares


Table of Contents
TABLE OF CONTENTS
Page
Item 1.
ClassOutstanding at October 31, 2017
Common stock, $1.00 par value53,484,560
shares




















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TABLE OF CONTENTS
Page
Glossary of Terms and AbbreviationsItem 2.
PART I.FINANCIAL INFORMATION
Item 1.Financial Statements
Condensed Consolidated Statements of Income - unaudited
   Three and Nine Months Ended September 30, 2017 and 2016
Condensed Consolidated Statements of Comprehensive Income - unaudited
   Three and Nine Months Ended September 30, 2017 and 2016
Condensed Consolidated Balance Sheets - unaudited
   September 30, 2017, December 31, 2016 and September 30, 2016
Condensed Consolidated Statements of Cash Flows - unaudited
   Nine Months Ended September 30, 2017 and 2016
Notes to Condensed Consolidated Financial Statements - unaudited
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.
Item 4.
OTHER INFORMATION
Item 1.
Item 1A.
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds4.
Item 4.Mine Safety Disclosures6.
Item 5.Other Information
Item 6.Exhibits
Signatures




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GLOSSARY OF TERMS AND ABBREVIATIONS


The following terms and abbreviations appear in the text of this report and have the definitions described below:
AFUDCAllowance for Funds Used During Construction
AOCIAccumulated Other Comprehensive Income (Loss)
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).
AFUDCASCAllowance for Funds Used During Construction
AOCIAccumulated Other Comprehensive Income (Loss)
APSCArkansas Public Service Commission
Arkansas GasBlack Hills Energy Arkansas, Inc., a direct, wholly-owned subsidiary of Black Hills Gas Inc.
Stockton StorageArkansas Gas storage facility
ARMRPAt-Risk Meter Relocation Program
ASCAccounting Standards Codification
ASUAccounting Standards Update issued by the FASB
ATMAt-the-market equity offering program
Availability
AvailabilityThe availability factor of a power plant is the percentage of the time that it is available to provide energy.
BblBarrel
BHCBlack Hills Corporation; the Company
Black Hills GasColorado IPPBlack Hills Gas,Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Gas Holdings, which was previously named SourceGas LLCElectric Generation
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 operationsServices Company, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas commodity supply for the Choice Gas Programs (doing business as Black Hills Energy).
Black Hills 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 South Dakota ElectricIncludes Black Hills Power 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.
Black Hills Non-regulated HoldingsBlack Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills PowerBlack Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy). Also known as South Dakota Electric.
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
BtuBritish thermal unit
CAPPCustomer Appliance Protection Plan


Ceiling TestRelated
CARES ActCoronavirus Aid, Relief, and Economic Security Act, signed on March 27, 2020, which is a tax and spending package intended to our Oilprovide additional economic relief and Gas subsidiary, capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test which limitsaddress the pooled costs to the aggregateimpact of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using prices and a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties.COVID-19 pandemic.
Cheyenne LightCheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service in the Cheyenne, Wyoming area (doing business as Black Hills Energy). Also known as Wyoming Electric.
CIACContribution In Aid of Construction
Choice Gas ProgramRegulator-approved programs in Wyoming and Nebraska that allow certain utility customers to select their natural gas commodity supplier, providing for the unbundling of the commodity service from the distribution delivery service.
City of Colorado SpringsColorado Springs, Colorado
City of GilletteGillette, 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 GasBlack Hills Colorado Gas Utility Company, LP, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
Colorado IPPBlack Hills Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Electric Generation
Consolidated Indebtedness to Capitalization RatioAny Indebtednessindebtedness 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 temperaturetemperatures 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 stabilitythe Renewable Ready program.
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COVID-19The official name for the Company’s utility customers, along with2019 novel coronavirus disease announced on February 11, 2020, by the World Health Organization, that is causing a reasonable expectation of customer savings over the life of the program.global pandemic
CP ProgramCommercial Paper Program
CPUCColorado Public Utilities Commission
CVA
CVACredit Valuation Adjustment
Dodd-Frank
Dodd-FrankDodd-Frank Wall Street Reform and Consumer Protection Act
DSMDRSPPDemand Side ManagementDividend Reinvestment and Stock Purchase Plan
DthDekatherm. A unit of energy equal to 10 therms or approximately one million British thermal units (MMBtu)
ECAEnergy Cost Adjustment - adjustments that allow us to pass the prudently-incurred cost of fuel and purchased energy through to customers.
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.
FASB
FASBFinancial Accounting Standards Board
FERCUnited States Federal Energy Regulatory Commission
FitchFitch Ratings Inc.
GAAPAccounting principles generally accepted in the United States of America
Global SettlementSettlement with a utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders.
GSRSGas System Reliability Surcharge
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.
HomeServeRepair service plans offered to electric and natural gas residential customers that cover parts and labor to repair electrical, gas, heating, cooling, and water systems.
ICFRInternal Controls over Financial Reporting
Iowa GasBlack Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Iowa (doing business as Black Hills Energy).
IPPIndependent power producerPower Producer
IRSUnited States Internal Revenue Service


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).
KCCKansas Corporation Commission
kVKilovolt
LIBORLondon Interbank Offered Rate
LOELease Operating Expense
McfThousand cubic feet
McfeThousand cubic feet equivalent
MMBtu
MMBtuMillion British thermal units
Moody’s
Moody’sMoody’s Investors Service, Inc.
MRPMeter Relocation Program
MWMegawattsMegawatt
MWhMegawatt-hoursMegawatt-hour
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).
NGLNatural Gas Liquids (1 barrel equals 6 Mcfe)
NOLNet Operating Loss
NPSC
NPSCNebraska Public Service Commission
NYMEXNew York Mercantile Exchange
NYSENew York Stock Exchange
Peak View Wind Project$109 million 60 MW wind generating project for Colorado Electric, adjacent to Busch Ranch wind farm
PPA
OCAOffice of Consumer Advocate
OCCOffice of Consumer Counsel
OCIOther Comprehensive Income
PPAPower Purchase Agreement
PRPAPlatte River Power Authority
PSAPower Sales Agreement
Pueblo Airport Generation420 MW combined cycle gas-fired power generation plants jointly owned by Colorado Electric (220 MW) and Black Hills Colorado IPP (200 MW). Black Hills Colorado IPP owns and operates this facility. The plants commenced operation on January 1, 2012.
Renewable AdvantageA 200 MW solar facility project to be constructed in Pueblo County, Colorado. The project aims to lower customer energy costs and provide economic and environmental benefits to Colorado Electric’s customers and communities. This project, which was approved by the CPUC in September 2020, will be owned by a third-party renewable energy developer with Colorado Electric purchasing all of the energy generated at the facility under the terms of a 15-year PPA. The project is expected to be placed in service in 2023.
Renewable ReadyVoluntary renewable energy subscription program for large commercial, industrial and governmental agency customers in South Dakota and Wyoming.
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Revolving Credit FacilityOur $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which matures in 2021.was amended and restated on July 30, 2018, and now terminates on July 30, 2023.
RMNGRocky Mountain Natural Gas, a regulated gas utility acquired in the SourceGas Acquisition that provides regulated transmission and wholesale natural gas service to Black Hills Gas in western Colorado (doing business as Black Hills Energy)
RSNsSDPUCRemarketable junior subordinated notes, issued on November 23, 2015
SDPUCSouth Dakota Public Utilities Commission
SECU. S.United States Securities and Exchange Commission
SourceGasSourceGas Holdings LLC and its subsidiaries, a gas utility owned by funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) that was acquired on February 12, 2016, and is now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy)
SourceGas AcquisitionService Guard Comfort PlanThe acquisition of SourceGas Holdings, LLC by Black Hills Utility HoldingsNew plan that consolidated Service Guard and Customer Appliance Protection Plan (CAPP) and provides similar home appliance repair services through on-going monthly service agreements to residential utility customers.
SourceGas TransactionS&POn 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.
S&PStandard and Poor’s, a division of The McGraw-Hill Companies, Inc.
South Dakota ElectricIncludes Black Hills Power, operationsInc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and Wyoming and Montana(doing business as Black Hills Energy).
SSIRSystem Safety and Integrity Rider
TCATransmission Cost Adjustment -- adjustments passed through to the customer based on transmission costs that are higher or lower than the costs approved in the rate case.
VIEVariable interest entity
Winter Storm AtlasTCJAAn October 2013 blizzard that impacted South Dakota Electric. It was the second most severe blizzard in Rapid City’s history.Tax Cuts and Jobs Act
WRDCTech ServicesNon-regulated product lines within Black Hills Corporation that 1) provide electrical system construction services to large industrial customers of our electric utilities and 2) serve gas transportation customers throughout its service territory by constructing and maintaining customer-owner gas infrastructure facilities, typically through one-time contracts.
UtilitiesBlack Hills’ Electric and Gas Utilities
Wind Capacity FactorMeasures the amount of electricity a wind turbine produces in a given time period relative to its maximum potential
WPSCWyoming Public Service Commission
WRDCWyodak Resources Development Corp.,Corporation, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings (doing business as Black Hills Energy)
Wygen IA 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 Municipal Energy Agency of Nebraska (MEAN) owns the remaining 23.5%.
Wyodak PlantWyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, is owned 80% by PacificorpPacifiCorp and 20% by Black Hills Energy South Dakota.Dakota Electric. Our WRDC mine supplies all of the fuel for the plant.
Wyoming Electric
Includes Cheyenne Light’sLight, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric utility operations

service to customers in the Cheyenne, Wyoming area (doing business as Black Hills Energy).
Wyoming GasIncludes Cheyenne Light’sBlack Hills Wyoming Gas, LLC, an indirect and wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas utility operations,services to customers in Wyoming (doing business as well as the acquired SourceGas utility Black Hills Gas Distribution’s Wyoming gas operationsEnergy).

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PART I.     FINANCIAL INFORMATION


ITEM 1.    FINANCIAL STATEMENTS

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(in thousands, except per share amounts)
Revenue$346,590 $325,548 $1,210,554 $1,257,246 
Operating expenses:
Fuel, purchased power and cost of natural gas sold71,686 73,544 331,194 413,486 
Operations and maintenance122,759 116,583 365,533 365,116 
Depreciation, depletion and amortization56,348 51,884 169,413 154,507 
Taxes - property and production13,563 12,986 42,062 39,454 
Total operating expenses264,356 254,997 908,202 972,563 
Operating income82,234 70,551 302,352 284,683 
Other income (expense):
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)(36,521)(34,000)(108,067)(103,677)
Interest income480 513 1,028 1,208 
Impairment of investment(19,741)(6,859)(19,741)
Other income (expense), net(1,193)580 (703)55 
Total other income (expense)(37,234)(52,648)(114,601)(122,155)
Income before income taxes45,000 17,903 187,751 162,528 
Income tax (expense)(4,651)(2,508)(25,484)(22,078)
Net income40,349 15,395 162,267 140,450 
Net income attributable to noncontrolling interest(4,066)(3,655)(11,844)(10,319)
Net income available for common stock$36,283 $11,740 $150,423 $130,131 
Earnings per share of common stock:
Earnings per share, Basic$0.58 $0.19 $2.41 $2.15 
Earnings per share, Diluted$0.58 $0.19 $2.41 $2.15 
Weighted average common shares outstanding:
Basic62,575 60,976 62,310 60,458 
Diluted62,630 61,104 62,362 60,578 
(unaudited)Three Months Ended
September 30,
Nine Months Ended
September 30,
 2017201620172016
 (in thousands, except per share amounts)
     
Revenue$342,138
$333,786
$1,244,119
$1,109,186
     
Operating expenses:    
Fuel, purchased power and cost of natural gas sold86,281
80,194
404,222
336,539
Operations and maintenance114,648
115,103
354,152
334,706
Depreciation, depletion and amortization49,434
48,925
146,744
140,637
Taxes - property, production and severance13,092
12,114
40,804
36,991
Impairment of long-lived assets
12,293

52,286
Other operating expenses164
6,748
3,301
40,730
Total operating expenses263,619
275,377
949,223
941,889
     
Operating income78,519
58,409
294,896
167,297
     
Other income (expense):    
Interest charges -    
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts)(35,305)(37,306)(105,499)(103,989)
Allowance for funds used during construction - borrowed753
860
2,061
2,115
Capitalized interest149
282
448
785
Interest income402
912
700
2,513
Allowance for funds used during construction - equity696
1,211
1,982
2,900
Other income (expense), net189
160
29
801
Total other income (expense), net(33,116)(33,881)(100,279)(94,875)
     
Income before income taxes45,403
24,528
194,617
72,422
Income tax benefit (expense)(13,805)(6,644)(57,562)(11,205)
Net income31,598
17,884
137,055
61,217
Net income attributable to noncontrolling interest(3,935)(3,753)(10,674)(6,415)
Net income available for common stock$27,663
$14,131
$126,381
$54,802
     
Earnings per share of common stock:    
Earnings per share, Basic$0.52
$0.27
$2.38
$1.06
Earnings per share, Diluted$0.50
$0.26
$2.29
$1.04
Weighted average common shares outstanding:    
Basic53,243
52,184
53,208
51,583
Diluted55,432
53,733
55,254
52,893
     
Dividends declared per share of common stock$0.445
$0.420
$1.335
$1.260


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


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BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited)Three Months Ended
September 30,
Nine Months Ended
September 30,
2020201920202019
(in thousands)
Net income$40,349 $15,395 $162,267 $140,450 
Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (net of tax of $0,$0, $(17) and $0, respectively)55 
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $6, $3, $19 and $13, respectively)(18)(16)(60)(45)
Reclassification adjustments of benefit plan liability - net gain (net of tax of $(149), $(92), $(426) and $(197), respectively)448 (9)1,365 327 
Derivative instruments designated as cash flow hedges:
Reclassification of net realized losses on settled/amortized interest rate swaps (net of tax of $(168), $(165), $(508) and $(500), respectively)544 548 1,630 1,639 
Net unrealized gains (losses) on commodity derivatives (net of tax of $(112), $35, $(44) and $100, respectively)401 (115)181 (334)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $(41), $(5), $(172), and $142, respectively)137 124 562 (366)
Other comprehensive income, net of tax1,512 532 3,733 1,221 
Comprehensive income41,861 15,927 166,000 141,671 
Less: comprehensive income attributable to noncontrolling interest(4,066)(3,655)(11,844)(10,319)
Comprehensive income available for common stock$37,795 $12,272 $154,156 $131,352 

(unaudited)Three Months Ended
September 30,
Nine Months Ended
September 30,
 2017201620172016
 (in thousands)
     
Net income$31,598
$17,884
$137,055
$61,217
     
Other comprehensive income (loss), net of tax:    
Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $17 and $19 for the three months ended September 30, 2017 and 2016 and $52 and $57 for the nine months ended September 30, 2017 and 2016, respectively)(32)(36)(94)(108)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(145) and $(171) for the three months ended September 30, 2017 and 2016 and $(445) and $(517) for the nine months ended September 30, 2017 and 2016, respectively)269
323
797
966
Derivative instruments designated as cash flow hedges:    
Net unrealized gains (losses) on interest rate swaps (net of tax of $0 and $163 for the three months ended September 30, 2017 and 2016 and $0 and $10,930 for the nine months ended September 30, 2017 and 2016, respectively)
(302)
(20,200)
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(249) and $(294) for the three months ended September 30, 2017 and 2016 and $(779) and $(886) for the nine months ended September 30, 2017 and 2016, respectively)464
546
1,449
1,644
Net unrealized gains (losses) on commodity derivatives (net of tax of $94 and $(423) for the three months ended September 30, 2017 and 2016 and $(442) and $(324) for the nine months ended September 30, 2017 and 2016, respectively)(160)(249)755
(417)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $95 and $860 for the three months ended September 30, 2017 and 2016 and $344 and $3,337 for the nine months ended September 30, 2017 and 2016, respectively)(166)(1,469)(590)(5,781)
Other comprehensive income (loss), net of tax375
(1,187)2,317
(23,896)
     
Comprehensive income31,973
16,697
139,372
37,321
Less: comprehensive income attributable to noncontrolling interest(3,935)(3,753)(10,674)(6,415)
Comprehensive income available for common stock$28,038
$12,944
$128,698
$30,906

See Note 1311 for additional disclosures.


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


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BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)As of
September 30, 2020December 31, 2019
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents$6,955 $9,777 
Restricted cash and equivalents4,257 3,881 
Accounts receivable, net160,478 255,805 
Materials, supplies and fuel126,358 117,172 
Derivative assets, current2,001 342 
Income tax receivable, net20,828 16,446 
Regulatory assets, current49,493 43,282 
Other current assets33,287 26,479 
Total current assets403,657 473,184 
Investments15,659 21,929 
Property, plant and equipment7,128,387 6,784,679 
Less: accumulated depreciation and depletion(1,276,410)(1,281,493)
Total property, plant and equipment, net5,851,977 5,503,186 
Other assets:
Goodwill1,299,454 1,299,454 
Intangible assets, net12,242 13,266 
Regulatory assets, non-current221,743 228,062 
Other assets, non-current24,318 19,376 
Total other assets, non-current1,557,757 1,560,158 
TOTAL ASSETS$7,829,050 $7,558,457 

(unaudited)As of
 September 30,
2017
 December 31, 2016 September 30,
2016
 (in thousands)
ASSETS     
Current assets:     
Cash and cash equivalents$13,510
 $13,580
 $31,814
Restricted cash and equivalents2,683
 2,274
 2,140
Accounts receivable, net153,832
 263,289
 154,617
Materials, supplies and fuel126,520
 107,210
 113,475
Derivative assets, current657
 4,138
 4,382
Regulatory assets, current61,023
 49,260
 50,561
Other current assets26,793
 27,063
 30,032
Total current assets385,018
 466,814
 387,021
      
Investments12,947
 12,561
 12,416
      
Property, plant and equipment6,615,098
 6,412,223
 6,306,119
Less: accumulated depreciation and depletion(2,020,331) (1,943,234) (1,841,116)
Total property, plant and equipment, net4,594,767
 4,468,989
 4,465,003
      
Other assets:     
Goodwill1,299,454
 1,299,454
 1,300,379
Intangible assets, net7,765
 8,392
 8,944
Regulatory assets, non-current239,571
 246,882
 234,240
Derivative assets, non-current
 222
 183
Other assets, non-current11,655
 12,130
 12,800
Total other assets, non-current1,558,445
 1,567,080
 1,556,546
      
TOTAL ASSETS$6,551,177
 $6,515,444
 $6,420,986

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

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BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
(unaudited)As of
September 30, 2020December 31, 2019
(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable$152,010 $193,523 
Accrued liabilities244,010 226,767 
Derivative liabilities, current1,439 2,254 
Regulatory liabilities, current22,282 33,507 
Notes payable84,320 349,500 
Current maturities of long-term debt9,871 5,743 
Total current liabilities513,932 811,294 
Long-term debt, net of current maturities3,526,894 3,140,096 
Deferred credits and other liabilities:
Deferred income tax liabilities, net398,136 360,719 
Regulatory liabilities, non-current505,317 503,145 
Benefit plan liabilities144,049 154,472 
Other deferred credits and other liabilities120,522 124,662 
Total deferred credits and other liabilities1,168,024 1,142,998 
Commitments and contingencies (See Notes 7, 9, 12, 13)
Equity:
Stockholders’ equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 62,773,015 and 61,480,658 shares, respectively62,773 61,481 
Additional paid-in capital1,655,912 1,552,788 
Retained earnings828,993 778,776 
Treasury stock, at cost – 24,897 and 3,956 shares, respectively(1,710)(267)
Accumulated other comprehensive income (loss)(26,922)(30,655)
Total stockholders’ equity2,519,046 2,362,123 
Noncontrolling interest101,154 101,946 
Total equity2,620,200 2,464,069 
TOTAL LIABILITIES AND TOTAL EQUITY$7,829,050 $7,558,457 
(unaudited)As of
 September 30,
2017
 December 31, 2016 September 30,
2016
 (in thousands, except share amounts)
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND TOTAL EQUITY     
Current liabilities:     
Accounts payable$95,595
 $153,477
 $110,630
Accrued liabilities213,571
 244,034
 228,522
Derivative liabilities, current1,562
 2,459
 1,941
Accrued income taxes, net5,587
 12,552
 10,909
Regulatory liabilities, current7,042
 13,067
 16,925
Notes payable225,170
 96,600
 75,000
Current maturities of long-term debt5,743
 5,743
 5,743
Total current liabilities554,270
 527,932
 449,670
      
Long-term debt3,109,864
 3,211,189
 3,211,768
      
Deferred credits and other liabilities:     
Deferred income tax liabilities, net, non-current605,744
 535,606
 533,865
Derivative liabilities, non-current74
 274
 317
Regulatory liabilities, non-current198,189
 193,689
 186,496
Benefit plan liabilities149,803
 173,682
 171,633
Other deferred credits and other liabilities137,251
 138,643
 141,007
Total deferred credits and other liabilities1,091,061
 1,041,894
 1,033,318
      
Commitments and contingencies (See Notes 8, 10, 15, 16)

 
 
      
Redeemable noncontrolling interest
 4,295
 4,206
      
Equity:     
Stockholders’ equity —     
Common stock $1 par value; 100,000,000 shares authorized; issued 53,524,529; 53,397,467; and 53,131,469 shares, respectively53,525
 53,397
 53,131
Additional paid-in capital1,147,922
 1,138,982
 1,123,527
Retained earnings516,371
 457,934
 462,090
Treasury stock, at cost – 41,457; 15,258; and 22,368 shares, respectively(2,448) (791) (1,155)
Accumulated other comprehensive income (loss)(32,566) (34,883) (32,951)
Total stockholders’ equity1,682,804
 1,614,639
 1,604,642
Noncontrolling interest113,178
 115,495
 117,382
Total equity1,795,982
 1,730,134
 1,722,024
      
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND TOTAL EQUITY$6,551,177
 $6,515,444
 $6,420,986


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


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BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)Nine Months Ended September 30,(unaudited)Nine Months Ended September 30,
2017201620202019
Operating activities:(in thousands)Operating activities:(in thousands)
Net income$137,055
$54,802
Net income$162,267 $140,450 
Adjustments to reconcile net income to net cash provided by operating activities: Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization146,744
140,637
Depreciation, depletion and amortization169,413 154,507 
Deferred financing cost amortization6,212
4,002
Deferred financing cost amortization5,523 6,326 
Impairment of long-lived assets
52,286
Derivative fair value adjustments1,931
(7,308)
Impairment of investmentImpairment of investment6,859 19,741 
Stock compensation7,594
9,124
Stock compensation2,696 8,332 
Deferred income taxes64,672
38,578
Deferred income taxes28,502 24,381 
Employee benefit plans8,470
11,830
Employee benefit plans9,294 7,965 
Other adjustments, net(5,550)(2,076)Other adjustments, net7,910 9,192 
Changes in certain operating assets and liabilities: Changes in certain operating assets and liabilities:
Materials, supplies and fuel(19,560)(5,166)Materials, supplies and fuel(10,905)(4,126)
Accounts receivable, unbilled revenues and other operating assets107,026
78,869
Accounts payable and other operating liabilities(101,471)(117,631)
Accounts receivable and other current assetsAccounts receivable and other current assets75,960 115,325 
Accounts payable and other current liabilitiesAccounts payable and other current liabilities(11,136)(83,436)
Regulatory assets - current1,287
8,453
Regulatory assets - current1,954 12,455 
Regulatory liabilities - current(4,328)(8,181)Regulatory liabilities - current(17,686)(15,644)
Contributions to defined benefit pension plans(27,700)(14,200)Contributions to defined benefit pension plans(12,700)(12,700)
Interest rate swap settlement
(28,820)
Other operating activities, net(2,952)(5,998)Other operating activities, net1,508 3,307 
Net cash provided by (used in) operating activities319,430
209,201
Net cash provided by operating activitiesNet cash provided by operating activities419,459 386,075 
 
Investing activities: Investing activities:
Property, plant and equipment additions(256,138)(334,098)Property, plant and equipment additions(535,993)(592,537)
Acquisition, net of long term debt assumed
(1,124,238)
Other investing activities(250)(860)Other investing activities6,269 (735)
Net cash provided by (used in) investing activities(256,388)(1,459,196)
Net cash (used in) investing activitiesNet cash (used in) investing activities(529,724)(593,272)
 
Financing activities: Financing activities:
Dividends paid on common stock(71,334)(65,247)Dividends paid on common stock(99,999)(91,779)
Common stock issued3,562
107,690
Common stock issued99,316 101,361 
Sale of noncontrolling interest
216,370
Net (payments) borrowings of short-term debt128,570
(1,800)Net (payments) borrowings of short-term debt(265,180)109,280 
Long-term debt - issuances
1,767,608
Long-term debt - issuances400,000 400,000 
Long-term debt - repayments(104,307)(1,162,872)Long-term debt - repayments(7,163)(304,307)
Distributions to noncontrolling interest(12,884)(4,516)Distributions to noncontrolling interest(12,636)(12,736)
Other financing activities(6,719)(16,285)Other financing activities(6,519)(1,992)
Net cash provided by (used in) financing activities(63,112)840,948
Net change in cash and cash equivalents(70)(409,047)
Cash and cash equivalents, beginning of period13,580
440,861
Cash and cash equivalents, end of period$13,510
$31,814
Net cash provided by financing activitiesNet cash provided by financing activities107,819 199,827 
Net change in cash, restricted cash and cash equivalentsNet change in cash, restricted cash and cash equivalents(2,446)(7,370)
Cash, restricted cash and cash equivalents at beginning of periodCash, restricted cash and cash equivalents at beginning of period13,658 24,145 
Cash, restricted cash and cash equivalents at end of periodCash, restricted cash and cash equivalents at end of period$11,212 $16,775 
Supplemental cash flow information:Supplemental cash flow information:
Cash (paid) refunded during the period:Cash (paid) refunded during the period:
Interest (net of amounts capitalized)Interest (net of amounts capitalized)$(87,453)$(99,375)
Income taxesIncome taxes$1,256 $2,255 
Non-cash investing and financing activities:Non-cash investing and financing activities:
Accrued property, plant and equipment purchases at September 30Accrued property, plant and equipment purchases at September 30$86,474 $86,661 


See Note 14 for supplemental disclosure of cash flow information.

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


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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(unaudited)Common StockTreasury Stock
(in thousands except share amounts)SharesValueSharesValueAdditional Paid in CapitalRetained EarningsAOCINon controlling InterestTotal
December 31, 201961,480,658 $61,481 3,956 $(267)$1,552,788 $778,776 $(30,655)$101,946 $2,464,069 
Net income available for common stock— — — — — 93,174 — 4,050 97,224 
Other comprehensive income (loss), net of tax— — — — — — 1,273 — 1,273 
Dividends on common stock ($0.535 per share)— — — — — (32,902)— — (32,902)
Share-based compensation69,378 69 20,700 (1,658)2,263 — — — 674 
Issuance of common stock1,222,942 1,223 — — 98,777 — — — 100,000 
Issuance costs— — — — (967)— — — (967)
Implementation of ASU 2016-13 Financial Instruments - - Credit Losses— — — — — (207)— — (207)
Distributions to noncontrolling interest— — — — — — — (4,741)(4,741)
March 31, 202062,772,978 $62,773 24,656 $(1,925)$1,652,861 $838,841 $(29,382)$101,255 $2,624,423 
Net income available for common stock20,966 — 3,728 24,694 
Other comprehensive income (loss), net of tax— — — — — — 948 — 948 
Dividends on common stock ($0.535 per share)— — — — — (33,538)— — (33,538)
Share-based compensation18 — 1,743 46 1,781 — — — 1,827 
Issuance costs— — — — (79)— — — (79)
Distributions to noncontrolling interest— — — — — — — (3,779)(3,779)
June 30, 202062,772,996 $62,773 26,399 $(1,879)$1,654,563 $826,269 $(28,434)$101,204 $2,614,496 
Net income available for common stock— — — — — 36,283 — 4,066 40,349 
Other comprehensive income, net of tax— — — — — — 1,512 — 1,512 
Dividends on common stock (0.535 per share)— — — — — (33,559)— — (33,559)
Share-based compensation19 — (1,502)169 1,468 — — — 1,637 
Issuance costs— — — — (119)— — — (119)
Distributions to noncontrolling interest— — — — — — — (4,116)(4,116)
September 30, 202062,773,015 $62,773 24,897 $(1,710)$1,655,912 $828,993 $(26,922)$101,154 $2,620,200 
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Common StockTreasury Stock
(in thousands except share amounts)SharesValueSharesValueAdditional Paid in CapitalRetained EarningsAOCINon controlling InterestTotal
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 available for common stock— — — — — 103,808 — 3,554 107,362 
Other comprehensive income (loss), net of tax— — — — — — 457 — 457 
Dividends on common stock ($0.505 per share)— — — — — (30,332)— — (30,332)
Share-based compensation48,956 49 (20,497)1,078 (589)— — — 538 
Tax effect of share-based compensation— — — — — — — — — 
Issuance of common stock280,497 280 — — 19,719 — — — 19,999 
Issuance costs— — — — (289)— — — (289)
Implementation of ASU 2016-02 Leases— — — — — 3,390 — — 3,390 
Distributions to noncontrolling interest— — — — — — — (4,846)(4,846)
March 31, 201960,378,020 $60,378 23,756 $(1,432)$1,469,410 $777,262 $(26,459)$104,543 $2,383,702 
Net income available for common stock— — — — — 14,583 — 3,110 17,693 
Other comprehensive income, net of tax— — — — — — 232 — 232 
Dividends on common stock ($0.505 per share)— — — — — (30,620)— — (30,620)
Share-based compensation54,767 54 1,603 (112)3,948 — — — 3,890 
Tax effect of share-based compensation— — — — — — — — — 
Issuance of common stock658,598 659 — — 49,342 — — — 50,001 
Issuance costs— — — — (492)— — — (492)
Implementation of ASU 2016-02 Leases— — — — — (3)— — (3)
Distributions to noncontrolling interest— — — — — — — (4,405)(4,405)
June 30, 201961,091,385 $61,091 25,359 $(1,544)$1,522,208 $761,222 $(26,227)$103,248 $2,419,998 
Net income available for common stock— — — — — 11,740 — 3,655 15,395 
Other comprehensive income, net of tax— — — — — — 532 — 532 
Dividends on common stock ($0.505 per share)— — — — — (30,827)— — (30,827)
Share-based compensation18 1,213 (92)1,769 — — — 1,677 
Tax effect of share-based compensation— — — — — — — — — 
Issuance of common stock389,237 390 — — 29,611 — — — 30,001 
Issuance costs— — — — (398)— — — (398)
Implementation of ASU 2016-02 Leases— — — — — — — 
Distributions to noncontrolling interest— — — — — — — (3,485)(3,485)
September 30, 201961,480,640 $61,481 26,572 $(1,636)$1,553,190 $742,138 $(25,695)$103,418 $2,432,896 

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BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 20162019 Annual Report on Form 10-K)


(1)    MANAGEMENT’S STATEMENT(1)    Management’s Statement


The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company,” “us,” “we,”“Company”, “us”, “we” or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of AmericaGAAP have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Condensed Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 20162019 Annual Report on Form 10-K filed with the SEC.


Segment Reporting


We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation Mining and Oil and Gas.Mining. 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.

On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. We have initiated the process of divesting all Oil and Gas segment assets in order to fully exit the oil and gas business. We anticipate selling or otherwise disposing of all remaining oil and gas properties and assets by year-end 2018 and have retained advisors to accelerate the marketing and sales process. The Company’s Condensed Consolidated Financial Statements and accompanying Notes as of and for the three and nine months ended September 30, 2017 include the Oil and Gas segment’s assets and liabilities, results of operations and cash flows within continuing operations, as we did not meet the criteria for classifying assets as held for sale and presenting the segment’s activities as discontinued operations during the quarter. See Note 20.


Use of Estimates and Basis of Presentation


The information furnished in the accompanying Condensed Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the September 30, 2017,2020, December 31, 2016,2019 and September 30, 20162019 financial information and are of a normal recurring nature.information. Certain industries in which we operate are highly seasonal and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market prices.requirements. In particular, the normal peak usage season for electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and nine months ended September 30, 20172020 and September 30, 2016,2019, and our financial condition as of September 30, 2017,2020 and December 31, 2016, and September 30, 2016,2019 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. September 30, 2017 reflects a full nine months of activity from the SourceGas Acquisition on February 12, 2016, as compared to the nine months ended September 30, 2016 which reflects a partial period of approximately 7.5 months. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.


RevisionsReclassification


Certain revisions have been made to prior years’ financial information to conform to the current year presentation.
The Company revised its presentationWe changed certain classifications of cash as of December 31, 2016.  The Company has banking arrangements at certain financial institutions whereby if required, payments of one account are cleared with cash from other accounts at the same financial institution; therefore, book overdrafts are presentedoperating expenses 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 $31 million as of September 30, 2016, and decreased net cash flows provided by operations by $15 million for the nine months ended September 30, 2016. We assessed the materiality of these changes, taking into account quantitative and qualitative factors, and determined them to be immaterial to the Condensed Consolidated Balance Sheet as of September


30, 2016 and to the Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2016. There is no impact to the Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2019 to conform with current year presentation. The prior year reclassifications, which are shown in the table below, did not impact previously reported operating income or net income.

Three Months Ended September 30, 2019Nine Months Ended September 30, 2019
(in millions)
Fuel, purchased power and cost of natural gas sold$0.5 $1.8 
Operations and maintenance(0.5)(1.8)
Operating income$$

COVID-19 Pandemic

In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the outbreak a national emergency.  The U.S. government has deemed electric and natural gas utilities to be critical infrastructure sectors that provide essential services during this emergency.  As a provider of essential services, the Company has an obligation to provide services to our customers.  The Company remains focused on protecting the health of our employees and the communities in which we operate while assuring the continuity of our business operations.
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The Company’s Condensed Consolidated Financial Statements reflect estimates and assumptions made by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Condensed Consolidated Financial Statements and reported amounts of Comprehensive Incomerevenue and expenses during the reporting periods presented.  The Company considered the impacts of COVID-19 on the assumptions and estimates used and determined that for any period reported.the three and nine months ended September 30, 2020, there were no material adverse impacts on the Company’s results of operations.


Change in Accounting Principle - Pension Accounting Asset Method

Effective January 1, 2020, we changed our method of accounting for net periodic benefit cost. Prior to the change, the Company used a calculated value for determining market-related value of plan assets which amortized the effects of gains and losses over a five-year period. Effective with the accounting change, the Company will use a calculated value for the return-seeking assets (equities) in the portfolio and change to fair value for the liability-hedging assets (fixed income). See Note 12 for additional information.

Recently Issued Accounting Standards


Revenue from Contracts with Customers,Simplifying the Accounting for Income Taxes, ASU 2014-092019-12


In May 2014,December 2019, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model2019-12, Simplifying the Accounting for useIncome Taxes, as part of its overall simplification initiative to reduce costs and complexity in applying accounting standards while maintaining or improving the usefulness of the information provided to users of the financial statements. Amendments include removal of certain exceptions to the general principles of ASC 740, Income Taxes, and simplification in several other areas such as accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance.a franchise tax (or similar tax) that is partially based on income. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017 with early adoption on January 1, 2017 permitted. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption.

We currently expect to implement the standard on a modified retrospective basis effective January 1, 2018. We have substantially completed our assessment of all sources of revenue and are currently determining the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. A majority 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 revenue from contracts with the customer will be equivalent to the electricity or gas delivered during that period. Therefore, we do not expect to have a significant shift in the timing or pattern of revenue recognition for regulated tariff based sales. We also continue to monitor outstanding industry implementation issues and assess the impacts to our current accounting policies and/or patterns of revenue recognition.

Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07

In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The changes to the standard require employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. This ASU will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and post-retirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and post-retirement benefit costs in assets will be applied on a prospective basis. This new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. We continue to assess the impact of this new standard on our financial statements and disclosures, and we monitor regulated utility industry implementation discussions and guidance. For our rate-regulated entities, we currently expect to capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities. The presentation changes required for net periodic pension and post-retirement costs will result in offsetting changes to Operating income and Other income which are not expected to be material. We will implement this standard effective January 1, 2018.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. The ASU will be effective for fiscal years beginning after December 15, 2017.We will use the retrospective transition method to implement this standard effective January 1, 2018. This standard will not have a material impact on our financial position, results of operations or cash flows.





Leases, ASU 2016-02

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for all leases with a term greater than 12 months, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted.

We currently expect to adopt this standard on January 1, 2019. We continue to evaluate the impact of this new standard on our financial position, results of operations and cash flows as well as monitor emerging guidance on such topics as easements and rights of way, pipeline laterals, purchase power agreements, and other industry-related areas. We have begun the process of identifying and categorizing our lease contracts and evaluating our current business processes.

Derivatives and Hedging: Targeted Improvement to Accounting for Hedging Activities, 2017-12

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvement to Accounting for Hedging Activities. This standard better aligns risk management activities and financial reporting for hedging relationships, simplifies hedge accounting requirements and improves disclosures of hedging arrangements. This ASU is effective for fiscal years beginning after December 15, 2018,2020 with early adoption permitted. We are currently reviewing this standard to assess the impact on our financial position, results of operations and cash flows.


Recently Adopted Accounting Standards


Improvements to Employee Share-Based Payment Accounting,Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, ASU 2016-092016-13


In MarchJune 2016, the FASB issued ASU 2016-09, Improvements2016-13, Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, which was subsequently amended by ASUs 2018-19, 2019-04, 2019-05, 2019-10, and 2019-11. The standard introduces new accounting guidance for credit losses on financial instruments within its scope, including trade receivables. This new guidance adds an impairment model that is based on expected losses rather than incurred losses.

We adopted this standard on January 1, 2020 with prior year comparative financial information remaining as previously reported when transitioning to Employee Share-Based Payment Accounting. This ASU simplifies several aspectsthe new standard. On January 1, 2020, we recorded an increase to our allowance for credit losses, primarily associated with the inclusion of expected losses on unbilled revenue. The cumulative effect of the accountingadoption, net of tax impact, was $0.2 million, which was recorded as an adjustment to retained earnings.

Simplifying the Test for employee share-based payment transactions, includingGoodwill Impairment, ASU 2017-04

In January 2017, the accountingFASB issued ASU 2017-04, Simplifying the Test for forfeitures, income taxes, and statutory tax withholding requirements. The ASU was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. Certain amendmentsGoodwill Impairment, by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit. We adopted this standard prospectively on January 1, 2020. Adoption of this guidance did not have an impact on our financial position, results of operations or cash flows.

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

In August 2018, the FASB issued ASU 2018-15, Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, which aligns the requirements for recording implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. As a result, certain categories of implementation costs that previously would have been charged to expense as incurred are to be applied retrospectivelynow capitalized as prepayments and others prospectively.amortized over the term of the arrangement. We implementedadopted this ASU effectivestandard prospectively on January 1, 2017, recording a cumulative-effect adjustment to retained earnings as of the date of adoption of $3.2 million in the Condensed Consolidated Balance Sheets, representing previously recorded forfeitures and excess tax benefits generated in years prior to 2017 that were previously not recognized in stockholders’ equity due to NOLs in those years.2020. Adoption of this ASUguidance did not have a material impact on our consolidated financial position, results of operations or cash flows.




(2)    ACQUISITIONRevenue


2016 AcquisitionOur revenue contracts generally provide for performance obligations that: are fulfilled and transfer control to customers over time; represent a series of SourceGas

On February 12, 2016, Black Hills Corporation acquired SourceGas (now referred to as Black Hills Gas Holdings). We acquired SourceGas for $1.1 billiondistinct services that are substantially the same; involve the same pattern of cash plus the assumption of $760 million of long-term debt. We finalized our purchase price allocation at December 31, 2016. See Note 2 of our Notestransfer to the Consolidated Financial Statementscustomer; and provide a right to consideration from our customers in our 2016 Annual Report on Form 10-Kan amount that corresponds directly with the value to the customer for more details.

Pro Forma Results

the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice. The following unaudited pro forma financial information reflectstables depict the consolidated resultsdisaggregation of operations as if the SourceGas Acquisition had taken place on January 1, 2015. The unaudited pro forma financial information is presentedrevenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for illustrative purposes only and is not necessarily indicativeeach of the consolidated results of operations that would have been achieved or our future consolidated results.

The pro forma financial information does not reflect any potential cost savings from operating efficiencies resulting from the


acquisition and does not include certain acquisition-related costs that are not expected to have a continuing impact on the combined consolidated results. Pro forma resultsreportable segments for the three and nine months ended September 30, 2016 exclude approximately $3.8 million2020 and $23 million, respectively, of after-tax transaction costs, including professional fees, employee related expenses2019. Sales tax and other miscellaneous costs.similar taxes are excluded from revenues.

Three Months Ended September 30, 2020 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer types:(in thousands)
Retail$169,505 $94,367 $$14,668 $(8,100)$270,440 
Transportation38,196 (139)38,057 
Wholesale5,925 26,049 (24,521)7,453 
Market - off-system sales9,535 36 (1,904)7,667 
Transmission/Other15,653 10,277 (5,235)20,695 
Revenue from contracts with customers$200,618 $142,876 $26,049 $14,668 $(39,899)$344,312 
Other revenues224 1,053 469 568 (36)2,278 
Total revenues$200,842 $143,929 $26,518 $15,236 $(39,935)$346,590 
Timing of revenue recognition:
Services transferred at a point in time$$$$14,668 $(8,100)$6,568 
Services transferred over time200,618 142,876 26,049 (31,799)337,744 
Revenue from contracts with customers$200,618 $142,876 $26,049 $14,668 $(39,899)$344,312 
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 Three Months Ended September 30, 2016Nine Months Ended September 30, 2016
 (in thousands, except per share amounts)
Revenue$333,786
$1,188,148
Net income available for common stock$17,376
$89,973
Earnings per share, Basic$0.33
$1.74
Earnings per share, Diluted$0.32
$1.70
Three Months Ended September 30, 2019 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer Types:
Retail$162,214 $89,810 $$14,992 $(8,146)$258,870 
Transportation29,019 (195)28,824 
Wholesale8,210 16,119 (14,414)9,915 
Market - off-system sales6,452 139 (1,488)5,103 
Transmission/Other14,274 10,965 (4,206)21,033 
Revenue from contracts with customers$191,150 $129,933 $16,119 $14,992 $(28,449)$323,745 
Other revenues234 811 9,692 560 (9,494)1,803 
Total Revenues$191,384 $130,744 $25,811 $15,552 $(37,943)$325,548 
Timing of Revenue Recognition:
Services transferred at a point in time$$$$14,992 $(8,146)$6,846 
Services transferred over time191,150 129,933 16,119 (20,303)316,899 
Revenue from contracts with customers$191,150 $129,933 $16,119 $14,992 $(28,449)$323,745 

Nine Months Ended September 30, 2020 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer types:(in thousands)
Retail$459,949 $513,208 $$43,917 $(23,855)$993,219 
Transportation113,096 (416)112,680 
Wholesale14,947 77,234 (72,609)19,572 
Market - off-system sales17,940 197 (6,123)12,014 
Transmission/Other43,271 32,038 (14,080)61,229 
Revenue from contracts with customers$536,107 $658,539 $77,234 $43,917 $(117,083)$1,198,714 
Other revenues2,074 7,273 1,372 1,940 (819)11,840 
Total revenues$538,181 $665,812 $78,606 $45,857 $(117,902)$1,210,554 
Timing of revenue recognition:
Services transferred at a point in time$$$$43,917 $(23,855)$20,062 
Services transferred over time536,107 658,539 77,234 (93,228)1,178,652 
Revenue from contracts with customers$536,107 $658,539 $77,234 $43,917 $(117,083)$1,198,714 
Redemption
17


Table of seller’s noncontrolling interestContents

Nine Months Ended September 30, 2019 Electric Utilities Gas UtilitiesPower Generation MiningInter-company RevenuesTotal
Customer Types:
Retail$455,409 $567,715 $$43,249 $(23,315)$1,043,058 
Transportation102,159 (903)101,256 
Wholesale23,334 46,650 (40,923)29,061 
Market - off-system sales16,592 517 (5,047)12,062 
Transmission/Other42,865 35,767 (12,608)66,024 
Revenue from contracts with customers$538,200 $706,158 $46,650 $43,249 $(82,796)$1,251,461 
Other revenues2,465 1,135 29,114 1,777 (28,706)5,785 
Total Revenues$540,665 $707,293 $75,764 $45,026 $(111,502)$1,257,246 
Timing of Revenue Recognition:
Services transferred at a point in time$$$$43,249 $(23,315)$19,934 
Services transferred over time538,200 706,158 46,650 (59,481)1,231,527 
Revenue from contracts with customers$538,200 $706,158 $46,650 $43,249 $(82,796)$1,251,461 
As part
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 SourceGas Transaction, a seller retained a 0.5% noncontrolling interestbalance in our Accounts Receivable further discussed in Note 4.


(3)    Business Segment Information

Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and we entered into an associated option agreement withregulation. All of our operations and assets are located within the holder for the 0.5% retained interest. The terms of the agreement provided us a call option to purchase the remaining interest beginning 366 days after the initial close of the SourceGas Transaction. In March 2017, we exercised our call option and purchased the remaining 0.5% equity interest in SourceGas for $5.6 million.United States.

(3)    BUSINESS SEGMENT INFORMATION


Segment information and Corporate activities included in the accompanying Condensed Consolidated Statements of Income wereand Other information is as follows (in thousands):
Three Months Ended September 30, 2020External Operating
Revenue
Inter-company Operating RevenueTotal Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities$194,941 $224 $5,677 $$200,842 
Gas Utilities141,275 863 1,601 190 143,929 
Power Generation1,528 414 24,521 55 26,518 
Mining6,568 777 8,100 (209)15,236 
Inter-company eliminations— — (39,899)(36)(39,935)
Total$344,312 $2,278 $$$346,590 
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Table of Contents
Three Months Ended September 30, 2017 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 Net Income (Loss) Available for Common Stock
Segment:      
Electric $181,238
 $2,333
 $27,324
Gas 142,821
 73
 (4,329)
Power Generation (b)
 1,810
 21,117
 6,155
Mining 9,742
 7,751
 3,477
Oil and Gas 6,527
 
 (2,712)
Corporate activities (c)
 
 
 (2,252)
Inter-company eliminations 
 (31,274) 
Total $342,138
 $
 $27,663
Three Months Ended September 30, 2019External Operating RevenueInter-company Operating Revenue Total Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities$185,811 $234 $5,339 $$191,384 
Gas Utilities129,385 810 549 130,744 
Power Generation1,703 531 14,415 9,162 25,811 
Mining6,846 228 8,146 332 15,552 
Inter-company eliminations— — (28,449)(9,494)(37,943)
Total$323,745 $1,803 $$$325,548 

Nine Months Ended September 30, 2020External Operating RevenueInter-company Operating Revenue Total Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities$518,641 $2,074 $17,466 $$538,181 
Gas Utilities655,386 7,083 3,153 190 665,812 
Power Generation4,625 1,206 72,609 166 78,606 
Mining20,062 1,477 23,855 463 45,857 
Inter-company eliminations— — (117,083)(819)(117,902)
Total$1,198,714 $11,840 $$$1,210,554 

Nine Months Ended September 30, 2019External Operating RevenueInter-company Operating Revenue Total Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities$521,614 $2,465 $16,586 $$540,665 
Gas Utilities704,188 1,134 1,971 707,293 
Power Generation5,725 1,401 40,924 27,714 75,764 
Mining19,934 785 23,315 992 45,026 
Inter-company eliminations— — (82,796)(28,706)(111,502)
Total$1,251,461 $5,785 $$$1,257,246 


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Table of Contents
Three Months Ended September 30, 2016 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 Net Income (Loss) Available for Common Stock
Segment:      
Electric.
 $171,754
 $2,747
 $24,181
Gas 141,445
 
 (2,939)
Power Generation (b)
 1,906
 21,431
 5,642
Mining 9,042
 7,778
 3,307
Oil and Gas (e)
 9,639
 
 (8,828)
Corporate activities (c)
 
 
 (7,232)
Inter-company eliminations 
 (31,956) 
Total $333,786
 $
 $14,131
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
Adjusted operating income (a):
Electric Utilities$52,083 $50,653 $121,726 $125,219 
Gas Utilities18,147 4,736 139,253 116,607 
Power Generation8,738 11,822 31,489 33,945 
Mining3,505 3,374 9,992 9,351 
Corporate and Other(239)(34)(108)(439)
Operating income82,234 70,551 302,352 284,683 
Interest expense, net(36,041)(33,487)(107,039)(102,469)
Impairment of investment(19,741)(6,859)(19,741)
Other income (expense), net(1,193)580 (703)55 
Income tax (expense)(4,651)(2,508)(25,484)(22,078)
Net income40,349 15,395 162,267 140,450 
Net income attributable to noncontrolling interest(4,066)(3,655)(11,844)(10,319)
Net income available for common stock$36,283 $11,740 $150,423 $130,131 

__________

(a)    Adjusted operating income recognizes inter-segment revenues and costs for Colorado Electric’s PPA with Black Hills Colorado IPP on an accrual basis rather than as a finance lease. This presentation of segment information does not impact consolidated financial results.
       
Nine Months Ended September 30, 2017 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 Net Income (Loss) Available for Common Stock
Segment:      
Electric $518,925
 $9,123
 $68,386
Gas (a)
 674,161
 90
 41,409
Power Generation (b)
 5,382
 62,907
 18,017
Mining 26,500
 22,485
 9,048
Oil and Gas 19,151
 
 (7,609)
Corporate activities (c)(d)
 
 
 (2,870)
Inter-company eliminations 
 (94,605) 
Total $1,244,119
 $
 $126,381
       
Nine Months Ended September 30, 2016 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 Net Income (Loss) Available for Common Stock
Segment:      
Electric $493,845
 $9,413
 $62,625
Gas (a)
 563,879
 
 29,975
Power Generation (b)
 5,304
 63,055
 19,907
Mining 20,498
 23,651
 6,969
Oil and Gas (e)
 25,660
 
 (35,277)
Corporate activities (c)(d)
 
 
 (29,397)
Inter-company eliminations 
 (96,119) 
Total $1,109,186
 $
 $54,802
___________
(a)Gas Utility revenue increased for the nine months ended September 30, 2017 compared to the same period in the prior year primarily due to the addition of the SourceGas utilities on February 12, 2016.
(b)Net income (loss) available for common stock for the three and nine months ended September 30, 2017 and September 30, 2016 was net of net income attributable to noncontrolling interests of $3.9 million and $11 million, and $3.8 million and $6.4 million, respectively.
(c)
Net income (loss) available for common stock for the three and nine months ended September 30, 2017 andSeptember 30, 2016 included incremental, non-recurring acquisition costs, net of tax of $0.2 million and $1.5 million, and $4.0 million and $24 million respectively. The nine months ended September 30, 2017 and the three and nine months ended September 30, 2016 included $0.4 million, $1.7 million and $7.4 million, respectively, of after-tax internal labor costs attributable to the acquisition.
(d)Net income (loss) available for common stock for the nine months ended September 30, 2017 included a $1.4 million tax benefit recognized from carryback claims for specified liability losses involving prior tax years. Net income (loss) available for common stock for the nine months ended September 30, 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. See Note 18.
(e)Net income (loss) available for common stock for the three and nine months ended September 30, 2016 included non-cash after-tax impairments of oil and gas properties of $7.9 million and $33 million, respectively. See Note 17 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.




Segment information and Corporate and Other balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):
Total assets (net of inter-company eliminations) as of:September 30, 2020December 31, 2019
Segment:
Electric Utilities$3,040,064 $2,900,983 
Gas Utilities4,201,325 4,032,339 
Power Generation403,491 417,715 
Mining75,752 77,175 
Corporate and Other108,418 130,245 
Total assets$7,829,050 $7,558,457 


(4)    Selected Balance Sheet Information
Total Assets (net of inter-company eliminations) as of:September 30, 2017 December 31, 2016 September 30, 2016
Segment:     
Electric (a)
$2,911,919
 $2,859,559
 $2,814,408
Gas3,288,104
 3,307,967
 3,170,571
Power Generation (a)
64,357
 73,445
 77,570
Mining66,700
 67,347
 66,804
Oil and Gas (b)
105,963
 96,435
 158,981
Corporate activities114,134
 110,691
 132,652
Total assets$6,551,177
 $6,515,444
 $6,420,986

__________
(a)The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation Station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.
(b)As a result of continued low commodity prices and our decision to divest non-core oil and gas assets, we recorded non-cash impairments of $107 million for the year ended December 31, 2016 and $52 million for the nine months ended September 30, 2016. See Note 17 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Accounts Receivable and Allowance for Credit Losses

(4)    ACCOUNTS RECEIVABLE


Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
September 30, 2020December 31, 2019
Accounts receivable, trade$108,351 $144,747 
Unbilled revenue60,736 113,502 
Less: Allowance for credit losses(8,609)(2,444)
Accounts receivable, net$160,478 $255,805 

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 AccountsUnbilledLess Allowance forAccounts
September 30, 2017Receivable, TradeRevenue Doubtful AccountsReceivable, net
Electric Utilities$42,716
$29,762
$(494)$71,984
Gas Utilities49,842
24,516
(1,190)73,168
Power Generation1,010


1,010
Mining3,534


3,534
Oil and Gas3,590

(83)3,507
Corporate629


629
Total$101,321
$54,278
$(1,767)$153,832

 AccountsUnbilledLess Allowance forAccounts
December 31, 2016Receivable, TradeRevenue Doubtful AccountsReceivable, net
Electric Utilities$41,730
$36,463
$(353)$77,840
Gas Utilities88,168
88,329
(2,026)174,471
Power Generation1,420


1,420
Mining3,352


3,352
Oil and Gas3,991

(13)3,978
Corporate2,228


2,228
Total$140,889
$124,792
$(2,392)$263,289



 AccountsUnbilledLess Allowance forAccounts
September 30, 2016Receivable, TradeRevenue Doubtful AccountsReceivable, net
Electric Utilities$44,747
$30,970
$(580)$75,137
Gas Utilities48,057
23,582
(1,923)69,716
Power Generation1,165


1,165
Mining3,612


3,612
Oil and Gas3,341

(13)3,328
Corporate1,659


1,659
Total$102,581
$54,552
$(2,516)$154,617

(5)    REGULATORY ACCOUNTING

We hadChanges to allowance for credit losses for the following regulatory assetsnine months ended September 30, 2020 and liabilities2019, respectively, were as follows (in thousands) as of:
:
 
Maximum Amortization
(in years)
September 30, 2017December 31, 2016September 30, 2016
Regulatory assets    
Deferred energy and fuel cost adjustments -
current (a)(d)
1$20,559
$17,491
$16,525
Deferred gas cost adjustments (a) (d)
112,833
15,329
12,172
Gas price derivatives (a)
311,297
8,843
14,405
Deferred taxes on AFUDC (b)
4515,645
15,227
14,093
Employee benefit plans (c)
12105,671
108,556
107,578
Environmental (a)
subject to approval1,051
1,108
1,126
Asset retirement obligations (a)
44514
505
507
Loss on reacquired debt (a)
3021,067
22,266
18,077
Renewable energy standard adjustment (b)
51,956
1,605
1,694
Deferred taxes on flow through accounting (c)
3541,900
37,498
33,136
Decommissioning costs (e)
613,989
16,859
17,271
Gas supply contract termination521,402
26,666
28,164
Other regulatory assets (a) (e)
3032,710
24,189
20,053
  $300,594
$296,142
$284,801
     
Regulatory liabilities    
Deferred energy and gas costs (a) (d)
1$3,780
$10,368
$15,033
Employee benefit plan costs and related deferred taxes (c)
1266,620
68,654
65,575
Cost of removal (a)
44125,360
118,410
114,616
Revenue subject to refund11,386
2,485
1,892
Other regulatory liabilities (c)
258,085
6,839
6,305
  $205,231
$206,756
$203,421
Balance at Beginning of YearAdditions Charged to Costs and ExpensesRecoveries and Other AdditionsWrite-offs and Other DeductionsBalance at September 30,
2020$2,444 $8,471 (a)$3,720 $(6,026)$8,609 
2019$3,209 $5,637 $2,742 $(8,429)$3,159 

__________
(a)We are allowed recovery of costs, but we are not allowed a rate of return.
(b)In addition to recovery of costs, we are allowed a rate of return.
(c)In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base.
(d)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)In accordance with a settlement agreement approved by the SDPUC on June 16, 2017, South Dakota Electric’s decommissioning costs of approximately $11 million, vegetation management costs of approximately $14 million, and Winter Storm Atlas costs of approximately $2.0 million are being amortized over 6 years, effective July 1, 2017. Decommissioning costs and Winter Storm Atlas costs were previously amortized over a 10 year period ending September 30, 2024. The vegetation management costs were previously


unamortized. The change in amortization periods(a)    Due to the COVID-19 pandemic, all of our jurisdictions temporarily suspended disconnections for these costs will increase annual amortizationa period of time, which increased our accounts receivable arrears balances. As a result, we increased our allowance for credit losses and bad debt expense for the nine months ended September 30, 2020 by approximately $2.7an incremental $3.7 million.


The ongoing credit evaluation of our customers during the COVID-19 pandemic is further discussed in the Credit Risk section of Note 9.


(6)    MATERIALS, SUPPLIES AND FUELMaterials, Supplies and Fuel


The following amounts by major classification are included in Materials, supplies and fuel inon the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
September 30, 2020December 31, 2019
Materials and supplies$93,069 $82,809 
Fuel - Electric Utilities1,745 2,425 
Natural gas in storage31,544 31,938 
Total materials, supplies and fuel$126,358 $117,172 

Accrued Liabilities

The following amounts by major classification are included in Accrued liabilities on the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
September 30, 2020December 31, 2019
Accrued employee compensation, benefits and withholdings$65,309 $62,837 
Accrued property taxes40,624 44,547 
Customer deposits and prepayments59,510 54,728 
Accrued interest46,044 31,868 
Other (none of which is individually significant)32,523 32,787 
Total accrued liabilities$244,010 $226,767 


21

 September 30, 2017 December 31, 2016 September 30, 2016
Materials and supplies$73,938
 $68,456
 $67,257
Fuel - Electric Utilities2,993
 3,667
 4,282
Natural gas in storage held for distribution49,589
 35,087
 41,936
Total materials, supplies and fuel$126,520
 $107,210
 $113,475

Table of Contents

(5)    Regulatory Matters


We had the following regulatory assets and liabilities (in thousands) as of:
(7)    EARNINGS PER SHARE
September 30, 2020December 31, 2019
Regulatory assets
Deferred energy and fuel cost adjustments (a)
$35,878 $34,088 
Deferred gas cost adjustments (a)
3,670 1,540 
Gas price derivatives (a)
499 3,328 
Deferred taxes on AFUDC (b)
7,683 7,790 
Employee benefit plan costs and related deferred taxes (c)
114,971 115,900 
Environmental (a)
1,417 1,454 
Loss on reacquired debt (a)
23,342 24,777 
Renewable energy standard adjustment (a)
1,622 
Deferred taxes on flow through accounting (c)
44,528 41,220 
Decommissioning costs (b)
9,421 10,670 
Gas supply contract termination (a)
4,027 8,485 
Other regulatory assets (a)
25,800 20,470 
Total regulatory assets271,236 271,344 
Less current regulatory assets(49,493)(43,282)
Regulatory assets, non-current$221,743 $228,062 
Regulatory liabilities
Deferred energy and gas costs (a)
$14,443 $17,278 
Employee benefit plan costs and related deferred taxes (c)
40,719 43,349 
Cost of removal (a)
169,426 166,727 
Excess deferred income taxes (c)
286,055 285,438 
Other regulatory liabilities (c)
16,956 23,860 
Total regulatory liabilities527,599 536,652 
Less current regulatory liabilities(22,282)(33,507)
Regulatory liabilities, non-current$505,317 $503,145 

__________
(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.

22


Table of Contents
Regulatory Activity

Except as discussed below, there have been no other significant changes to our Regulatory Matters from those previously disclosed in Note 13 of the Notes to the Consolidated Financial Statements in our 2019 Annual Report on Form 10-K.

Colorado Gas

Rate Reviews and Jurisdictional Consolidation

On September 11, 2020, Colorado Gas filed a rate review with the CPUC seeking recovery on significant infrastructure investments in its 7,000-mile natural gas pipeline system. The rate review requests $13.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 9.95%. The request seeks to implement new rates in the second quarter of 2021. On September 11, 2020, in accordance with the final order from the earlier rate review discussed below, Colorado Gas also filed a new SSIR proposal that would recover safety-focused investments in its system over five years.

On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting $2.5 million in new revenue to recover investments in safety, reliability and system integrity and approval to consolidate rates, tariffs, and services of its 2 existing gas distribution territories. Colorado Gas also requested a new rider mechanism to recover future safety and integrity investments in its system. On May 19, 2020, the CPUC issued a final order which denied the system integrity recovery mechanism and consolidation of rate territories. In addition, the order resulted in an annual revenue decrease of $0.6 million and a return on equity of 9.2%. New rates were effective July 3, 2020.

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 our deferred income taxes at the 21% federal tax rate as of December 31, 2017. In 2018, the Company successfully delivered the benefits from the TCJA to most of its utility customers.

In 2020, regulatory proceedings resolved the last of the Company’s open dockets seeking approval of its TCJA plans. As a result, the Company relieved certain TCJA-related liabilities, which resulted in an increase to net income for the three and nine months ended September 30, 2020 of $3.5 million and $4.0 million, respectively.

Nebraska Gas

Jurisdictional Consolidation and Rate Review

On June 1, 2020, Nebraska Gas filed a rate review with the NPSC to consolidate rate schedules into a new, single statewide structure and seek recovery on significant infrastructure investments in its 13,000-mile natural gas pipeline system. The rate review requests $17.3 million in new revenue with a capital structure of 50% equity and 50% debt and a return on equity of 10%. Nebraska statute allows for implementation of interim rates 90 days after filing a rate review and Nebraska Gas implemented interim rates effective on September 1, 2020. The request seeks to finalize rates in the first quarter of 2021. Nebraska Gas is also requesting an extension of its SSIR for five years to align the rider recovery mechanism across the consolidated utility.

Black Hills Wyoming and Wyoming Electric

Wygen I FERC Filing

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



23


Table of Contents
(6)    Earnings Per Share

A reconciliation of share amounts used to compute Earnings (loss)earnings per share in the accompanying Condensed Consolidated Statements of Income was as follows (in thousands):
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
Net income available for common stock$36,283 $11,740 $150,423 $130,131 
Weighted average shares - basic62,575 60,976 62,310 60,458 
Dilutive effect of:
Equity compensation55 128 52 120 
Weighted average shares - diluted62,630 61,104 62,362 60,578 
Earnings per share of common stock:
Earnings per share, Basic$0.58 $0.19 $2.41 $2.15 
Earnings per share, Diluted$0.58 $0.19 $2.41 $2.15 
 Three Months Ended September 30, Nine Months Ended September 30,
 20172016 20172016
      
Net income available for common stock$27,663
$14,131
 $126,381
$54,802
      
Weighted average shares - basic53,243
52,184
 53,208
51,583
Dilutive effect of:     
Equity Units (a)
2,015
1,414
 1,872
1,191
Equity compensation174
135
 174
119
Weighted average shares - diluted55,432
53,733
 55,254
52,893

__________
(a)Calculated using the treasury stock method.


The following outstanding securities were excluded infrom the computation of diluted net income (loss)earnings per share ascomputation because of their inclusion would have been anti-dilutive nature (in thousands):
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
Equity compensation22 22 
Restricted stock49 40 
Anti-dilutive shares71 62 



(7)    Notes Payable, Current Maturities and Debt
 Three Months Ended September 30, Nine Months Ended September 30,
 20172016 20172016
      
Equity compensation
2
 
4
Anti-dilutive shares
2
 
4



(8)    NOTES PAYABLE AND LONG-TERM DEBT


We had the following notes payableshort-term debt outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
September 30, 2020December 31, 2019
Balance Outstanding
Letters of Credit (a)
Balance Outstanding
Letters of Credit (a)
Revolving Credit Facility$$24,588 $$30,274 
CP Program84,320 349,500 
Total$84,320 $24,588 $349,500 $30,274 
 September 30, 2017December 31, 2016September 30, 2016
 Balance OutstandingLetters of CreditBalance OutstandingLetters of CreditBalance OutstandingLetters of Credit
Revolving Credit Facility$
$25,391
$96,600
$36,000
$75,000
$30,500
CP Program225,170





Total$225,170
$25,391
$96,600
$36,000
$75,000
$30,500
_______________

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

For the nine months ended September 30, 2020, we utilized a combination of our $750 million Revolving Credit Facility and CP Program

On August 9, 2016, we amended to meet our business needs and restatedsupport our corporate Revolving Credit Facility to increase total commitments to $750 million from $500 million and extend the term through August 9, 2021 with two one-year extension options (subject to consent from lenders). This facility is similar to the former agreement, which includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents, to increase total commitments of the facility up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our most favorable Corporate credit rating from either S&P or Moody’s for our unsecured debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.250%, 1.250%, and 1.250%, respectively, at September 30, 2017. A 0.200% commitment fee is charged on the unused amount of the Revolving Credit Facility.

On December 22, 2016, we implemented a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million. The notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration exemption.capital investment plan. Our net amount borrowed under the CP Programshort-term borrowings (payments) during the nine months ended September 30, 2017 and our notes outstanding as2020 were $(265) million.

24


Table of September 30, 2017 were $225 million. As of September 30, 2017, the weighted average interest rate on CP Program borrowings was 1.46%.Contents

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,agreement, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Our Consolidated Indebtedness to Capitalization Ratio iswas calculated by dividing (i) Consolidated Indebtedness,consolidated indebtedness, which includes letters of credit and certain guarantees issued, and excludes RSNs by (ii) Capital,capital, which includes Consolidated Indebtednessconsolidated indebtedness plus Net Worth,consolidated 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 amount of the RSNs.accelerate all principal and interest outstanding.


Our Revolving Credit Facility and our Term Loansterm loans require compliance with the following financial covenant, at the end of each quarter:
 As of September 30, 2017 Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio61% Less than65%

As of September 30, 2017,which we were in compliance with this covenant.at September 30, 2020:

As of September 30, 2020Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio59.3%Less than65%
Long-Term Debt

Debt Offering

On May 16, 2017,June 17, 2020, we paid down $50completed a public debt offering which consisted of $400 million on our Corporate term loanof 2.50% 10-year senior unsecured notes due August 9, 2019. On July 17, 2017, we paid down an additional $50 million on the same term loan. Short-term borrowings from our CP programJune 15, 2030. The proceeds were used to fundrepay short-term debt and for working capital and general corporate purposes.

South Dakota Electric Series 94A Debt

On March 24, 2020, South Dakota Electric paid off its $2.9 million, Series 94A variable rate notes due June 1, 2024. These notes were tendered by the paymentssole investor on March 17, 2020.


(8)    Equity

February 2020 Equity Issuance

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

SEC.


(9)    EQUITYShelf Registration, DRSPP and ATM Activity

A summary of the changes in equity is as follows:

Nine Months Ended September 30, 2017Total Stockholders’ EquityNoncontrolling InterestTotal Equity
  (in thousands) 
Balance at December 31, 2016$1,614,639
$115,495
$1,730,134
Net income (loss)126,381
10,567
136,948
Other comprehensive income (loss)2,317

2,317
Dividends on common stock(71,334)
(71,334)
Share-based compensation5,853

5,853
Issuance of common stock


Dividend reinvestment and stock purchase plan2,300

2,300
Redeemable noncontrolling interest(886)
(886)
Cumulative effect of ASU 2016-09 implementation3,714

3,714
Other stock transactions(180)
(180)
Distribution to noncontrolling interest
(12,884)(12,884)
Balance at September 30, 2017$1,682,804
$113,178
$1,795,982

Nine Months Ended September 30, 2016Total Stockholders’ EquityNoncontrolling InterestTotal Equity
  (in thousands) 
Balance at December 31, 2015$1,465,867
$
$1,465,867
Net income (loss)54,802
6,402
61,204
Other comprehensive income (loss)(23,896)
(23,896)
Dividends on common stock(65,247)
(65,247)
Share-based compensation3,822

3,822
Issuance of common stock105,238

105,238
Dividend reinvestment and stock purchase plan2,242

2,242
Other stock transactions(24)
(24)
Sale of noncontrolling interest61,838
115,496
177,334
Distribution to noncontrolling interest
(4,516)(4,516)
Balance at September 30, 2016$1,604,642
$117,382
$1,722,024



At-the-Market Equity Offering Program


On August 4, 2017,3, 2020, we filed a shelf registration and DRSPP with the SEC. In conjunction with these shelf filings, we renewed the ATM equity offering program initiated in March 2016 which reset the size of the ATM equity offering program to an aggregate value of up to $300 million.ATM. The renewed ATM program, which allows us to sell shares of our common stock, is the same as the prior year program other than the aggregate value increased from $200$300 million to $300 million. The$400 million and a forward sales option was incorporated. Under the ATM, shares may be offered from time to time pursuant to a sales agreement dated August 4, 2017.3, 2020. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC.

We did not issue any common shares under the ATM during the three and nine months ended September 30, 2017 under the ATM equity offering program.2020. During the three months ended September 30, 2016,2019, we sold 819,442issued a total of 0.4 million shares of common stock under the ATM for $49proceeds of $30 million, net of $0.5$0.3 million in commissions, under the ATM equity offering program.issuance costs. During the nine months ended September 30, 2016,2019, we sold and issued under the ATM equity offering program an aggregatea total of 1,750,0911.3 million shares of common stock with settlement dates through September 30, 2016,under the ATM for $106proceeds of $99 million, net of $1.1$1.0 million in commissions.issuance costs.


Sale of Noncontrolling Interest in Subsidiary

Black Hills Colorado IPP owns a 200 MW, combined-cycle natural gas generating facility located in Pueblo, Colorado. On April 14, 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million 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.

This partial sale was recorded as an equity transaction with no resulting gain or loss on the sale. Further, 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 the noncontrolling interest are due within 30 days following the end of a quarter, but may be withheld as necessary by Black Hills Electric Generation.

Black Hills Colorado IPP has been determined to be a variable interest entity (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:
25

 September 30, 2017 December 31, 2016 September 30, 2016
 (in thousands)
Assets     
Current assets$14,732
 $12,627
 $14,191
Property, plant and equipment of variable interest entities, net$211,380
 $218,798
 $220,818
      
Liabilities     
Current liabilities$3,275
 $4,342
 $3,353

Table of Contents


(9)    Risk Management and Derivatives


(10)    RISK MANAGEMENT ACTIVITIESMarket and Credit Risk Disclosures


Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operationoperations 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 as discussed in our 2016 Annual Report on Form 10-K.


Market Risk


Market risk is the potential loss that mightmay 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 commodityto:

Commodity price risk associated with our natural long position in crude oil andretail natural gas, reserves and production, our retail natural gaswholesale electric power marketing activities and our fuel procurement for certainseveral of our gas-fired generation assets.assets which include market fluctuations due to unpredictable factors such as the COVID-19 pandemic, weather, market speculation, pipeline constraints, and other factors that may impact natural gas and electric energy supply and demand; and


Interest rate risk associated with future debt, including reduced access to liquidity during periods of extreme capital markets volatility, such as the 2008 financial crisis and the COVID-19 pandemic.

Credit Risk


Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.


For production and generation activities, weWe attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental guarantees, prepayments,cash collateral requirements, letters of credit, and other security agreements.


We perform ongoing credit evaluations of our customers and adjust credit limits based on payment history and the customer’scustomers’ current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience, changes in current market conditions, expected losses and any specific customer collection issue that is identified.


We continue to monitor COVID-19 impacts and changes to customer load, consistency in customer payments, requests for deferred or discounted payments, and requests for changes to credit limits to quantify estimated future financial impacts to the allowance for credit losses. During the three and nine months ended September 30, 2020, the potential economic impact of the COVID-19 pandemic was considered in forward looking projections related to write-off and recovery rates, and resulted in increases to the allowance for credit losses and bad debt expense of $1.7 million and $3.7 million, respectively. See Note 4 for further information.

Derivatives and Hedging Activity

Our derivative and hedging activities recordedincluded in the accompanying Condensed Consolidated Balance Sheets, Condensed Consolidated Statements of Income and Condensed Consolidated Statements of Comprehensive Income are detailed below and in Note 1110.

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, 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. We elect hedge accounting on our futures and swaps. These transactions were designated at 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 were recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP. 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 Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Revenue in the accompanying Condensed Consolidated Statements of Income.



The contract or notional amounts and terms of the crude oil futures and natural gas futures and swaps held at our Oil and Gas segment are composed of short positions. We had the following short positions as of:

 September 30, 2017 December 31, 2016 September 30, 2016
 Crude Oil FuturesCrude Oil OptionsNatural Gas Futures and Swaps Crude Oil FuturesCrude Oil OptionsNatural Gas Futures and Swaps Crude Oil FuturesCrude Oil OptionsNatural Gas Futures and Swaps
Notional (a)
54,000
9,000
540,000
 108,000
36,000
2,700,000
 159,000
36,000
1,625,000
Maximum terms in
months (b)
15
3
3
 24
12
12
 27
15
15
__________
(a)Crude oil futures and call options in Bbls, natural gas in MMBtus.
(b)Term reflects the maximum forward period hedged.
Based on September 30, 2017 prices, a $0.1 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. Concurrent with the divestiture of our Oil and Gas Business, our existing oil and gas derivative contracts are expected to be unwound within the next six months. Accordingly, we have de-designated our hedge positions in our Oil and Gas Business effective November 1, 2017. See Note 20.


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), and natural gas sold by our Gas Utilities, 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 Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP.


26


Table of Contents
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 Condensed 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 Condensed Consolidated Statements of Income.


We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risksrisk 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 October 20172020 through December 2020.May 2022. 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 Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Fuel, purchased power and cost of natural gas soldreclassified into earnings in the accompanying Condensed Consolidated Statements of Income.same period that the underlying hedged item is recognized in earnings. Effectiveness of our hedging position is evaluated at inception of the hedge, upon occurrence of a triggering event and as of the end of each quarter.least quarterly.




The contract or notional amounts and terms of the electric and natural gas derivative commodity instruments held at our Utilitiesutilities are composed of both long and short positions. We were in ahad the following net long positionpositions as of:
September 30, 2017 December 31, 2016 September 30, 2016September 30, 2020December 31, 2019
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
UnitsNotional
Amounts
Maximum
Term
(months) (a)
Notional
Amounts
Maximum
Term
(months) (a)
Natural gas futures purchased10,250,000
 39 14,770,000
 48 17,740,000
 51Natural gas futures purchasedMMBtus1,930,000 61,450,000 12
Natural gas options purchased, net7,360,000
 17 3,020,000
 5 6,540,000
 17Natural gas options purchased, netMMBtus8,320,000 63,240,000 3
Natural gas basis swaps purchased9,170,000
 39 12,250,000
 48 13,650,000
 51Natural gas basis swaps purchasedMMBtus1,780,000 61,290,000 12
Natural gas over-the-counter swaps, net (b)
4,600,000
 20 4,622,302
 28 4,749,000
 20
Natural gas over-the-counter swaps, net (b)
MMBtus4,525,100 204,600,000 24
Natural gas physical contracts, net21,071,714
 38 21,504,378
 10 15,666,202
 13
Natural gas physical contracts, net (c)
Natural gas physical contracts, net (c)
MMBtus23,350,287 1313,548,235 12
Electric wholesale contracts (c)
Electric wholesale contracts (c)
MWh55,225 30
__________
(a)    Term reflects the maximum forward period hedged.
(b)    As of September 30, 2020, 1,274,900 MMBtus of natural gas over-the-counter swaps purchases were designated as cash flow hedges.
(c)     Volumes exclude contracts that qualify for the normal purchases and normal sales exception.

We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At September 30, 2020, the Company posted $0.5 million related to such provisions, which is included in Other current assets on the Condensed Consolidated Balance Sheets.

Derivatives by Balance Sheet Classification

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

27


Table of Contents
The following table presents the fair value and balance sheet classification of our derivative instruments (in thousands) as of:
Balance Sheet LocationSeptember 30, 2020December 31, 2019
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivativesDerivative assets, current$435 $
Noncurrent commodity derivativesOther assets, non-current94 
Liability derivative instruments:
Current commodity derivativesDerivative liabilities, current(9)(490)
Noncurrent commodity derivativesOther deferred credits and other liabilities(29)
Total derivatives designated as hedges$520 $(515)
Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivativesDerivative assets, current$1,566 $341 
Noncurrent commodity derivativesOther assets, non-current434 
Liability derivative instruments:
Current commodity derivativesDerivative liabilities, current(1,430)(1,764)
Noncurrent commodity derivativesOther deferred credits and other liabilities(63)
Total derivatives not designated as hedges$570 $(1,484)

Derivatives Designated as Hedges

The impacts of cash flow hedges on our Condensed Consolidated Statements of Comprehensive Income and Condensed Consolidated Statements of Income are presented below for the three and nine months ended September 30, 2020 and 2019. Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.
Three Months Ended
September 30,
Three Months Ended
September 30,
2020201920202019
Derivatives in Cash Flow Hedging RelationshipsAmount of (Gain)/Loss Recognized in OCIIncome Statement LocationAmount of Gain/(Loss) Reclassified from AOCI into Income
(in thousands)(in thousands)
Interest rate swaps$712 $713 Interest expense$(712)$(713)
Commodity derivatives691 (21)Fuel, purchased power and cost of natural gas sold(178)(129)
Total$1,403 $692 $(890)$(842)
(a)Term reflects the maximum forward period hedged.
(b)2,260,000 MMBtus were designated as cash flow hedges for the natural gas fixed for float swaps purchased.

Nine Months Ended September 30,Nine Months Ended September 30,
2020201920202019
Derivatives in Cash Flow Hedging RelationshipsAmount of (Gain)/Loss Recognized in OCIIncome Statement LocationAmount of Gain/(Loss) Reclassified from AOCI into Income
(in thousands)(in thousands)
Interest rate swaps$2,138 $2,139 Interest expense$(2,138)$(2,139)
Commodity derivatives959 (942)Fuel, purchased power and cost of natural gas sold(734)508 
Total$3,097 $1,197 $(2,872)$(1,631)

Based on September 30, 20172020 prices, a $0.3$0.1 million lossgain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

Financing Activities

In October 2015 and January 2016, we entered into forward starting interest rate swaps with a notional value totaling $400 million to reduce the interest rate risk 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 senior note issued on August 19, 2016. Amortization of approximately $2.9 million, which includes the amortization of the $28 million loss currently deferred in AOCI will be recognized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. The ineffective portion of $1.0 million, related to the timing of the debt issuance, was recognized in earnings as a component of interest expense in 2016. The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of:
28


Table of Contents
 September 30, 2017 December 31, 2016 September 30, 2016
 Designated 
Interest Rate
Swaps
 
Designated
Interest Rate
Swap
 (a)
 
Designated
Interest Rate
Swaps
(a)
Notional$
 $50,000
 $75,000
Weighted average fixed interest rate% 4.94% 4.97%
Maximum terms in months0
 1
 4
Derivative liabilities, current$
 $90
 $654
__________
(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.




Cash FlowDerivatives Not Designated as Hedges


The following table summarizes the impacts of cash flow hedgesderivative instruments not designated as hedge instruments on our Condensed Consolidated Statements of Income is presented below for the three and nine months ended September 30, 20172020 and 2016 (in thousands).2019. Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit or loss we realized when the underlying physical and financial transactions were settled.
Three Months Ended September 30,
20202019
Derivatives Not Designated as Hedging InstrumentsIncome Statement LocationAmount of Gain/(Loss) on Derivatives Recognized in Income
Commodity derivatives - ElectricFuel, purchased power and cost of natural gas sold$(1,386)$— 
Commodity derivatives - ElectricOther income (expense), net— 142 
Commodity derivatives - Natural GasFuel, purchased power and cost of natural gas sold1,777 (20)
$391 $122 
Three Months Ended September 30, 2017
Derivatives in Cash Flow Hedging Relationships 
Location of
Reclassifications from AOCI into Income
 
Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
(Settlements)
 
Location of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
 
Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps Interest expense $(713) Interest expense $
Commodity derivatives Revenue 295
 Revenue 
Commodity derivatives Fuel, purchased power and cost of natural gas sold (34) Fuel, purchased power and cost of natural gas sold 
Total   $(452)   $


Nine Months Ended September 30,
20202019
Derivatives Not Designated as Hedging InstrumentsIncome Statement LocationAmount of Gain/(Loss) on Derivatives Recognized in Income
(in thousands)
Commodity derivatives - ElectricFuel, purchased power and cost of natural gas sold$(228)$— 
Commodity derivatives - ElectricOther income (expense), net— 142 
Commodity derivatives - Natural GasFuel, purchased power and cost of natural gas sold2,992 (1,180)
$2,764 $(1,038)
Three Months Ended September 30, 2016
Derivatives in Cash Flow Hedging Relationships 
Location of
Reclassifications from AOCI into Income
 
Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
(Settlements)
 
Location of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
 
Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps Interest expense $(840) Interest expense $
Commodity derivatives Revenue 2,201
 Revenue 
Commodity derivatives Fuel, purchased power and cost of natural gas sold 128
 Fuel, purchased power and cost of natural gas sold 
Total   $1,489
   $

         
Nine Months Ended September 30, 2017
Derivatives in Cash Flow Hedging Relationships 
Location of
Reclassifications from AOCI into Income
 
Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
(Settlements)
 
Location of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
 
Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps Interest expense $(2,228) Interest expense $
Commodity derivatives Revenue 954
 Revenue 
Commodity derivatives Fuel, purchased power and cost of natural gas sold (20) Fuel, purchased power and cost of natural gas sold 
Total   $(1,294)   $
         



         
Nine Months Ended September 30, 2016
Derivatives in Cash Flow Hedging Relationships 
Location of
Reclassifications from AOCI into Income
 
Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
(Settlements)
 
Location of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
 
Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps Interest expense $(2,530) Interest expense $
Commodity derivatives Revenue 9,140
 Revenue 
Commodity derivatives Fuel, purchased power and cost of natural gas sold (23) Fuel, purchased power and cost of natural gas sold 
Total   $6,587
   $

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 three and nine months ended September 30, 2017 and 2016. The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts, if any, are immediately recognized in the Consolidated Statements of Income as incurred.
 Three Months Ended September 30,
 2017 2016
 (In thousands)
Increase (decrease) in fair value:   
Interest rate swaps$
 $(787)
Forward commodity contracts(254) 174
Recognition of (gains) losses in earnings due to settlements:   
Interest rate swaps713
 1,162
Forward commodity contracts(261) (2,329)
Total other comprehensive income (loss) from hedging$198
 $(1,780)

 Nine Months Ended September 30,
 2017 2016
 (In thousands)
Increase (decrease) in fair value:   
Interest rate swaps$
 $(31,452)
Forward commodity contracts1,197
 (92)
Recognition of (gains) losses in earnings due to settlements:   
Interest rate swaps2,228
 2,852
Forward commodity contracts(934) 4,459
Total other comprehensive income (loss) from hedging$2,491
 $(24,233)



Derivatives Not Designated as Hedge Instruments

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income for the three and nine months ended September 30, 2017 and 2016 (in thousands). Note that this presentation does not reflect 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.
  Three Months Ended September 30,
  2017 2016
Derivatives Not Designated as Hedging InstrumentsLocation of Gain/(Loss) on Derivatives Recognized in IncomeAmount of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income
     
Commodity derivativesRevenue$(53) $
Commodity derivativesFuel, purchased power and cost of natural gas sold(322) (342)
  $(375) $(342)

  Nine Months Ended September 30,
  2017 2016
Derivatives Not Designated as Hedging InstrumentsLocation of Gain/(Loss) on Derivatives Recognized in IncomeAmount of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income
     
Commodity derivativesRevenue$90
 $
Commodity derivativesFuel, purchased power and cost of natural gas sold(1,822) 2,492
  $(1,732) $2,492


As discussed above, financial instruments used in our regulated utilities are not designated as cash flow hedges. However, thereThere is no earnings impact for our Gas Utilities because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets.assets or Regulatory liabilities. The net unrealized losses included in our Regulatory assetsasset or Regulatory liability accounts related to the hedgesthese derivatives in our Gas Utilities were $11 million, $8.8$0.5 million and $14$3.3 million atas of September 30, 2017,2020 and December 31, 20162019, respectively. For our Electric Utilities, the unrealized gains and September 30, 2016, respectively.losses arising from these derivatives are recognized in the Condensed Consolidated Statements of Income.







(10)    Fair Value Measurements
(11)    FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

The accounting guidance forWe use the following fair value measurements requires certain disclosures abouthierarchy for determining inputs for our financial instruments. Our assets and liabilities measured at fair value. This guidance establishes a hierarchical framework for disclosing the observabilityfinancial instruments are classified and disclosed in one of the following fair value categories:

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

Level 2 — Pricing inputs utilized in measuringinclude quoted prices for identical or similar assets and liabilities atin 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; and

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

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Table of Contents
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. For additional information, see Notes 1, 9, 10 and 11 to the Consolidated Financial Statements included in our 2016 Annual Report on Form 10-K filed with the SEC.


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 Recurring Fair Value Measurements

Derivatives

Oil and Gas Segment:


The commodity contracts for our Oil and Gas segmentUtilities segments are valued using the market approach and include exchange-traded futures, basis swaps and call options. 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.

Utilities Segments:

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

Corporate Activities:

As of September 30, 2017, we no longer have derivatives within our corporate activities as our interest rate swaps matured in January 2017. The interest rate swaps that were in place prior For additional information, see Note 1 to January 2017 were valued using the market approach. We established fair value by obtaining price quotes directly from the counterparty which were based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty was validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for the interest rate swap derivatives included a CVA component. The CVA considered the fair value of the interest rate swap and the probability of default based on the life of the contract. For the probability of a default component, we utilized observable inputs supporting a Level 2 disclosure by using the credit default spread of the obligor, if available, or a generic credit default spread curve that took into account our credit ratings, and the credit rating of our counterparty.



Recurring Fair Value Measurements

There have been no significant transfers between Level 1 and Level 2 derivative balances. AmountsConsolidated Financial Statements 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 postedour 2019 Annual Report on Form 10-K filed with the same counterparties.SEC.

As of September 30, 2020
Level 1Level 2Level 3Cash Collateral and Counterparty
Netting
Total
(in thousands)
Assets:
Commodity derivatives — Gas Utilities$$6,544 $$(4,015)$2,529 
Commodity derivatives — Electric Utilities
Total$$6,544 $$(4,015)$2,529 
Liabilities:
Commodity derivatives — Gas Utilities$$1,537 $$(326)$1,211 
Commodity derivatives — Electric Utilities228 $228 
Total$$1,765 $$(326)$1,439 
The following tables set forth by level within the fair value hierarchy are gross assets and gross liabilities and related offsetting cash collateral and counterparty netting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments.

As of December 31, 2019
Level 1Level 2Level 3Cash Collateral and Counterparty
Netting
Total
(in thousands)
Assets:
Commodity derivatives — Gas Utilities$$1,433 $$(1,085)$348 
Total$$1,433 $$(1,085)$348 
Liabilities:
Commodity derivatives — Gas Utilities$$5,254 $$(2,909)$2,345 
Total$$5,254 $$(2,909)$2,345 

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Table of Contents
 As of September 30, 2017
 Level 1Level 2Level 3 
Cash Collateral and Counterparty
Netting
Total
 (in thousands)
Assets:      
Commodity derivatives — Oil and Gas$
$769
$
 $(544)$225
Commodity derivatives — Utilities
2,880

 (2,448)432
Total$
$3,649
$
 $(2,992)$657
       
Liabilities:      
Commodity derivatives — Oil and Gas$
$114
$
 $
$114
Commodity derivatives — Utilities
12,647

 (11,125)1,522
Total$
$12,761
$
 $(11,125)$1,636
Pension and Postretirement Plan Assets


 As of December 31, 2016
 Level 1Level 2Level 3 
Cash Collateral and Counterparty
Netting
Total
 (in thousands)
Assets:      
Commodity derivatives — Oil and Gas$
$2,886
$
 $(2,733)$153
Commodity derivatives —Utilities
7,469

 (3,262)4,207
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 September 30, 2016
 Level 1Level 2Level 3 
Cash Collateral and Counterparty
Netting
Total
 (in thousands)
Assets:      
Commodity derivatives — Oil and Gas$
$2,882
$
 $
$2,882
Commodity derivatives — Utilities
5,330

 (3,647)1,683
Total$
$8,212
$
 $(3,647)$4,565
       
Liabilities:      
Commodity derivatives — Oil and Gas$
$705
$
 $
$705
Commodity derivatives — Utilities
16,130

 (15,231)899
Interest rate swaps
654

 
654
Total$
$17,489
$
 $(15,231)$2,258

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 (in thousands):
As of September 30, 2017
 Balance Sheet Location 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:    
Commodity derivativesDerivative assets — current $227
$
Commodity derivativesDerivative assets — non-current 

Commodity derivativesDerivative liabilities — current 
511
Commodity derivativesDerivative liabilities — non-current 
59
Total derivatives designated as hedges  $227
$570
     
Derivatives not designated as hedges:    
Commodity derivativesDerivative assets — current $430
$
Commodity derivativesDerivative assets — non-current 

Commodity derivativesDerivative liabilities — current 
1,051
Commodity derivativesDerivative liabilities — non-current 
15
Total derivatives not designated as hedges  $430
$1,066



As of December 31, 2016
 Balance Sheet Location 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:    
Commodity derivativesDerivative assets — current $1,161
$
Commodity derivativesDerivative assets — non-current 124

Commodity derivativesDerivative liabilities — current 
1,090
Commodity derivativesDerivative liabilities — non-current 
238
Interest rate swapsDerivative liabilities — current 
90
Total derivatives designated as hedges  $1,285
$1,418
     
Derivatives not designated as hedges:    
Commodity derivativesDerivative assets — current $2,977
$
Commodity derivativesDerivative assets — non-current 98

Commodity derivativesDerivative liabilities — current 
1,279
Commodity derivativesDerivative liabilities — non-current 
36
Total derivatives not designated as hedges  $3,075
$1,315

As of September 30, 2016
 Balance Sheet Location 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:    
Commodity derivativesDerivative assets — current $2,919
$
Commodity derivativesDerivative assets — non-current 66

Commodity derivativesDerivative liabilities — current 
479
Commodity derivativesDerivative liabilities — non-current 
256
Interest rate swapsDerivative liabilities — current 
654
Total derivatives designated as hedges  $2,985
$1,389
     
Derivatives not designated as hedges:    
Commodity derivativesDerivative assets — current $1,463
$
Commodity derivativesDerivative assets — non-current 117

Commodity derivativesDerivative liabilities — current 
808
Commodity derivativesDerivative liabilities — non-current 
61
Total derivatives not designated as hedges  $1,580
$869

Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about the fair value measurements of their assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 18 to the Consolidated Financial Statements included in our 20162019 Annual Report on Form 10-K. The Company has concluded that the market volatility associated with COVID-19 does not require interim re-measurement of our pension plan assets or defined benefit obligations. See Note 12 for additional information.




Nonrecurring Fair Value Measurement
(12)    FAIR VALUE OF FINANCIAL INSTRUMENTS

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 15.

Other Fair Value Measures

The estimatedfollowing table presents the carrying amounts and fair values of our financial instruments excluding derivatives which are presented in Note 11, were as followsnot recorded at fair value on the Condensed Consolidated Balance Sheets (in thousands) as of:
 September 30, 2017 December 31, 2016 September 30, 2016
 
Carrying
Amount
Fair Value 
Carrying
Amount
Fair Value 
Carrying
Amount
Fair Value
Cash and cash equivalents (a)
$13,510
$13,510
 $13,580
$13,580
 $31,814
$31,814
Restricted cash and equivalents (a)
$2,683
$2,683
 $2,274
$2,274
 $2,140
$2,140
Notes payable (b)
$225,170
$225,170
 $96,600
$96,600
 $75,000
$75,000
Long-term debt, including current maturities (c) (d)
$3,115,607
$3,362,971
 $3,216,932
$3,351,305
 $3,217,511
$3,525,362
September 30, 2020December 31, 2019
Carrying
Amount
Fair ValueCarrying
Amount
Fair Value
Long-term debt, including current maturities (a)
$3,536,765 $4,177,801 $3,145,839 $3,479,367 
__________
(a)Carrying value approximates fair value due to either the short-term length of maturity or variable interest rates that approximate prevailing market rates, and therefore is classified in Level 1 in the fair value hierarchy.
(b)Notes payable consist of commercial paper borrowings and borrowings on our Revolving Credit Facility. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy.
(c)Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.
(d)
(a)    Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified as Level 2 in the fair value hierarchy. Carrying amount of long-term debt is net of deferred financing costs.




(13)
OTHER COMPREHENSIVE INCOME (LOSS)


31


Table of Contents
(11)    Other Comprehensive Income (Loss)

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 Condensed Consolidated Statements of Income for the period net of tax (in thousands):
Location on the Condensed Consolidated Statements of IncomeAmount Reclassified from AOCILocation on the Condensed Consolidated Statements of IncomeAmount Reclassified from AOCI
Three Months Ended Nine Months EndedThree Months Ended
September 30,
Nine Months Ended September 30,
September 30, 2017September 30, 2016 September 30, 2017September 30, 20162020201920202019
Gains and (losses) on cash flow hedges:    Gains and (losses) on cash flow hedges:
Interest rate swapsInterest expense$(713)$(840) $(2,228)$(2,530)Interest rate swapsInterest expense$(712)$(713)$(2,138)$(2,139)
Commodity contractsRevenue295
2,201
 954
9,140
Commodity contractsFuel, purchased power and cost of natural gas sold(178)(129)(734)508 
Commodity contracts
Fuel, purchased power and cost of natural gas sold

(34)128
 (20)(23)
 (452)1,489
 (1,294)6,587
(890)(842)(2,872)(1,631)
Income taxIncome tax benefit (expense)154
(566) 435
(2,450)Income taxIncome tax benefit (expense)209 170 680 358 
Total reclassification adjustments related to cash flow hedges, net of tax $(298)$923
 $(859)$4,137
Total reclassification adjustments related to cash flow hedges, net of tax$(681)$(672)$(2,192)$(1,273)
    
Amortization of components of defined benefit plans:    Amortization of components of defined benefit plans:
Prior service costOperations and maintenance$49
$55
 $146
$165
Prior service costOperations and maintenance$24 $19 $79 $58 
Actuarial gain (loss)Operations and maintenance(414)(494) (1,242)(1,483)Actuarial gain (loss)Operations and maintenance(597)(83)(1,791)(524)
 (365)(439) (1,096)(1,318)(573)(64)(1,712)(466)
Income taxIncome tax benefit (expense)128
152
 393
460
Income taxIncome tax benefit (expense)143 89 407 184 
Total reclassification adjustments related to defined benefit plans, net of tax $(237)$(287) $(703)$(858)Total reclassification adjustments related to defined benefit plans, net of tax$(430)$25 $(1,305)$(282)
Total reclassifications $(535)$636
 $(1,562)$3,279
Total reclassifications$(1,111)$(647)$(3,497)$(1,555)




Balances by classification included within AOCI, net of tax on the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):
Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
As of December 31, 2019$(15,122)$(456)$(15,077)$(30,655)
Other comprehensive income (loss)
before reclassifications181 55 236 
Amounts reclassified from AOCI1,630 562 1,305 3,497 
As of September 30, 2020$(13,492)$287 $(13,717)$(26,922)
Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
As of December 31, 2018$(17,307)$328 $(9,937)$(26,916)
Other comprehensive income (loss)
before reclassifications(334)(334)
Amounts reclassified from AOCI1,639 (366)282 1,555 
As of September 30, 2019$(15,668)$(372)$(9,655)$(25,695)

32

 Derivatives Designated as Cash Flow Hedges  
 Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
As of December 31, 2016$(18,109)$(233)$(16,541)$(34,883)
Other comprehensive income (loss)    
before reclassifications
755

755
Amounts reclassified from AOCI1,449
(590)703
1,562
Ending Balance September 30, 2017$(16,660)$(68)$(15,838)$(32,566)
     
     
 Derivatives Designated as Cash Flow Hedges  
 Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
Balance as of December 31, 2015$(341)$7,066
$(15,780)$(9,055)
Other comprehensive income (loss)    
before reclassifications(20,200)(417)
(20,617)
Amounts reclassified from AOCI1,644
(5,781)858
(3,279)
Ending Balance September 30, 2016$(18,897)$868
$(14,922)$(32,951)


(14)    SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION


Table of Contents
Nine Months EndedSeptember 30, 2017 September 30, 2016
 (in thousands)
Non-cash investing and financing activities—   
Property, plant and equipment acquired with accrued liabilities$35,065
 $44,140
Increase (decrease) in capitalized assets associated with asset retirement obligations$1,362
 $(2,285)
    
Cash (paid) refunded during the period —   
Interest (net of amounts capitalized)$(101,840) $(82,639)
Income taxes, net$1
 $(1,168)
(12)    Employee Benefit Plans




Change in Accounting Principle - Pension Accounting Asset Method


(15)    EMPLOYEE BENEFIT PLANSEffective January 1, 2020, the Company changed its method of accounting for net periodic benefit cost. Prior to the change, the Company used a calculated value for determining market-related value of plan assets which amortized the effects of gains and losses over a five-year period. Effective with the accounting change, the Company will use a calculated value for the return-seeking assets (equities) in the portfolio and fair value for the liability-hedging assets (fixed income). The Company considers the fair value method for determining market-related value of liability-hedging assets to be a preferable method of accounting because asset-related gains and losses are subject to amortization into pension cost immediately. Additionally, the fair value for liability-hedging assets allows for the impact of gains and losses on this portion of the asset portfolio to be reflected in tandem with changes in the liability which is linked to changes in the discount rate assumption for re-measurement.


We evaluated the effect of this change in accounting method and deemed it immaterial to the historical and current financial statements and therefore did not account for the change retrospectively. Accordingly, the Company calculated the cumulative difference using a calculated value versus fair value to determine market-related value for liability-hedging assets of the portfolio. The cumulative effect of this change, as of January 1, 2020, resulted in a decrease to prior service costs, as recorded in Other income (expense), net, of $0.6 million, an increase in Income tax expense of $0.2 million and an increase to Net income of $0.4 million within the accompanying Condensed Consolidated Statements of Income for the nine months ended September 30, 2020.

Funding Status of Employee Benefit Plans

Based on the fair value of assets and estimated discount rate used to value benefit obligations as of September 30, 2020, we estimate the unfunded status of our employee benefit plans to be approximately $51 million compared to $51 million at December 31, 2019. In 2012, we froze our pension plan and closed it to new participants. Since then, we have implemented various de-risking strategies including lump sum buyouts, the purchase of annuities and the reduction of return-seeking assets over time to a more liability-hedged portfolio.As a result, recent capital markets volatility driven by the COVID-19 pandemic has not materially affected our unfunded status and does not require interim re-measurement of our pension plan assets or defined benefit obligations.

Defined Benefit Pension PlansPlan


The components of net periodic benefit cost for the Defined Benefit Pension PlansPlan were as follows (in thousands):
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
Service cost$1,352 $1,346 $4,058 $4,037 
Interest cost3,356 4,344 10,069 13,031 
Expected return on plan assets(5,647)(6,100)(16,943)(18,300)
Prior service cost (benefit)19 
Net loss (gain)2,093 941 6,279 2,822 
Net periodic benefit cost$1,154 $537 $3,463 $1,609 

33


 Three Months Ended September 30, Nine Months Ended September 30,
 20172016 20172016
Service cost$1,759
$2,078
 $5,276
$6,234
Interest cost3,880
3,936
 11,640
11,808
Expected return on plan assets(6,130)(5,766) (18,388)(17,297)
Prior service cost15
15
 44
45
Net loss (gain)1,002
1,793
 3,005
5,379
Net periodic benefit cost$526
$2,056
 $1,577
$6,169
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Defined Benefit Postretirement Healthcare PlansPlan


The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare PlansPlan were as follows (in thousands):
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
Service cost$514 $454 $1,542 $1,362 
Interest cost412 560 1,237 1,683 
Expected return on plan assets(46)(57)(137)(172)
Prior service cost (benefit)(136)(99)(410)(298)
Net loss (gain)15 
Net periodic benefit cost$749 $858 $2,247 $2,575 
 Three Months Ended September 30, Nine Months Ended September 30,
 20172016 20172016
Service cost$575
$467
 $1,725
$1,401
Interest cost533
485
 1,600
1,455
Expected return on plan assets(79)(70) (237)(210)
Prior service cost (benefit)(109)(107) (327)(321)
Net loss (gain)125
84
 375
252
Net periodic benefit cost$1,045
$859
 $3,136
$2,577


Supplemental Non-qualified Defined Benefit and Defined Contribution Plans


The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands):
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
Service cost$1,035 $429 $1,482 $2,406 
Interest cost274 324 824 972 
Prior service cost (benefit)
Net loss (gain)425 134 1,277 402 
Net periodic benefit cost$1,735 $887 $3,584 $3,781 
 Three Months Ended September 30, Nine Months Ended September 30,
 20172016 20172016
Service cost$612
$623
 $2,048
$1,530
Interest cost319
314
 957
943
Prior service cost
1
 1
2
Net loss (gain)251
207
 751
621
Net periodic benefit cost$1,182
$1,145
 $3,757
$3,096




Contributions


Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. On July 24, 2017, we made contributionsContributions to the Defined Benefit Pension Plan in the amount of approximately $13 million. On September 15, 2017, we made an additional contribution of $15 million to reduce our Pension Benefit Guaranty Corporation premiums and offset the forecasted increase in pension expense due to low bond yields which impact the pension discount rate. Contributions to thePostretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made in 2017the first nine months of 2020 and anticipated contributions for 20172020 and 20182021 are as follows (in thousands):
Contributions MadeAdditional ContributionsContributions
Nine Months Ended September 30, 2020Anticipated for 2020Anticipated for 2021
Defined Benefit Pension Plan$12,700 $$12,700 
Non-pension Defined Benefit Postretirement Healthcare Plans$4,006 $1,335 $5,227 
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans$1,065 $355 $1,964 


34

 Contributions MadeContributions MadeAdditional ContributionsContributions
 Three Months Ended September 30, 2017Nine Months Ended September 30, 2017Anticipated for 2017Anticipated for 2018
Defined Benefit Pension Plan$27,700
$27,700
$
$12,700
Non-pension Defined Benefit Postretirement Healthcare Plans$1,270
$3,810
$1,270
$5,115
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans$395
$1,187
$396
$1,682

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(13)    Commitments and Contingencies

(16)    COMMITMENTS AND CONTINGENCIES

There have been no significant changes to commitments and contingencies from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 20162019 Annual Report on Form 10-K.10-K except for those described below and in Note 5.


Dividend RestrictionsPower Sales Agreement - Colorado Electric


Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends uponOn July 1, 2020, Colorado Electric entered into a default or event of default. As of September 30, 2017, we were in compliancePSA with the debt covenants.City of Colorado Springs to sell up to 60 MW of wind energy purchased from PRPA under a separate 60 MW PPA transacted on June 26, 2019. This PSA with the City of Colorado Springs expires June 30, 2025.


DuePower Purchase Agreement - South Dakota Electric

On September 11, 2020, South Dakota Electric entered into a PPA with Fall River Solar, LLC to our holding company structure, substantiallypurchase up to 80 MW of renewable energy upon construction completion of a new solar facility which is expected by the end of 2022. This agreement will expire 20 years after construction completion.


(14)    Income Taxes

CARES Act

On March 27, 2020, the President signed the CARES Act, which contained, in part, an allowance for deferral of the employer portion of Social Security employment tax liabilities until 2021 and 2022, as well as a COVID-19 employee retention tax credit of up to $5,000 per eligible employee.

Eligible employers are taxpayers experiencing either: (1) a full or partial suspension of business operations stemming from a government COVID-19 related order or (2) a more than 50% drop in gross receipts compared to the corresponding calendar quarter in 2019. This 50% employee retention tax credit applies up to $10,000 in qualified wages paid between March 13, 2020 through December 31, 2020, and is refundable to the extent it exceeds the employer portion of payroll tax liability.

Eligible wages or employer-paid health benefits must be paid for the period of time during which an employee did not provide services. However, employees do not need to stop providing all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cashservices to pay dividendsthe employer for the credit to our stockholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affectpotentially apply.

Additionally, the levels of distributions allowed to be made by our subsidiaries.

Our utilities are generally limited toCARES Act accelerates the amount of dividends allowed toalternative minimum tax (“AMT”) credits that can be paid to us as a utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions and financing agreements. As of September 30, 2017, the restricted net assets at our Electric Utilities and Gas Utilities were approximately $257 million.

(17)    IMPAIRMENT OF ASSETS

Long-lived Assets

Our Oil and Gas segment accounts for oil and gas activities under the full cost method of accounting. Under the full cost method, all productive and non-productive costs related to acquisition, exploration, development, abandonment and reclamation activities are capitalized. These 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. Any costs in excess of the ceiling are written off as a non-cash charge.

There were no impairmentsrefunded for the nine months ended September 30, 2017.2018 and 2019 annual tax returns. In determining the ceiling value2020, we filed for, and received, a refund of our assetsapproximately $2.4 million of AMT credit carryforwards under the full cost accounting rules of the SEC, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. At September 30, 2017, the average NYMEX natural gas price was $3.00 per Mcf, adjusted to $2.66 per Mcf at the wellhead; the average NYMEX crude oil price was $49.81 per barrel, adjusted to $45.58 per barrel at the wellhead. At September 30, 2016, the average NYMEX natural gas price was $2.28 per Mcf, adjusted to $1.03 per Mcf at the wellhead; the average NYMEX crude oil price was $41.68 per barrel, adjusted to $35.88 per barrel at the wellhead. this provision.

During the three and nine months ended September 30, 2016,2020, we recorded pre-tax non-cash impairmentsutilized the payroll tax deferral provision which allowed us to defer payment of approximately $4.0 million and $6.9 million, respectively, of Social Security employment tax liabilities. We are currently reviewing the potential future benefits of the CARES Act related to employee retention tax credits to assess the impact on our financial position, results of operations and cash flows.

Income tax (expense) for the Three Months Ended September 30, 2020 Compared to the Three Months Ended September 30, 2019.

Income tax (expense) for the three months ended September 30, 2020 was $(4.7) million compared to $(2.5) million reported for the same period in 2019. For the three months ended September 30, 2020, the effective tax rate was 10.3% compared to 14.0% for the same period in 2019. The lower effective tax rate is primarily due to increased tax benefits from federal production tax credits associated with new wind assets and reversal of accrued excess deferred income taxes as part of resolving the last of the Company’s open dockets seeking approval of its TCJA plans as discussed in Note 5.

35


Table of Contents
Income tax (expense) for the Nine Months Ended September 30, 2020 Compared to the Nine Months Ended September 30, 2019.

Income tax (expense) for the nine months ended September 30, 2020 was $(25) million compared to $(22) million reported for the same period in 2019. The effective tax rate was 13.6% for both the nine months ended September 30, 2020 and 2019, primarily due to increased tax benefits from forecasted federal production tax credits associated with new wind assets and reversal of accrued excess deferred income taxes as part of resolving the last of the Company’s open dockets seeking approval of its TCJA plans as discussed in Note 5 offset by a prior year discrete tax benefit related to repairs and certain indirect costs.


(15)     Investments

In February 2018, we contributed $28 million of assets in exchange for equity securities in a privately held oil and gas assets included incompany as we divested our Oil and Gas segmentsegment. The carrying value of $12 million and $38 million, respectively.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 secondthird quarter of 2016, certain non-core assets were identified that were not suitable for inclusion in a possible Cost of Service Gas program. We2019, we assessed these assetsour investment for impairment as a result of a deterioration in accordance with ASC 360.earnings performance of the privately held oil and gas company and an adverse change in future natural gas prices. We valuedengaged a third-party valuation consultant to estimate the assets applyingfair value of our investment. The valuation was primarily based on an income approach but also considered a market method approachvaluation approach. The significant inputs used to estimate the fair value were the oil and gas reserve quantities and values utilizing assumptions consistent with similar knownforward market price curves, industry standard reserve adjustment factors and measurable transactions and determineda discount rate of 10%. Based on the results of the valuation, we concluded that the carrying amountvalue of the investment exceeded the fair value. As a result, we recorded a pre-tax impairment loss of depreciable properties$20 million for the three months ended September 30, 2019, which was the difference between the carrying value and the fair value of the investment at June 30, 2016 of $14 million, in addition to the impairments noted above.that time.


(18)    INCOME TAXES

The effective tax rate differs from the federal statutory rate as follows:
 Three Months Ended September 30,
Tax (benefit) expense20172016
Federal statutory rate35.0 %35.0 %
State income tax (net of federal tax effect) (a)
(1.0)(4.0)
Percentage depletion in excess of cost(1.1)(2.3)
Accounting for uncertain tax positions adjustment(0.9)(2.4)
Noncontrolling interest (b)
(3.0)(3.7)
Tax credits (c)
(1.5)
Effective tax rate adjustment (d)
3.9
7.2
Flow-through adjustments 
(1.7)(2.2)
AFUDC equity(0.4)(0.6)
Other tax differences1.1
0.1
 30.4 %27.1 %
__________
(a)In the three months ending September 30, 2017 and 2016, the state income tax benefit is primarily attributable to favorable flow-through adjustments and a pretax net loss at state tax accruing companies. 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.
(b)The adjustment reflects the noncontrolling interest attributable to the sale of 49.9% of the membership interests of Colorado IPP in April 2016.
(c)The increase in tax credits is due to the production tax credits for the Peak View wind farm and marginal gas well tax credit for the oil and gas segment.
(d)Adjustment to reflect the projected annual effective tax rate, pursuant to ASC 740-270.






   
 Nine Months Ended September 30,
Tax (benefit) expense20172016
Federal statutory rate35.0 %35.0 %
State income tax (net of federal tax effect) (a)
0.5
1.7
Percentage depletion in excess of cost (b)
(0.7)(9.7)
Accounting for uncertain tax positions adjustment (c)
(0.2)(7.7)
Noncontrolling interest (d)
(1.9)(2.5)
IRC 172(f) carryback claim (e)
(1.0)
Tax credits (f)
(1.7)
Effective tax rate adjustment (g)
0.3
0.1
Flow-through adjustments (h)
(1.2)(1.9)
Transaction costs
1.4
Other tax differences0.5
(0.9)
 29.6 %15.5 %
__________
(a)The lower state income tax expense in 2017 is lower primarily attributable to favorable flow-through adjustments. 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.
(b)The tax benefit for the nine months ended September 30, 2016 relates to additional percentage depletion deductions that are being claimed with respect to the oil and gas properties involving prior tax years. Such deductions are 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.
(c)The tax benefit for the nine months ended September 30, 2016 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.
(d)Black Hills Colorado IPP went from a single member LLC, wholly-owned by Black Hills Electric Generation, to a partnership as a result of the sale of 49.9% of its membership interest in April 2016. The effective tax rate reflects the income attributable to the noncontrolling interest for which a tax provision is not recorded.
(e)In Q1 2017, the Company filed amended income tax returns for the years 2006 through 2008 to carryback specified liability losses in accordance with IRC172(f). As a result of filing the amended returns, the Company's accrued tax liability interest decreased, certain valuation allowances increased and the previously recorded domestic production activities deduction decreased.
(f)The tax credits for the nine months ended September 30, 2017 are the result of Colorado Electric placing the Peak View Wind Project into service in November 2016.   The Peak View Wind Project began generating production tax credits during the fourth quarter of 2016. 
(g)Adjustment to reflect our 2017 and 2016 annual projected effective tax rate, pursuant to ASC 740-270.
(h)The flow-through adjustments related primarily to an accounting method change for tax purposes that allows 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 for certain indirect costs that continue to be capitalized for book purposes. 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.

InDuring the first quarter of 2016,2020, we reached an agreement in principle with IRS Appeals in regards to the like-kind exchange transaction associated with the gain deferred from the tax treatment related to the 2008 IPP Transaction and the Aquila Transaction.  An agreement in principle 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. We reversed approximately $35 million of the liabilityassessed our investment for unrecognized tax benefits, including interest, during the first quarter of 2016.  The vast majority of such reversal was to restore accumulated deferred income taxes. We reversed accrued after-tax interest expense and tax credits of approximately $5.1 million associated with these liabilities in the first quarter of 2016. The cash taxes dueimpairment as a result of continued adverse changes in future natural gas prices and liquidity concerns at the agreement in principle with IRS Appeals is estimatedprivately held oil and gas company. We performed an internal analysis to be $8.0compute the fair value of our investment, utilizing a consistent methodology as applied during the third quarter of 2019. 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 $6.9 million excluding interest.for the three months ended March 31, 2020, which was the difference between the carrying value and the fair value of the investment at that time.



(19)    ACCRUED LIABILITIES


The following amounts by major classification are included in Accrued liabilities intable presents the accompanying Condensed Consolidated Balance Sheetscarrying value of our investments (in thousands) as of:

September 30, 2020December 31, 2019
Investment in privately held oil and gas company$1,500 $8,359 
Cash surrender value of life insurance contracts13,467 13,056 
Other investments692 514 
Total investments$15,659 $21,929 


(16)    Subsequent Events
 September 30, 2017December 31, 2016September 30, 2016
Accrued employee compensation, benefits and withholdings$54,134
$56,926
$57,203
Accrued property taxes39,564
40,004
37,156
Customer deposits and prepayments45,711
51,628
51,137
Accrued interest and contract adjustment payments30,977
45,503
42,612
CIAC current portion1,575

5,465
Other (none of which is individually significant)41,610
49,973
34,949
Total accrued liabilities$213,571
$244,034
$228,522



(20)    SUBSEQUENT EVENTS

Divestiture of OilWe evaluated all subsequent event activity and Gas Business

On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. Weconcluded that no subsequent events have initiated the process of divesting all Oil and Gas segment assets in order to fully exit the oil and gas business. We anticipate selling or otherwise disposing of all remaining oil and gas properties and assets by year-end 2018 and have retained advisors to accelerate the marketing and sales process. The Company’s Condensed Consolidated Financial Statements and accompanying Notes as of and for the three and nine months ended September 30, 2017 include the Oil and Gas segment’s assets and liabilities, results of operations and cash flows within continuing operations, as we did not meet the criteria for classifying assets as held for sale and presenting the segment’s activities as discontinued operations. Effectiveoccurred that would require recognition in the fourth quartercondensed consolidated financial statements or disclosures, with the exception of 2017, our Oil and Gas segment assets and liabilities will be classified as held for sale, and the Oil and Gas resultsthose items disclosed in Note 5.
36


Table of operations and cash flows will be presented as discontinued operations. When these assets are classified as held for sale, they will be reviewed for impairment which could result in further impairment charges in the future.

 Three Months Ended Nine Months Ended
(in thousands)September 30, 2017September 30, 2016 September 30, 2017September 30, 2016
Revenue$6,527
$9,639
 $19,151
$25,660
Net (loss) available for common stock$(2,712)$(8,828) $(7,609)$(35,277)




ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

ITEM 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.


Executive Summary

We are a customer-focused, growth-oriented utility company operating in the United States. We report our operations and results in the following financialbusiness segments:


Electric Utilities: Our Electric Utilities segment generates, transmits and distributes electricity to approximately 208,500214,000 customers in Colorado, Montana, South Dakota Wyoming, Colorado and Montana.Wyoming. 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.


Gas Utilities: Our Gas Utilities conductsegment conducts natural gas utility operations through our Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming subsidiaries. Our Gas Utilities distributesegment distributes and transporttransports natural gas through our pipeline network to approximately 1,030,8001,066,000 natural gas customers. Additionally, we sell temporarily-available, contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates.affiliates, on an as-available basis.


We also provide non-regulated services through Black Hills Energy Services. Black Hills Energy Services provides natural gas supply to approximately 55,00049,000 retail distribution customers under the Choice Gas Program in Nebraska and Wyoming with unbundled natural gas commodity offeringsWyoming. Additionally, we provide services 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 protection plans under various trade names. Service Guard Comfort Plan 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.also offer HomeServe products.


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


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


OilOur reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and Gas: Our Oil and Gas segment engages in the productionregulation. All of crude oil and natural gas, primarily in the Rocky Mountain region. In the fourth quarter of 2017, we initiated the process of divesting of all remaining Oil and Gas segment assets in order to fully exit the oil and gas business. We anticipate the divestiture process will be complete by year-end 2018. The Company’s Condensed Consolidated Financial Statements and accompanying Notes as of and for the three and nine months ended September 30, 2017 include the Oil and Gas segment’s assets and liabilities, results ofour operations and cash flowsassets are located within continuing operations,the United States. All of our non-utility business segments support our utilities. Certain unallocated corporate expenses that support our operating segments are presented as we did not meet the criteria for classifying assets as held for saleCorporate and presenting the segment’s activities as discontinued operations during the quarter. See Note 20 of the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q for more information.Other.


Certain industries in which we operate are highly seasonal and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market prices.requirements. In particular, the normal peak usage season for our electric utilitiesElectric Utilities is June through August while the normal peak usage season for our gas utilitiesGas Utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and nine months ended September 30, 20172020 and 2016,2019, and our financial condition as of September 30, 2017,2020 and December 31, 2016 and September 30, 2016,2019, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period or for the entire year.


See Forward-Looking Information in the Liquidity and Capital Resources section of this Item 2, beginning on Page 59.

COVID-19 Pandemic

One of the Company’s core values is safety. The COVID-19 pandemic has given us an opportunity to demonstrate our commitment to the health and safety of our customers, employees, business partners and the communities we serve. We have executed our business continuity plans across all of our jurisdictions with the goal of continuing to provide safe and reliable service during the COVID-19 pandemic.
37


See Forward-Looking Information in the Liquidity and Capital Resources section of this Item 2, beginning on Page 73.


The segment information does not include inter-company eliminations. Minor differences in amounts may resultFor the three and nine months ended September 30, 2020, we have experienced limited impacts to our financial results and operational activities due to rounding. All amountsCOVID-19. Year-to-date decreases to gross margins are presented on a pre-tax basis unless otherwise indicated.driven primarily by lower volumes and waived customer late payment fees. Increased operations and maintenance expenses due to sequestration of mission critical and essential employees and increased bad debt expense were partially offset by decreased training, travel, outside services and employee related expenses.




Results of Operations

Executive Summary, Significant EventsDuring the three and Overview

Three Months Endednine months ended September 30, 2017 Compared to Three Months Ended September 30, 2016. Net income available for common stock2020, COVID-19 had a limited impact on revenues and customer loads. Increases in revenues and customer loads for the three months ended September 30, 2017 was $28 million, or $0.50 per share, compared to Net income available for common stock of $14 million, or $0.26 per share, reported for the same period in 2016. The Net income available for common stock for the three months ended September 30, 2017 increased over the same period in the prior year primarily due to a decrease in after-tax impairment charges on our oil and gas properties, lower after-tax corporate expenses, and higher earnings at our Electric Utilities. These are partially offset by lower earnings at our Gas Utilities. The variance to the prior year included the following:

A decrease in non-cash after-tax impairment charges of approximately $7.9 million on our oil and gas properties;
Corporate expenses decreased primarily due to a reduction of $3.8 million of after-tax acquisition and transition costs;
Electric Utilities’ earnings increased $3.1 million driven primarily by returns on prior year generation investments; and
Gas Utilities’ earnings decreased $1.4 million primarily due to the impact of cooler summer temperatures and higher precipitation on summer irrigation load delivered to agricultural customers.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. Net income available for common stock for the nine months ended September 30, 2017 was $126 million, or $2.29 per share, compared to Net income available for common stock of $55 million, or $1.04 per share, reported for the same period in 2016. The Net income available for common stock for the nine months ended September 30, 2017 increased over the same period in the prior year primarily due to higher earnings at our Gas Utilities, Electric Utilities and Mining segments, lower corporate expenses, and a decrease in impairment charges on our oil and gas properties, partially offset by lower earnings at our Power Generation segment and by tax benefits realized during the same period in the prior year. The variance to the prior year included the following:

Earnings at our Oil and Gas segment increased $28 million primarily due to prior year non-cash after-tax impairments on our oil and gas properties of approximately $33 million, partially offset by a prior year $5.8 million tax benefit recognized from additional percentage depletion deductions claimed with respect to our oil and gas properties;
Corporate expenses decreased $27 million2020, when compared to the same period in the prior year, were driven primarily by a $23 million reduction of after-tax acquisitionwarmer and transition costs;
Gas Utilities’ earnings increased $11 million with a full nine months of earnings fromdrier weather across our acquired SourceGas utilities compared to approximately 7.5 monthsservice territories. Declines in the same period of the prior year;
Electric Utilities’ earnings increased $5.8 million driven primarily by returns on prior year generation investments;
Earnings at our Mining segment increased $2.1 million due to an increase in tons sold as a result of an extended outage in the prior year; and
Earnings at our Power Generation segment decreased $1.9 million primarily due to an increase in net income attributable to noncontrolling interests, reflecting a full nine months in 2017 compared to approximately 5.5 months in the same period of the prior year.






The following table summarizes select financial results by operating segmentrevenues and details significant items (in thousands):
 Three Months Ended September 30,Nine Months Ended September 30,
 20172016Variance20172016Variance
Revenue      
Revenue$373,412
$365,742
$7,670
$1,338,724
$1,205,305
$133,419
Inter-company eliminations(31,274)(31,956)682
(94,605)(96,119)1,514
 $342,138
$333,786
$8,352
$1,244,119
$1,109,186
$134,933
       
Net income (loss) available for common stock      
Electric Utilities$27,324
$24,181
$3,143
$68,386
$62,625
$5,761
Gas Utilities(4,329)(2,939)(1,390)41,409
29,975
11,434
Power Generation (a)
6,155
5,642
513
18,017
19,907
(1,890)
Mining3,477
3,307
170
9,048
6,969
2,079
Oil and Gas (b) (c)
(2,712)(8,828)6,116
(7,609)(35,277)27,668
 29,915
21,363
8,552
129,251
84,199
45,052
       
Corporate activities and eliminations (d) (e)
(2,252)(7,232)4,980
(2,870)(29,397)26,527
       
Net income available for common stock$27,663
$14,131
$13,532
$126,381
$54,802
$71,579
__________
(a)Net income available for common stockcustomer loads for the three and nine months ended September 30, 2017 is net of net income attributable to noncontrolling interest of $3.9 million and $11 million, respectively, and $3.8 million and $6.4 million for the three and nine months ended September 30, 2016, respectively.
(b)Net (loss) available for common stock for the three and nine months ended September 30, 2016 included non-cash after-tax impairments of our oil and gas properties of $7.9 million and $33 million, respectively. See Note 17 of the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
(c)Net (loss) available for common stock for the nine months ended September 30, 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 tax years.
(d)Net (loss) available for common stock for the three and nine months ended September 30, 2017 included incremental, non-recurring acquisition costs, after-tax of $0.2 million and $1.5 million, respectively, as compared to $4.0 million and $24 million for the same periods in the prior year. The three and nine months ended September 30, 2016 also included after-tax internal labor costs attributable to the acquisition of $1.7 million and $7.4 million, respectively.
(e)Net (loss) available for common stock for the nine months ended September 30, 2017 included a net tax benefit of approximately $1.4 million from a carryback claim for specified liability losses involving prior tax years. Net (loss) available for common stock for the nine months ended September 30, 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. See Note 18 of the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.



Overview of Business Segments and Corporate Activity

Electric Utilities Segment

Electric Utilities experienced milder summer weather during the three and nine months ended September 30, 20172020, when compared to the threesame period in the prior year, were driven primarily by milder first quarter winter temperatures in our Gas Utilities’ service territories. We continue to closely monitor loads in our states as updated executive orders and nine months ended September 30, 2016. Cooling degree daysrecommendations associated with COVID-19 are provided. We have continued to proactively communicate with various commercial and industrial customers in our service territories to understand their needs and forecast the potential financial implications. We have increased our allowance for credit losses and bad debt expense by $1.7 million and $3.7 million for the three and nine months ended September 30, 2017 were both 15% higher than normal, compared2020, respectively, after considering the potential economic impact of the COVID-19 pandemic in forward looking projections related to 15%write-off and 26% higher than normalrecovery rates. All of our jurisdictions temporarily suspended disconnections for a period of time. State orders lifting those restrictions have been issued in nearly all of our jurisdictions; however, we expect the status of restrictions will continue to fluctuate for the same periodsnext several months. We continue to monitor customer loads, accounts receivable arrears balances, disconnects, cash flows and bad debt expense. We are proactively working with customers to establish payment plans and find available payment assistance resources.

We continue to maintain adequate liquidity to operate our businesses and fund our capital investment program. In February 2020, the Company issued $100 million in 2016. Comparedequity to support its 2020 capital investment program. In June 2020, the same periods inCompany issued $400 million of long-term debt which was used to repay short-term debt and for working capital and general corporate purposes. For the prior year, cooling degree days were 5% and 14% lower, respectively. Heating degree days for the three and nine months ended September 30, 2017 were 8%2020, the Company also utilized a combination of its $750 million Revolving Credit Facility and 11% lower than normal, respectively, comparedCP Program to 34%meet its funding requirements. The Company has no material debt maturities until late 2023 and 13% lower than normalas of September 30, 2020, had $648 million of liquidity which included $7.0 million of cash and $641 million of available capacity on its Revolving Credit Facility. We continue to meet our debt covenant requirements. We also continue to monitor the funding status of our employee benefit plan obligations, which did not materially change during the nine months ended September 30, 2020.

We are monitoring supply chains, including lead times for key materials and supplies, availability of resources, and statuses of large capital projects. To date, there have been limited impacts from COVID-19 on supply chains including the same periodsavailability of supplies, materials and lead times. Capital projects are ongoing without material disruption to schedules. Our third party resources continue to support our business plans without disruption. Contingency plans are ready to be executed if significant disruption to supply chain occurs; however, we currently do not anticipate a significant impact from COVID-19 on our capital investment plan for 2020.

We continue to work closely with local health, public safety and government officials to minimize the spread of COVID-19 and its impact to our employees and the services we provide to our customers. Actions the Company had taken earlier in 2016.the year include implementing protocols for our field operations personnel to continue to safely and effectively interact with our customers, asking employees to work from home, requiring employees to complete daily health assessments, covering COVID-19 testing at 100% for our active employee medical plans, limiting travel to only mission-critical purposes and sequestering essential employees.


During the third quarter of 2020, we suspended sequestration of essential employees but continue to monitor the impacts of COVID-19 in our service territories to ensure we provide essential services to our customers. Additionally, we implemented our Ready2Return program, which includes a phased return of our employees to our work facilities while keeping our workforce healthy, safe and informed. Our Ready2Return program also focuses on enhancing our facility readiness to improve ventilation, ensure social distancing and establish cleaning services to reduce the spread of infection.

We provide periodic status updates and maintain ongoing dialogue with the regulatory commissions in our jurisdictions.  We are working with regulators in each of our service territories to preserve our right for deferred regulatory treatment for certain COVID-19 related costs and to seek recovery of these costs at a later date.

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During these uncertain times, we remain highly focused on the safety and health of our customers, employees, business partners and communities. We continue to monitor load, customers’ ability to pay, the potential for supply chain disruption that may impact our capital and maintenance project plans, the availability of resources to execute our plans and the capital markets to ensure we have the liquidity necessary to support our financial needs.

As we look forward to the fourth quarter of 2020 and beyond, we anticipate that our operating results could be further affected by COVID-19, as discussed in detail in our Risk Factors.

2020 Business Segment Highlights and Corporate Activity

Electric Utilities

South Dakota Electric and Wyoming Electric continued construction of the $79 million, Corriedale project. The wind project will be jointly owned by the two electric utilities to deliver renewable energy for large commercial, industrial and governmental agency customers. The project is expected to be fully in service in the fourth quarter of 2020.

On October 15, 2020, the FERC approved a settlement agreement that represents a resolution of all issues in the joint application filed by Wyoming Electric and Black Hills Wyoming on August 2, 2019 for approval of a new 60 MW PPA. Under terms of the settlement, Wyoming Electric will continue to receive 60 MW of capacity and energy from the Wygen I power plant. The new agreement will commence on January 17, 2017,1, 2022, replace the existing PPA and continue for 11 years.

On September 23, 2020, Colorado Electric received approval from the CPUC on a settlement agreement for its electric resource plan which providesrequest for the additionapproval of 60 megawattsits preferred solar bid in support of its Renewable Advantage program. The program plans to add up to 200 MW of renewable energy to be in service by 2019. The resource plan was filed June 3, 2016, to meet requirements under the Colorado Renewable Energy Standard. In the second quarter of 2017, Colorado Electric issued a request for proposals to construct new generation and plans to present the results to the CPUC by year-end.

On January 9, 2017, we filed an application with the CPUC for rehearing, reargument or reconsideration of the Commission’s December 19, 2016 decision to increase annual revenue by $1.2 million. This application was denied by the CPUC on June 9, 2017. We subsequently filed an appealend of this decision with Denver County District Court on2023.

On July 10, 2017. The briefing schedule runs through November 2017. The timing of a ruling is uncertain.

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

On July 19, 2017,2020, Wyoming Electric set a new summerall-time peak load of 271 MW, surpassing the previous peak of 249 MW, exceeding the previous summer peak of 236265 MW set in July 2016.2019.


On May 5, 2020, citizens in Pueblo, Colorado voted overwhelmingly to retain Colorado Electric as its electric utility provider by 75.6% of votes cast. The current franchise agreement continues through 2030.

Gas Utilities Segment


On October 3, 2017, RMNGSeptember 11, 2020, Colorado Gas filed a rate review applicationwith the CPUC seeking recovery on significant infrastructure investments in its 7,000-mile natural gas pipeline system. The rate review requests $13.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 9.95%. The request seeks to implement new rates in the second quarter of 2021. On September 11, 2020, in accordance with the final order from the earlier rate review discussed below, Colorado Gas also filed a new SSIR proposal that would recover safety-focused investments in its system over five years.

On June 1, 2020, Nebraska Gas filed a rate review with the NPSC to consolidate rate schedules into a new, single statewide structure and seek recovery on significant infrastructure investments in its 13,000-mile natural gas pipeline system. The rate review requests $17.3 million in new revenue with a capital structure of 50% equity and 50% debt and a return on equity of 10%. Nebraska statute allows for implementation of interim rates 90 days after filing a rate review and Nebraska Gas implemented interim rates effective on September 1, 2020. The request seeks to finalize rates in the first quarter of 2021. Nebraska Gas is also requesting an extension of its SSIR for five years to align the rider recovery mechanisms across the consolidated utility.

On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting $2.5 million in new revenue to recover investments in safety, reliability and system integrity and approval to consolidate rates, tariffs, and services of its two existing gas distribution territories. Colorado Gas also requested a new rider mechanism to recover future safety and integrity investments in its system. On May 19, 2020, the CPUC issued a final order which denied the new system integrity recovery mechanism and consolidation of rate territories. In addition, the order resulted in an annual increase in revenue decrease of $2.2$0.6 million and an extensiona return on equity of SSIR9.2%. New rates were effective July 3, 2020.

39



Wyoming Gas’s new single statewide rate structure was effective March 1, 2020. On December 11, 2019, Wyoming Gas received approval from the WPSC to recover costs from 2018 through 2022. Theconsolidate the rates, tariffs and services of its four existing gas distribution territories. New rates are expected to generate $13 million in new annual increase isrevenue based on a return on equity of 12.25%9.40% and a capital structure of 53.37% debt50.23% equity and 46.63% equity. This rate review was driven by49.77% debt. The approval also allows for a rider to recover integrity investments for system safety and reliability.

Power Generation

On October 15, 2020, the impending expiration of the SSIR on May 31, 2018; this application requestsFERC approved a continuation of the SSIR through 2022.

Gas Utilities experienced milder weather during the non-peak three months ended September 30, 2017 compared to the three months ended September 30, 2016. Heating degree days for the three months ended September 30, 2017 were 22% lower than normal compared to 2% lower than normal for the same period in 2016. For the nine months ended September 30, 2017, Gas Utilities experienced slightly colder weather compared to the nine months ended September 30, 2016. Heating degree days were 12% lower than normal for the nine months ended September 30, 2017 compared to 20% lower than normal for the same period in 2016.

The Gas Utilities also experienced cooler summer temperatures and higher precipitation levels during the three months ended September 30, 2017 than the same period in 2016, which reduced the irrigation load delivered to agricultural customers, primarily in our Nebraska service territory.

Oil and Gas Segment

On November 1, 2017, our board of directors authorized the salesettlement agreement that represents a resolution of all remaining oil and gas assets and the exit of the business. The segment will be reported as discontinued operations beginning with fourth quarter results. The company has retained advisors to support its ongoing property sales efforts and plans to divest all remaining properties by year-end 2018.

We recently signed agreements to sell our San Juan Basin assets in New Mexico and certain Powder River Basin assets in Wyoming for a combined $28 million. The San Juan Basin transaction is subject to final approval from the


U.S. Bureau of Indian Affairs and U.S. Bureau of Land Management. Both transactions are expected to close by year-end.

Oil and Gas production volumes decreased 9% and 17% for the three and nine months ended September 30, 2017 compared to the same periods in 2016, respectively. The decrease in production was due to the 2016 sales of non-core properties, and limiting natural gas production to meet minimum daily quantity contractual gas processing commitmentsissues in the Piceance. Crude oil production also decreased due to non-core property salesjoint application filed by Black Hills Wyoming and Wyoming Electric on August 2, 2019 for approval of a new 60 MW PPA. See additional information in the fourth quarter of 2016. The average hedged price received for natural gas decreased 15% for the three months ended September 30, 2017 and increased 21% for the nine months ended September 30, 2017 compared to the same periods in 2016, respectively. The average hedged price received for oil decreased 11% and 14% for the three and nine months ended September 30, 2017 compared to the same periods in 2016, respectively.
Electric Utilities Segment highlights above.


Corporate Activitiesand Other


On August 4, 2017,20, 2020, Fitch affirmed South Dakota Electric’s credit rating at A.

On August 20, 2020, Fitch affirmed our BBB+ rating and maintained a stable outlook.

On August 3, 2020, we filed a shelf registration and DRSPP with the SEC. In conjunction with these shelf filings, we renewed the ATM equity offering program initiated in March 2016 which reset the size of the ATM equity offering program to an aggregate value of up to $300 million.ATM. The renewed ATM program, which allows us to sell shares of our common stock, is the same as the prior year program with the exception thatother than the aggregate value increased $100 million.from $300 million to $400 million and a forward sales option was incorporated.


We utilized favorableOn June 17, 2020, we completed a public debt offering of $400 million principal amount in senior unsecured notes. The debt offering consisted of $400 million of 2.50%, 10-year senior notes due June 15, 2030. The proceeds were used to repay short-term borrowings from our CP program to pay down $100 million on a Corporate term loan due in 2019 with principal payments of $50 million paid in Maydebt and an additional $50 million paid in July.for working capital and general corporate purposes.


On July 21, 2017,April 16, 2020, S&P affirmed Black Hills’South Dakota Electric’s credit rating at BBBA.

On April 10, 2020, S&P affirmed our BBB+ rating and maintained a Stablestable outlook.


On October 4, 2017, Fitch affirmedFebruary 27, 2020, we issued 1.2 million shares of common stock at a price of $81.77 per share for net proceeds of $99 million.


40


Results of Operations

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

Consolidated Summary and Overview
(in thousands, except per share amounts)Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
Revenue
Revenue$386,525 $363,491 $1,328,456 $1,368,748 
Inter-company eliminations(39,935)(37,943)(117,902)(111,502)
$346,590 $325,548 $1,210,554 $1,257,246 
Adjusted operating income (a)
Electric Utilities$52,083 $50,653 $121,726 $125,219 
Gas Utilities18,147 4,736 139,253 116,607 
Power Generation8,738 11,822 31,489 33,945 
Mining3,505 3,374 9,992 9,351 
Corporate and Other(239)(34)(108)(439)
Operating income82,234 70,551 302,352 284,683 
Interest expense, net(36,041)(33,487)(107,039)(102,469)
Impairment of investment— (19,741)(6,859)(19,741)
Other income (expense), net(1,193)580 (703)55 
Income tax (expense)(4,651)(2,508)(25,484)(22,078)
Net income40,349 15,395 162,267 140,450 
Net income attributable to noncontrolling interest(4,066)(3,655)(11,844)(10,319)
Net income available for common stock$36,283 $11,740 $150,423 $130,131 
Earnings per share, Basic$0.58 $0.19 $2.41 $2.15 
Earnings per share, Diluted$0.58 $0.19 $2.41 $2.15 
__________
(a)    Adjusted operating income recognizes inter-segment revenues and costs for Colorado Electric’s PPA with Black Hills’ credit rating at BBB+ rating and changed its outlook from NegativeHills Colorado IPP on an accrual basis rather than as a finance lease. This presentation of segment information does not impact consolidated financial results.

Three Months Ended September 30, 2020 Compared to Stable, citing successful integration of SourceGas, a low business risk profile focused on utility operations and expected improvement of credit metrics.Three Months Ended September 30, 2019:


Tax Matters - Potential Corporate Tax Reform

President Trump and Congressional Republicans have stated that one of their top priorities is enactment of comprehensive tax reform.  On November 2, 2017, the House Ways and Means Committee released its tax reform bill. Significant uncertainty exists asThe variance to the ultimate legislation that will be enacted into law.  We are evaluatingprior year included the proposed legislation; any impactfollowing:

COVID-19 related impacts to consolidated results included $1.0 million of lower gross margin driven primarily by waived customer late payment fees, $1.7 million of additional bad debt expense and $0.5 million of costs due to sequestration of mission-critical and essential employees which were partially offset by $1.1 million of lower travel, training, and employee related expenses;
Electric Utilities’ adjusted operating income increased $1.4 million primarily due to rider revenues and benefits from the release of TCJA revenue reserves partially offset by higher operating expenses and mark-to-market losses on wholesale energy contracts;
Gas Utilities’ adjusted operating income increased $13 million primarily due to drier summer weather favorably impacting our futureNebraska service territory irrigation loads, new customer rates in Wyoming and Nebraska and mark-to-market gains on non-utility natural gas commodity contracts partially offset by higher operating expenses;
Power Generation adjusted operating income decreased $3.1 million primarily due to higher operating expenses driven by the early retirement of certain assets;
Interest expense increased $2.6 million primarily due to higher debt balances partially offset by lower rates;
41


A prior year $20 million pre-tax non-cash impairment of our investment in equity securities of a privately held oil and gas company;
Other expense increased $1.8 million primarily due to increased costs for our non-qualified benefit plan driven by market performance on plan assets and increased non-service pension costs resulting from a change in accounting principle for our defined benefit pension plan effective January 1, 2020; and
Income tax expense increased $2.1 million primarily due to higher pre-tax earnings partially offset by a lower effective tax rate.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019:

The variance to the prior year included the following:

COVID-19 related impacts to consolidated results included $3.4 million of operations, financial positionlower gross margin driven primarily by lower volumes and cash flows aswaived customer late payment fees, $2.6 million of costs due to sequestration of mission-critical and essential employees and $3.7 million of additional bad debt expense which were partially offset by $4.6 million of lower travel, training, outside services and employee related expenses;
Electric Utilities’ adjusted operating income decreased $3.5 million primarily due to higher operating expenses and COVID-19 impacts partially offset by benefits from the release of TCJA revenue reserves, rider revenues and favorable weather;
Gas Utilities’ adjusted operating income increased $23 million primarily due to new customer rates in Wyoming, mark-to-market gains on non-utility natural gas commodity contracts, prior year amortization of excess deferred income taxes and customer growth partially offset by higher operating expenses and COVID-19 impacts;
Power Generation adjusted operating income decreased $2.5 million primarily due to higher operating expenses driven by the early retirement of certain assets;
Interest expense increased $4.6 million primarily due to higher debt balances partially offset by lower rates;
A prior year $20 million pre-tax non-cash impairment of our investment in equity securities of a result ofprivately held oil and gas company compared to a current year $6.9 million impairment on the potential changes cannot yet be determinedsame investment; and such changes could be material.

Income tax expense increased $3.4 million primarily due to higher pre-tax earnings with similar effective tax rates.

Operating Results by Segment


A discussion of operating results from our segments and Corporate activities follows.follows in the sections below. Revenues for operating segments in the following sections are presented in total and by retail class. For disaggregation of revenue by contract type and operating segment, see Note 2 of the Notes to Condensed Consolidated Financial Statements for more information.



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 revenue less cost of natural gas sold. Our gross margin is impacted by the fluctuations in power purchases 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.measures. Furthermore, this measure is not intended to replace operating income, as determined in accordance with GAAP, as an indicator of operating performance.





42


Electric Utilities
Three Months Ended September 30,Nine Months Ended September 30,
20202019Variance20202019Variance
(in thousands)
Revenue$200,842 $191,384 $9,458 $538,181 $540,665 $(2,484)
Total fuel and purchased power77,885 71,593 6,292 201,398 207,004 (5,606)
Gross margin (non-GAAP)122,957 119,791 3,166 336,783 333,661 3,122 
Operations and maintenance47,426 47,172 254 144,956 143,049 1,907 
Depreciation and amortization23,448 21,966 1,482 70,101 65,393 4,708 
Total operating expenses70,874 69,138 1,736 215,057 208,442 6,615 
Adjusted operating income$52,083 $50,653 $1,430 $121,726 $125,219 $(3,493)
 Three Months Ended September 30,Nine Months Ended September 30,
 20172016Variance20172016Variance
 (in thousands)
Revenue$183,571
$174,501
$9,070
$528,048
$503,258
$24,790
       
Total fuel and purchased power68,733
66,953
1,780
199,398
194,477
4,921
       
Gross margin114,838
107,548
7,290
328,650
308,781
19,869
       
Operations and maintenance40,204
38,108
2,096
125,302
116,312
8,990
Depreciation and amortization23,446
21,063
2,383
69,427
62,794
6,633
Total operating expenses63,650
59,171
4,479
194,729
179,106
15,623
       
Operating income51,188
48,377
2,811
133,921
129,675
4,246
       
Interest expense, net(12,744)(12,046)(698)(39,049)(36,676)(2,373)
Other income (expense), net649
1,335
(686)1,579
2,828
(1,249)
Income tax benefit (expense)(11,769)(13,485)1,716
(28,065)(33,202)5,137
Net income$27,324
$24,181
$3,143
$68,386
$62,625
$5,761


Results of Operations for the Electric Utilities for the Three Months Ended September 30, 20172020 Compared to the Three Months Ended September 30, 2016: Net income available for common stock for the Electric Utilities was $27 million2019:

Gross margin for the three months ended September 30, 2017, compared to Net income available for common stock of $24 million for the three months ended September 30, 2016,2020 increased as a result of:of the following:

(in millions)
Release of TCJA revenue reserves$1.5 
Rider recovery1.3 
Off-system power marketing0.9 
Weather0.2 
Mark-to-market on wholesale energy contracts(1.4)
COVID-19 impacts(0.2)
Other0.9 
Total increase in Gross margin (non-GAAP)$3.2 
Gross margin increased due primarily to a $3.3 million increase in rider revenues primarily related to transmission investment recovery and a $3.0 million return on investment from the Peak View Wind Project.

Operations and maintenance expense increased primarily due to $1.4COVID-19 related expenses of $0.5 million for the sequestration of essential employees and $0.3 million of higher generation outage and major maintenance expenses for turbine, generator, pulverizer and boiler work as compared to the prior year. Employee costs increased $0.9 million as a result of prior year integration activities and transition expenses charged to the Corporate segment. In addition, operating expenses increasedadditional bad debt expense which were partially offset by $0.4 million from the addition of the Peak View Wind Projectlower travel, training and the 40-megawatt gas turbine at the Pueblo Airport Generating Station.employee related expenses.


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

Interest expense, net increased primarily due to higher intercompany debt resulting from additional investments as compared to the prior year.

Other income (expense), net decreased due to reduced AFUDC with lower current year capital spend.expenditures.


Income tax benefit (expense): The effective tax rate was lower than the prior year due primarily to wind production tax credits related to the Peak View Wind Project.
43







Results of Operations for the Electric Utilities for the Nine Months Ended September 30, 20172020 Compared to the Nine Months Ended September 30, 2016: Net income available for common stock for the Electric Utilities was $68 million2019:

Gross margin for the nine months ended September 30, 2017, compared to Net income available for common stock of $63 million for the nine months ended September 30, 2016,2020 increased as a result of:of the following:

(in millions)
Release of TCJA revenue reserves$2.7 
Rider recovery and true-up (a)
1.0 
Weather0.9 
COVID-19 impacts (b)
(1.7)
Other0.2 
Total increase in Gross margin (non-GAAP)$3.1 
____________________
(a)    Gross margin increased over the prior year reflecting a $7.5due to $2.6 million return on investment from the Peak View Wind Project, a $6.4 million increase inof rider revenues, primarily relatedwhich was partially offset by a $1.6 million rider true-up.
(b)    The impacts to transmission investment recovery and a $3.3 million increase in commercial and industrial marginsElectric Utilities’ gross margin from COVID-19 were primarily driven by increased demand largely associated with data centers in Cheyenne, Wyoming. A variety of smaller items contribute to the remainder of the increase.reduced commercial volumes and waived customer late payment fees partially offset by higher residential usage.


Operations and maintenance expense increased primarily due to $4.2$1.4 million of higher employee costs as a result of prior year integration activities and transition expenses chargedrelated to the Corporate segment, $2.0 million increaseefforts to retain our franchise privileges in generation outagePueblo, Colorado. COVID-19 impacts to operations and major maintenance expenses with increased scope of work, $1.9expense included $2.2 million of higher property taxes with an increased asset base,expenses related to the sequestration of essential employees and $1.3$0.9 million of higher operating expenses from the Peak View Wind Projectadditional bad debt expense which were partially offset by $2.4 million of lower travel, training, outside services and 40-megawatt gas turbine at the Pueblo Airport Generating Station.employee related expenses.


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

Interest expense, net increased primarily due to higher intercompany debt resulting from additional investments as compared to prior year.

Other income (expense), net decreased due to reduced AFUDC with lower current year capital spend.expenditures.


Income tax benefit (expense): The effective tax rate was lower than the prior year due primarily to wind production tax credits related to the Peak View Wind Project.

Operating Statistics

Electric RevenueQuantities Sold
(in thousands)(MWh)
Three Months Ended
September 30,
Nine Months Ended
September 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
20202019202020192020201920202019
Residential$62,395 $58,919 $167,048 $162,257 405,989 384,735 1,113,821 1,075,394 
Commercial64,756 65,732 178,979 186,434 538,299 560,547 1,492,239 1,556,449 
Industrial35,660 33,937 99,725 98,074 462,545 462,809 1,382,710 1,335,260 
Municipal4,834 4,792 12,732 13,184 46,256 46,106 121,027 121,025 
Subtotal Retail Revenue - Electric167,645 163,380 458,484 459,949 1,453,089 1,454,197 4,109,797 4,088,128 
Contract Wholesale (a)
5,924 8,211 14,947 23,335 129,960 229,369 348,991 646,611 
Off-system/Power Marketing Wholesale9,535 6,452 17,939 16,592 167,494 160,357 469,590 436,298 
Other17,738 13,341 46,811 40,789 — — — — 
Total Revenue and Energy Sold200,842 191,384 538,181 540,665 1,750,543 1,843,923 4,928,378 5,171,037 
Other Uses, Losses or Generation, net (b)
— — — — 118,410 112,172 294,466 299,038 
Total Revenue and Energy200,842 191,384 538,181 540,665 1,868,953 1,956,095 5,222,844 5,470,075 
Less cost of fuel and purchased power77,885 71,593 201,398 207,004 
Gross Margin (non-GAAP)$122,957 $119,791 $336,783 $333,661 



44


 Three Months Ended September 30, Nine Months Ended September 30,
Revenue - Electric (in thousands)2017 2016 2017 2016
Residential:       
South Dakota Electric$18,020
 $17,501
 $53,724
 $53,057
Wyoming Electric10,083
 9,585
 29,571
 29,283
Colorado Electric27,763
 27,460
 74,722
 73,721
Total Residential55,866
 54,546
 158,017
 156,061
        
Commercial:       
South Dakota Electric25,459
 25,714
 72,608
 73,026
Wyoming Electric16,389
 16,306
 48,565
 47,818
Colorado Electric26,196
 25,907
 74,322
 72,782
Total Commercial68,044
 67,927
 195,495
 193,626
        
Industrial:       
South Dakota Electric8,149
 8,275
 24,774
 24,540
Wyoming Electric12,104
 11,904
 37,737
 32,353
Colorado Electric10,311
 9,870
 29,072
 28,917
Total Industrial30,564
 30,049
 91,583
 85,810
        
Municipal:       
South Dakota Electric1,071
 1,053
 2,849
 2,844
Wyoming Electric542
 543
 1,588
 1,606
Colorado Electric3,345
 3,299
 9,497
 8,879
Total Municipal4,958
 4,895
 13,934
 13,329
        
Total Retail Revenue - Electric159,432
 157,417
 459,029
 448,826
        
Contract Wholesale:       
Total Contract Wholesale - South Dakota Electric (a)
8,048
 4,596
 22,593
 12,717
        
Off-system Wholesale:       
South Dakota Electric4,787
 3,984
 11,044
 11,304
Wyoming Electric758
 924
 3,505
 3,777
Colorado Electric387
 522
 561
 1,229
Total Off-system Wholesale5,932
 5,430
 15,110
 16,310
        
Other Revenue:       
South Dakota Electric8,404
 5,605
 26,193
 19,901
Wyoming Electric794
 325
 2,333
 1,435
Colorado Electric961
 1,128
 2,790
 4,069
Total Other Revenue10,159
 7,058
 31,316
 25,405
        
Total Revenue - Electric$183,571
 $174,501
 $528,048
 $503,258
Electric Revenue
(in thousands)
Gross Margin (non-GAAP) (in thousands)
Quantities Sold (MWh) (b)
Three Months Ended September 30,202020192020201920202019
Colorado Electric$74,742 $70,771 $42,236 $41,916 666,916 634,098 
South Dakota Electric (a)
78,861 77,022 58,062 55,217 699,150 835,725 
Wyoming Electric47,239 43,591 22,659 22,658 502,887 486,272 
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold$200,842 $191,384 $122,957 $119,791 1,868,953 1,956,095 
__________
(a)Increase for the three and nine months ended September 30, 2017 was primarily due to a new 50 MW power sales agreement effective January 1, 2017.

Electric Revenue
(in thousands)
Gross Margin (non-GAAP) (in thousands)
Quantities Sold (MWh) (b)
Nine Months Ended September 30,202020192020201920202019
Colorado Electric$191,197 $186,030 $106,961 $104,411 1,765,501 1,611,126 
South Dakota Electric (a)
213,059 225,309 163,659 162,390 1,954,902 2,438,366 
Wyoming Electric133,925 129,326 66,163 66,860 1,502,441 1,420,583 
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold$538,181 $540,665 $336,783 $333,661 5,222,844 5,470,075 


 Three Months Ended
September 30,
 Nine Months Ended
September 30,
Quantities Generated and Purchased (in MWh)2017 2016 2017 2016
Generated —       
Coal-fired:       
South Dakota Electric423,766
 401,231
 1,101,291
 1,054,264
Wyoming Electric (d)
201,824
 188,739
 562,644
 548,513
Total Coal-fired625,590
 589,970
 1,663,935
 1,602,777
        
Natural Gas and Oil:       
South Dakota Electric (a)
54,466
 41,654
 75,840
 96,649
Wyoming Electric (a)
25,567
 23,874
 39,136
 58,944
Colorado Electric76,432
 64,507
 134,089
 128,397
Total Natural Gas and Oil156,465
 130,035
 249,065
 283,990
        
Wind:       
Colorado Electric (b)
38,773
 10,676
 167,429
 34,325
Total Wind38,773
 10,676
 167,429
 34,325
        
Total Generated:       
South Dakota Electric478,232
 442,885
 1,177,131
 1,150,913
Wyoming Electric (a)
227,391
 212,613
 601,780
 607,457
Colorado Electric (b)
115,205
 75,183
 301,518
 162,722
Total Generated820,828
 730,681
 2,080,429
 1,921,092
        
Purchased —       
South Dakota Electric (c)
357,053
 247,097
 1,222,864
 902,166
Wyoming Electric (d)
207,554
 215,257
 696,229
 624,137
Colorado Electric (b)
476,084
 527,947
 1,273,125
 1,473,195
Total Purchased1,040,691
 990,301
 3,192,218
 2,999,498
        
Total Generated and Purchased:       
South Dakota Electric (c)
835,285
 689,982
 2,399,995
 2,053,079
Wyoming Electric434,945
 427,870
 1,298,009
 1,231,594
Colorado Electric591,289
 603,130
 1,574,643
 1,635,917
Total Generated and Purchased1,861,519
 1,720,982
 5,272,647
 4,920,590
__________
(a)Variances for the three and nine months ended September 30, 2017 compared to the same periods in the prior year are driven primarily by the ability to purchase excess generation in the open market at a lower or higher cost than to generate.
(b)Increase in generation in 2017 is due to the addition of the Peak View Wind Project in November 2016. This generation replaced resources provided by PPAs in 2016, reducing the quantities purchased.
(c)Increase in 2017 is primarily driven by resource needs from a new 50 MW power sales agreement effective January 1, 2017.
(d)Year over year increase for nine months ended September 30, 2017 is primarily driven by new load supporting data centers in Cheyenne, Wyoming.



 Three Months Ended September 30, Nine Months Ended September 30,
Quantity Sold (in MWh)20172016 20172016
Residential:     
South Dakota Electric129,616
124,012
 386,709
381,616
Wyoming Electric65,723
63,505
 190,087
191,405
Colorado Electric174,127
176,900
 461,641
470,246
Total Residential369,466
364,417
 1,038,437
1,043,267
      
Commercial:     
South Dakota Electric212,773
213,276
 582,899
592,371
Wyoming Electric137,169
137,534
 398,178
398,414
Colorado Electric208,033
211,716
 566,177
572,062
Total Commercial557,975
562,526
 1,547,254
1,562,847
      
Industrial:     
South Dakota Electric109,745
110,220
 323,038
320,861
Wyoming Electric  (a)
182,844
175,188
 545,640
468,262
Colorado Electric114,357
116,073
 323,638
329,016
Total Industrial406,946
401,481
 1,192,316
1,118,139
      
Municipal:     
South Dakota Electric10,156
9,927
 25,865
25,855
Wyoming Electric2,154
2,201
 6,643
6,848
Colorado Electric35,079
34,507
 92,557
91,116
Total Municipal47,389
46,635
 125,065
123,819
      
Total Retail Quantity Sold1,381,776
1,375,059
 3,903,072
3,848,072
      
Contract Wholesale:     
Total Contract Wholesale-South Dakota Electric (b)
185,723
62,547
 537,720
182,087
      
Off-system Wholesale:     
South Dakota Electric (c)
130,825
128,415
 388,287
438,852
Wyoming Electric17,981
18,788
 72,517
77,534
Colorado Electric (c)
10,619
17,949
 16,479
53,644
Total Off-system Wholesale159,425
165,152
 477,283
570,030
      
Total Quantity Sold:     
South Dakota Electric778,838
648,397
 2,244,518
1,941,642
Wyoming Electric405,871
397,216
 1,213,065
1,142,463
Colorado Electric542,215
557,145
 1,460,492
1,516,084
Total Quantity Sold1,726,924
1,602,758
 4,918,075
4,600,189
      
Other Uses, Losses or Generation, net (d):
     
South Dakota Electric56,447
41,585
 155,477
111,437
Wyoming Electric29,074
30,654
 84,944
89,131
Colorado Electric49,074
45,985
 114,151
119,833
Total Other Uses, Losses and Generation, net134,595
118,224
 354,572
320,401
      
Total Energy1,861,519
1,720,982
 5,272,647
4,920,590
__________________________
(a)    Year over year increasesRevenue and purchased power for the three and nine months ended September 30, 2020 as well as associated quantities, for certain wholesale contracts have been presented on a net basis.  Amounts for the three and nine months ended September 30, 2019, were presented on a gross basis and, due to their immaterial nature, were not revised.  This presentation change has no impact on Gross margin.
(b)    Includes company uses, line losses, and excess exchange production.
Three Months Ended
September 30,
Nine Months Ended
September 30,
Quantities Generated and Purchased (MWh)2020201920202019
Coal-fired592,681 564,220 1,712,540 1,621,355 
Natural Gas and Oil199,408 234,366 453,950 445,498 
Wind54,518 55,407 191,696 167,331 
Total Generated846,607 853,993 2,358,186 2,234,184 
Purchased (a)
1,022,346 1,102,102 2,864,658 3,235,891 
Total Generated and Purchased1,868,953 1,956,095 5,222,844 5,470,075 

Three Months Ended
September 30,
Nine Months Ended
September 30,
Quantities Generated and Purchased (MWh)2020201920202019
Generated:
Colorado Electric97,450 149,509 271,957 341,925 
South Dakota Electric518,821 489,042 1,434,353 1,262,336 
Wyoming Electric230,336 215,442 651,876 629,923 
Total Generated846,607 853,993 2,358,186 2,234,184 
Purchased:
Colorado Electric569,466 484,589 1,493,544 1,269,201 
South Dakota Electric (a)
180,329 346,683 520,549 1,176,030 
Wyoming Electric272,551 270,830 850,565 790,660 
Total Purchased1,022,346 1,102,102 2,864,658 3,235,891 
Total Generated and Purchased1,868,953 1,956,095 5,222,844 5,470,075 
________________
(a)    Purchased power quantities for the three and nine months ended September 30, 2020, for certain wholesale contracts have been presented on a net basis.  Amounts for the three and nine months ended September 30, 2019, were presented on a gross basis and, due to their immaterial nature, were not revised.  This presentation change has no impact on Gross margin.
45


Three Months Ended September 30,
Degree days20202019
ActualVariance from
Normal
ActualVariance from
Normal
Heating Degree Days:
Colorado Electric99 %(96)%
South Dakota Electric202 (10)%175 (22)%
Wyoming Electric208 (29)%120 (77)%
Combined (a)
156 (14)%86 (36)%
Cooling Degree Days:
Colorado Electric987 44 %1,079 58 %
South Dakota Electric561 %366 (31)%
Wyoming Electric492 65 %433 45 %
Combined (a)
742 34 %705 27 %

Nine Months Ended September 30,
Degree days20202019
ActualVariance from
Normal
ActualVariance from
Normal
Heating Degree Days:
Colorado Electric3,073 (9)%3,156 (6)%
South Dakota Electric4,440 — %5,370 20 %
Wyoming Electric4,356 (3)%4,677 %
Combined (a)
3,799 (4)%4,198 %
Cooling Degree Days:
Colorado Electric1,369 53 %1,226 37 %
South Dakota Electric681 %404 (36)%
Wyoming Electric593 70 %462 33 %
Combined (a)
977 41 %791 14 %
____________________
(a)    Combined actuals are drivencalculated based on the weighted average number of total customers by new load supporting data centers instate.

Three Months Ended September 30,Nine Months Ended September 30,
Contracted Power Plant Fleet Availability (a)
2020201920202019
Coal-fired plants (b)
97.4 %94.6 %94.1 %90.0 %
Natural gas-fired plants and Other plants (c)(d)
79.7 %89.6 %80.5 %89.8 %
Wind97.7 %93.7 %98.3 %95.0 %
Total Availability86.8 %91.5 %86.3 %90.3 %
Wind Capacity Factor33.2 %33.8 %39.3 %37.1 %
____________________
(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)     2020 included a planned outage at Cheyenne Wyoming.
(b)Increase for the three and nine months ended September 30, 2017 was primarily due to a new 50 MW power sales agreement effective January 1, 2017.
(c)Decrease in 2017 was primarily driven by commodity prices that impacted power marketing sales.
(d)Includes company uses, line losses, and excess exchange production.

Prairie and unplanned outages at Pueblo Airport Generation and Lange CT.

(d)    2019 included planned outages at Neil Simpson CT and Lange CT.


46


 Three Months Ended September 30,
Degree Days  2017   2016
 Actual 
Variance from
30-Year Average
 Actual Variance to Prior Year Actual 
Variance from
30-Year Average
Heating Degree Days:         
South Dakota Electric202
 (10)% 25% 161
 (23)%
Wyoming Electric292
 (4)% 39% 210
 (19)%
Colorado Electric87
 (11)% 335% 20
 (77)%
Combined (a)
168
 (8)% 57% 107
 (34)%
          
Cooling Degree Days:         
South Dakota Electric595
 11 % 29% 460
 (18)%
Wyoming Electric388
 30 % 8% 358
 19 %
Colorado Electric784
 14 % (19)% 968
 33 %
Combined (a)
640
 15 % (5)% 673
 15 %




          
 Nine Months Ended September 30,
Degree Days2017   2016
 Actual 
Variance from
30-Year Average
 Actual Variance to Prior Year Actual 
Variance from
30-Year Average
Heating Degree Days:         
South Dakota Electric4,242
 (5)% 10% 3,844
 (13)%
Wyoming Electric4,186
 (11)% 2% 4,120
 (12)%
Colorado Electric2,773
 (17)% (2)% 2,821
 (15)%
Combined (a)
3,559
 (11)% 4% 3,430
 (13)%
          
Cooling Degree Days:         
South Dakota Electric709
 12 % 10% 646
 (3)%
Wyoming Electric429
 23 % (7)% 460
 31 %
Colorado Electric1,027
 15 % (23)% 1,337
 40 %
Combined (a)
798
 15 % (14)% 926
 26 %
__________
(a)Combined actuals are calculated based on the weighted average number of total customers by state.

Electric Utilities Power Plant AvailabilityThree Months Ended September 30,Nine Months Ended September 30,
 201720162017 2016 
Coal-fired plants (a)
98.3% 94.8% 88.1% 88.0% 
Natural gas fired plants and Other plants94.6% 98.4% 95.8% 97.0% 
Wind (b)
91.0% 99.1% 92.0% 99.2% 
Total availability95.5% 97.1% 93.0% 93.7% 
         
Wind capacity factor23.6% 33.5% 34.3% 36.1% 
__________
(a)Both the nine months ended September 30, 2017 and 2016 included outages. 2017 included planned outages at Neil Simpson II, Wyodak and Wygen II, and 2016 included a planned outage at Wygen III and an extended planned outage at Wyodak.
(b)2017 is lower than the prior year primarily due to the addition of the Peak View Wind Project for which 2017 is the first year of commercial operation.



Gas Utilities
Three Months Ended September 30,Nine Months Ended September 30,
20202019Variance20202019Variance
(in thousands)
Revenue:
Natural gas - regulated$128,468 $117,549 $10,919 $612,797 $651,366 $(38,569)
Other - non-regulated services15,461 13,195 2,266 53,015 55,927 (2,912)
Total revenue143,929 130,744 13,185 665,812 707,293 (41,481)
Cost of sales:
Natural gas - regulated25,235 28,154 (2,919)222,144 280,312 (58,168)
Other - non-regulated services1,800 4,870 (3,070)4,874 16,975 (12,101)
Total cost of sales27,035 33,024 (5,989)227,018 297,287 (70,269)
Gross margin (non-GAAP)116,894 97,720 19,174 438,794 410,006 28,788 
Operations and maintenance73,642 70,170 3,472 223,351 225,239 (1,888)
Depreciation and amortization25,105 22,814 2,291 76,190 68,160 8,030 
Total operating expenses98,747 92,984 5,763 299,541 293,399 6,142 
Adjusted operating income$18,147 $4,736 $13,411 $139,253 $116,607 $22,646 
 Three Months Ended September 30,Nine Months Ended September 30,
 20172016Variance20172016Variance
 (in thousands)
Revenue:      
Natural gas — regulated$126,865
$123,699
$3,166
$618,924
$515,963
$102,961
Other — non-regulated services16,029
17,746
(1,717)55,327
47,916
7,411
Total revenue142,894
141,445
1,449
674,251
563,879
110,372
       
Cost of sales      
Natural gas — regulated33,376
29,330
4,046
255,410
202,244
53,166
Other — non-regulated services11,917
12,400
(483)33,615
25,755
7,860
Total cost of sales45,293
41,730
3,563
289,025
227,999
61,026
       
Gross margin97,601
99,715
(2,114)385,226
335,880
49,346
       
Operations and maintenance65,390
64,921
469
201,105
179,845
21,260
Depreciation and amortization20,937
21,193
(256)62,658
57,096
5,562
Total operating expenses86,327
86,114
213
263,763
236,941
26,822
       
Operating income11,274
13,601
(2,327)121,463
98,939
22,524
       
Interest expense, net(19,527)(21,267)1,740
(58,919)(53,858)(5,061)
Other income (expense), net(294)(418)124
(342)(28)(314)
Income tax benefit (expense)4,218
5,128
(910)(20,686)(15,065)(5,621)
Net income (loss)(4,329)(2,956)(1,373)41,516
29,988
11,528
Net (income) loss attributable to noncontrolling interest
17
(17)(107)(13)(94)
Net income (loss) available for common stock$(4,329)$(2,939)$(1,390)$41,409
$29,975
$11,434





Results of Operations for the Gas Utilities for the Three Months Ended September 30, 20172020 Compared to the Three Months Ended September 30, 2016: Net loss available for common stock for the Gas Utilities was $(4.3) million2019:

Gross margin for the three months ended September 30, 2017, compared to Net loss available for common stock of $(3.0) million2020 increased as a result of:
(in millions)
Weather (a)
$8.4 
New rates4.9 
Mark-to-market on non-utility natural gas commodity contracts1.8 
Customer growth - distribution1.5 
Non-Utility - Tech Services0.6 
COVID-19 impacts (b)
(0.8)
Other2.8 
Total increase in Gross margin (non-GAAP)$19.2 
____________________
(a)    Weather impacts for the three months ended September 30, 2016, as a result of:

Gross margin decreased primarily due to a $3.4 million weather impact from cooler summer temperatures and higher precipitation driving lower irrigation load to agriculture customers in our Nebraska Gas service territory as2020 compared to the same period in the prior year. This is partially offsetyear include increased irrigation loads to agriculture customers in 2020 in our Nebraska Gas service territory as 2019 was a record precipitation year and increased heating demand due to cooler temperatures.
(b)    The impacts to Gas Utilities’ gross margin from COVID-19 were primarily driven by gas utilities'waived customer growth and higher rider revenue.late payment fees.


Operations and maintenance expense increased primarily due to $1.2 million higher employee related expenses as a resultcosts. COVID-19 impacts to operations and maintenance expense included $1.4 million of prior year integration activities and transition expenses charged to the Corporate segment,additional bad debt expense which was partially offset by $0.7 million of lower pensiontravel and training expenses.


Depreciation and amortization was comparable to the same period in the prior year.

Interest expense, net decreased increased primarily due to the August 2016 refinancinga higher asset base driven by prior year and current year capital expenditures.

47



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

Income tax benefit (expense): The 2017 effective tax rate is lower than 2016 due to increased flow-through benefits and no changes to uncertain tax positions as compared to 2016.

Results of Operations for the Gas Utilities for the Nine Months Ended September 30, 20172020 Compared to the Nine Months Ended September 30, 2016: Net income available for common stock for the Gas Utilities was $41 million2019:

Gross margin for the nine months ended September 30, 2017, compared to Net income available for common stock of $30 million2020 increased as a result of:
(in millions)
New rates$14.1 
Mark-to-market on non-utility natural gas commodity contracts4.2 
Customer growth - distribution3.6 
Prior year amortization of excess deferred income taxes3.5 
Non-Utility - Tech Services and Gas Supply Services1.4 
Weather (a)
0.8 
COVID-19 impacts (b)
(1.7)
Other2.9 
Total increase in Gross margin (non-GAAP)$28.8 
____________________
(a)    Weather impacts for the nine months ended September 30, 2016, as a result of:

Gross margin increased primarily due to additional margins of approximately $51 million contributed by the SourceGas utilities in the first quarter of 20172020 compared to the first quarter of 2016 which included approximately 1.5 months of SourceGas results. 2017 reflects a full nine months of SourceGas results as compared to approximately 7.5 months in 2016. This is partially offset by lower irrigation loads delivered to agriculture customers primarily in the Nebraska service territory due to cooler summer temperatures and higher precipitation in the third quarter of 2017.

Operations and maintenance increased primarily due to additional operating costs of approximately $19 million for the acquired SourceGas utilities, reflecting a full nine months of results in 2017 as compared to approximately 7.5 months in 2016. In addition, employee related expenses increased $5.2 million for the Black Hills legacy gas utilities as a result of prior year integration activities and transition expenses charged to the Corporate segment. A variety of smaller items contribute to the partially offsetting decrease in operations and maintenance expenses.

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

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

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

Income tax benefit (expense): The effective tax rate was comparableyear include increased irrigation loads to the same periodagriculture customers in the prior year.third quarter of 2020 in our Nebraska Gas service territory as 2019 was a record precipitation year mostly offset by lower heating demand in the first quarter of 2020 due to warmer temperatures.



 Three Months Ended September 30, Nine Months Ended September 30,
Revenue (in thousands) (a)
2017 2016 2017 2016
Residential:       
Arkansas$9,085
 $8,201
 $57,992
 $33,778
Colorado12,911
 12,144
 80,351
 65,285
Nebraska (b)
12,622
 12,259
 72,965
 69,132
Iowa10,314
 9,694
 60,618
 57,328
Kansas8,128
 7,760
 44,309
 39,428
Wyoming (b)
4,744
 4,895
 28,172
 23,663
Total Residential$57,804
 $54,953
 $344,407
 $288,614
        
Commercial:       
Arkansas$5,281
 $4,123
 $30,465
 $16,652
Colorado4,893
 4,971
 29,967
 23,107
Nebraska2,994
 3,123
 20,567
 19,462
Iowa3,425
 3,144
 24,522
 22,617
Kansas2,672
 2,298
 14,695
 12,558
Wyoming2,101
 2,315
 13,940
 11,495
Total Commercial$21,366
 $19,974
 $134,156
 $105,891
        
Industrial:       
Arkansas$1,801
 $1,463
 $5,382
 $3,071
Colorado906
 808
 1,588
 1,340
Nebraska158
 143
 363
 330
Iowa119
 189
 1,158
 1,014
Kansas5,734
 5,204
 7,716
 7,793
Wyoming754
 692
 2,492
 2,349
Total Industrial$9,472
 $8,499
 $18,699
 $15,897
        
Transportation:       
Arkansas$2,335
 $1,997
 $7,750
 $5,730
Colorado738
 766
 2,940
 2,531
Nebraska (b) (c)
20,343
 23,222
 54,202
 49,147
Iowa967
 970
 3,557
 3,525
Kansas1,598
 1,736
 4,851
 5,134
Wyoming (b)
4,387
 4,245
 18,849
 14,382
Total Transportation$30,368
 $32,936
 $92,149
 $80,449



 Three Months Ended September 30, Nine Months Ended September 30,
Revenue (in thousands) (continued)2017 2016 2017 2016
Transmission:       
Arkansas$448
 $19
 $1,660
 $44
Colorado4,014
 3,572
 17,778
 12,334
Wyoming1,211
 1,209
 3,712
 3,386
Total Transmission$5,673
 $4,800
 $23,150
 $15,764
        
Other Sales Revenue:       
Arkansas$218
 $398
 $880
 $1,687
Colorado208
 315
 687
 770
Nebraska937
 912
 2,724
 2,587
Iowa96
 96
 357
 409
Kansas494
 582
 936
 3,215
Wyoming229
 234
 779
 680
Total Other Sales Revenue$2,182
 $2,537
 $6,363
 $9,348
        
Total Regulated Revenue$126,865
 $123,699
 $618,924
 $515,963
        
Non-regulated Services16,029
 17,746
 55,327
 47,916
        
Total Revenue$142,894
 $141,445
 $674,251
 $563,879
__________
(a)Certain prior year revenue classes have been revised to conform to current year presentation; total revenue did not change.
(b)Change in prior year due to reclassification of Residential Choice customers from Residential to Transportation class.
(c) Decrease for the three months ended September 30, 2017 is(b)    The impacts to Gas Utilities’ gross margin from COVID-19 were primarily driven by reduced volumes from certain transport customers and waived customer late payment fees.

Operations and maintenance expense decreased primarily due to $2.7 million of lower irrigation load in 2017 comparedoutside services expenses and $1.2 million of lower employee costs partially offset by $1.0 million of higher property taxes due to the prior year.
a higher asset base. COVID-19 impacts to operations and maintenance expense included $2.8 million of additional bad debt expense which was partially offset by $2.2 million of lower travel, training, outside services and employee related expenses.
 Three Months Ended September 30, Nine Months Ended September 30,
Gross Margin (in thousands) (a)
2017 2016 2017 2016
Residential:       
Arkansas$6,934
 $6,735
 $38,020
 $24,116
Colorado7,533
 7,235
 33,784
 28,531
Nebraska (b)
9,333
 9,214
 38,383
 37,634
Iowa8,430
 8,252
 31,442
 30,848
Kansas6,033
 5,872
 24,031
 22,401
Wyoming (b)
3,749
 3,863
 16,596
 15,164
Total Residential$42,012
 $41,171
 $182,256
 $158,694
        
Commercial:       
Arkansas$2,904
 $2,551
 $16,053
 $9,595
Colorado2,198
 2,385
 10,660
 8,612
Nebraska1,606
 1,652
 7,952
 7,865
Iowa1,930
 1,894
 8,504
 8,351
Kansas1,371
 1,289
 5,846
 5,300
Wyoming1,088
 1,217
 5,916
 5,596
Total Commercial$11,097
 $10,988
 $54,931
 $45,319



 Three Months Ended September 30, Nine Months Ended September 30,
Gross Margin (in thousands) (continued)2017 2016 2017 2016
Industrial:       
Arkansas$566
 $582
 $1,727
 $1,268
Colorado292
 326
 513
 594
Nebraska57
 54
 134
 149
Iowa33
 40
 169
 127
Kansas1,052
 986
 1,638
 1,754
Wyoming157
 163
 484
 513
Total Industrial$2,157
 $2,151
 $4,665
 $4,405
        
Transportation:       
Arkansas$2,335
 $1,997
 $7,750
 $5,730
Colorado738
 539
 2,940
 2,293
Nebraska (b) (c)
20,343
 23,222
 54,202
 49,147
Iowa967
 970
 3,557
 3,525
Kansas1,598
 1,736
 4,851
 5,134
Wyoming (b)
4,387
 4,245
 18,849
 14,382
Total Transportation$30,368
 $32,709
 $92,149
 $80,211
        
Transmission:       
Arkansas$448
 $19
 $1,660
 $44
Colorado4,014
 3,572
 17,778
 12,334
Wyoming1,211
 1,209
 3,712
 3,362
Total Transmission$5,673
 $4,800
 $23,150
 $15,740
        
Other Sales Margins:       
Arkansas$218
 $398
 $880
 $1,688
Colorado208
 315
 687
 770
Nebraska937
 912
 2,724
 2,586
Iowa96
 96
 357
 409
Kansas494
 595
 936
 3,217
Wyoming229
 234
 779
 680
Total Other Sales Margins$2,182
 $2,550
 $6,363
 $9,350
        
Total Regulated Gross Margin$93,489
 $94,369
 $363,514
 $313,719
        
Non-regulated Services4,112
 5,346
 21,712
 22,161
        
Total Gross Margin$97,601
 $99,715
 $385,226
 $335,880
__________
(a)Certain prior year revenue classes have been revised to conform to current year presentation.
(b)Change in prior year due to reclassification of Residential Choice customers from Residential to Transportation class.
(c) Decrease for the three months ended September 30, 2017 isDepreciation and amortization increased primarily due to a higher asset base driven by lower irrigation load in 2017 compared to the prior year.year and current year capital expenditures.





Operating Statistics
Gas Revenue
(in thousands)
Gross Margin (non-GAAP)
(in thousands)
Gas Utilities Quantities Sold & Transported (Dth)
Three Months Ended
September 30,
Three Months Ended
September 30,
Three Months Ended
September 30,
202020192020201920202019
Residential$61,515 $57,244 $48,165 $43,441 4,058,040 3,599,549 
Commercial19,940 19,629 12,821 11,589 2,354,719 2,298,919 
Industrial7,280 8,770 2,514 2,493 2,674,127 2,960,930 
Other1,271 2,499 1,271 2,499 — — 
Total Distribution90,006 88,142 64,771 60,022 9,086,886 8,859,398 
Transportation and Transmission38,462 29,407 38,462 29,373 33,668,174 31,538,815 
Total Regulated128,468 117,549 103,233 89,395 42,755,060 40,398,213 
Non-regulated Services15,461 13,195 13,661 8,325 
Total Gas Revenue & Gross Margin
(non-GAAP)
$143,929 $130,744 $116,894 $97,720 
48


 Three Months Ended September 30, Nine Months Ended September 30,
Gas Utilities Quantities Sold and Transportation
(in Dth) (a)
20172016 20172016
Residential:     
Arkansas530,573
531,564
 5,058,717
3,277,167
Colorado1,114,728
1,067,081
 9,385,555
8,012,982
Nebraska747,053
719,880
 7,496,171
7,375,926
Iowa544,429
478,158
 6,691,008
6,744,086
Kansas431,594
416,971
 4,066,531
4,071,723
Wyoming314,567
335,772
 3,354,432
2,951,579
Total Residential3,682,944
3,549,426
 36,052,414
32,433,463
      
Commercial:     
Arkansas586,224
526,937
 3,630,598
2,377,038
Colorado479,409
539,304
 3,700,032
2,973,962
Nebraska317,867
384,546
 2,764,350
2,800,616
Iowa438,185
423,084
 3,729,944
3,725,512
Kansas284,647
220,650
 1,831,946
1,771,050
Wyoming339,515
382,503
 2,454,248
2,194,570
Total Commercial2,445,847
2,477,024
 18,111,118
15,842,748
      
Industrial:     
Arkansas304,556
305,910
 914,235
651,815
Colorado234,770
212,997
 357,806
345,126
Nebraska33,050
29,531
 64,960
62,243
Iowa30,136
52,092
 225,464
243,902
Kansas1,931,919
1,645,891
 2,483,575
2,575,314
Wyoming187,742
185,299
 644,052
673,366
Total Industrial2,722,173
2,431,720
 4,690,092
4,551,766
      
Total Quantities Sold8,850,964
8,458,170
 58,853,624
52,827,977
      
Transportation:     
Arkansas2,528,754
2,225,478
 8,628,581
5,774,791
Colorado1,282,746
668,591
 5,713,315
2,267,404
Nebraska (b)
13,522,759
15,123,440
 42,476,603
38,723,621
Iowa4,333,161
4,394,260
 14,826,265
14,860,343
Kansas4,622,069
4,598,060
 12,593,545
11,646,066
Wyoming4,287,998
4,707,013
 18,076,356
17,194,446
Total Transportation30,577,487
31,716,842
 102,314,665
90,466,671
      
Total Quantities Sold and Transportation39,428,451
40,175,012
 161,168,289
143,294,648
Gas Revenue
(in thousands)
Gross Margin (non-GAAP)
(in thousands)
Gas Utilities Quantities Sold & Transported (Dth)
Nine Months Ended
September 30,
Nine Months Ended
September 30,
Nine Months Ended
September 30,
202020192020201920202019
Residential$351,986 $383,466 $207,654 $201,168 40,790,670 44,356,725 
Commercial127,617 146,752 61,676 61,673 19,155,051 21,484,646 
Industrial18,539 18,764 6,697 5,830 5,771,732 5,141,399 
Other856 (968)856 (968)— — 
Total Distribution498,998 548,014 276,883 267,703 65,717,453 70,982,770 
Transportation and Transmission113,799 103,352 113,770 103,351 108,967,182 110,622,285 
Total Regulated612,797 651,366 390,653 371,054 174,684,635 181,605,055 
Non-regulated Services53,015 55,927 48,141 38,952 
Total Gas Revenue & Gross Margin
(non-GAAP)
$665,812 $707,293 $438,794 $410,006 
__________
(a)Certain prior year revenue classes have been revised to conform to current year presentation.
(b)Decrease for the three months ended September 30, 2017 is primarily driven by lower irrigation load in 2017 compared to the prior year.



Gas Revenue
(in thousands)
Gross Margin (non-GAAP)
(in thousands)
Gas Utilities Quantities Sold & Transported (Dth)
Three Months Ended
September 30,
Three Months Ended
September 30,
Three Months Ended
September 30,
202020192020201920202019
Arkansas Gas$21,043 $21,387 $17,400 $16,249 3,925,893 4,094,454 
Colorado Gas22,724 22,632 16,972 15,667 3,702,666 3,806,360 
Iowa Gas18,155 16,381 14,672 13,135 5,628,110 5,686,772 
Kansas Gas18,591 19,013 13,099 12,309 8,564,408 7,602,758 
Nebraska Gas46,315 35,715 39,755 28,046��16,525,547 13,999,302 
Wyoming Gas17,101 15,616 14,996 12,314 4,408,436 5,208,567 
Total Gas Revenue & Gross Margin (non-GAAP)$143,929 $130,744 $116,894 $97,720 42,755,060 40,398,213 

Gas Revenue
(in thousands)
Gross Margin (non-GAAP)
(in thousands)
Gas Utilities Quantities Sold & Transported (Dth)
Nine Months Ended
September 30,
Nine Months Ended
September 30,
Nine Months Ended
September 30,
202020192020201920202019
Arkansas Gas$124,621 $127,014 $88,161 $79,148 19,795,077 21,061,567 
Colorado Gas123,943 135,816 73,785 73,022 21,845,915 23,050,638 
Iowa Gas94,386 105,736 50,355 50,773 25,429,502 28,834,731 
Kansas Gas70,571 77,609 44,162 42,385 25,202,180 24,336,744 
Nebraska Gas170,447 183,827 122,140 111,828 56,857,061 57,815,316 
Wyoming Gas81,844 77,291 60,191 52,850 25,554,900 26,506,059 
Total Gas Revenue & Gross Margin (non-GAAP)$665,812 $707,293 $438,794 $410,006 174,684,635 181,605,055 

Our Gas Utilities are highly seasonal and sales volumes vary considerably with weather and seasonal heating and industrial loads. Approximately 70% of our Gas Utilities’ revenue and margins are expected in the first and fourth quarters of each year. Therefore, revenue for, and certain expenses of, these operations fluctuate significantly among quarters. Depending upon the geographic location in which our Gas Utilities operate, the winter heating season begins around November 1 and ends around March 31.

49




 Three Months Ended September 30,
Degree Days2017   2016
Heating Degree Days:Actual 
Variance
from 30-Year
Average
 Actual Variance to Prior Year Actual 
Variance
from 30-Year
Average
Arkansas (a) (d)
15 (66)% 67% 9 (79)%
Colorado187 (13)% 22% 153 (29)%
Nebraska66 (40)% (65)% 191 74%
Iowa90 (35)% 32% 68 (51)%
Kansas (a)
37 (32)% 42% 26 (54)%
Wyoming307 1% (2)% 314 3%
Combined (b) (d)
117 (22)% (20)% 146 (2)%
Three Months Ended September 30,
20202019
Heating Degree DaysActualVariance
from Normal
ActualVariance
from Normal
Arkansas Gas (a)
24(44)%(100)%
Colorado Gas159(26)%68(68)%
Iowa Gas1401%43(69)%
Kansas Gas (a)
7027%(101)%
Nebraska Gas109(1)%22(80)%
Wyoming Gas245(20)%183(37)%
Combined (b)
125(13)%53(62)%
          
 Nine Months Ended September 30,
Degree Days2017   2016
Heating Degree Days:Actual 
Variance
from 30-Year
Average
 
Actual Variance to Prior Year (c)
 Actual 
Variance
from 30-Year
Average
Arkansas (a) (d)
1,826
 (26)% 52% 1,198
 (52)%
Colorado3,541
 (14)% (4)% 3,670
 (6)%
Nebraska3,280
 (13)% (1)% 3,312
 (13)%
Iowa3,641
 (13)% (4)% 3,783
 (11)%
Kansas (a)
2,584
 (13)% —% 2,596
 (13)%
Wyoming4,468
 (5)% 3% 4,334
 (7)%
Combined (b) (d)
3,521
 (12)% 10% 3,215
 (20)%
Nine Months Ended September 30,
20202019
Heating Degree DaysActualVariance
from Normal
ActualVariance
from Normal
Arkansas Gas (a)
2,036(18)%2,347(5)%
Colorado Gas3,797(7)%4,115—%
Iowa Gas4,104(2)%4,61110%
Kansas Gas (a)
2,851(4)%3,2048%
Nebraska Gas3,636(4)%4,16910%
Wyoming Gas4,678(1)%5,0939%
Combined (b)
3,731(4)%4,2977%
__________
(a)Arkansas has a weather normalization mechanism in effect during the months of November through April for customers with residential and business rate schedules. Kansas Gas has an approved weather normalization mechanism within its residential and business rate structure, which minimizes weather impact on gross margins. The weather normalization mechanism in Arkansas differs from that in Kansas in that it only uses one location to calculate the weather, compared to Kansas, which uses multiple locations. The weather normalization mechanism in Arkansas minimizes weather impact, but does not eliminate the impact.
(b)The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to its weather normalization mechanism. Arkansas Gas Distribution is partially excluded based on the weather normalization mechanism in effect from November through April.
(c)The actual variance in heating degree days for the nine months ended September 30, 2017 compared to prior year is not a reasonable measurement of weather impacts due to the exclusion of the pre-acquisition heating degree days for the SourceGas utilities in Arkansas, Colorado, Nebraska and Wyoming. These utilities were acquired on February 12, 2016.
(d)In 2016, the 30-year weather average for Arkansas was calculated on average actual daily temperatures. To conform to current year comparisons to normal, the 2016 variances for Arkansas compared to normal and the 2016 combined variance compared to normal have been updated for both the three and nine months ended September 30, 2016.

___________


(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 is excluded based on the weather normalization mechanism in effect from November through April.


Regulatory Matters


For more information on recent regulatory activity and enacted regulatory provisions with respect to the states in which our Utilities operate, see Note 5 of the Notes to Condensed Consolidated Financial Statements and Part I, Items 1 and 2 and Part II, Item 8 of our 20162019 Annual Report on Form 10-K filed with the SEC.


Electric Utilities Rates and Rate Activity

South Dakota Electric Settlement

On June 16, 2017, South Dakota Electric received approval from the SDPUC on a settlement reached with the SDPUC staff agreeing to a six-year moratorium period effective July 1, 2017. As part of this agreement, South Dakota Electric will not increase base rates, absent an extraordinary event. The moratorium period also includes suspension of both the Transmission Facility Adjustment and the Environmental Improvement Adjustment, and a $1.0 million increase to the annual power marketing margin guarantee during this period. Additionally, existing regulatory asset balances of approximately $13 million related to decommissioning and Winter Storm Atlas are being amortized over the moratorium period. These balances were previously being amortized over a 10-year period ending September 30, 2024. The vegetation management regulatory asset of $14 million, previously unamortized, will also be amortized over the moratorium period. The change in amortization periods for these costs will increase annual amortization expense by approximately $2.7 million.

The June 16, 2017 settlement had no impact to base rates. The following table illustrates information about certain enacted regulatory provisions with respect to South Dakota Electric:
SubsidiaryJurisdictionAuthorized 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 Customers
South Dakota ElectricSDGlobal Settlement7.76%Global Settlement$543.910/2014ECA, TCA, Energy Efficiency Cost Recovery/DSM70%

Colorado Electric Rate Case filing

On December 19, 2016, Colorado Electric received approval from the CPUC to increase its annual revenues by $1.2 million to recover investments in a $63 million, 40 MW natural gas-fired combustion turbine and normal increases in operating expenses. This increase is in addition to approximately $5.9 million in annualized revenue being recovered under the Clean Air-Clean Jobs Act construction financing rider. The 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. An authorized return on rate base of 7.4% was received for the remaining system investments, with a return on equity of 9.37% and an approved capital structure of 47.6% debt and 52.4% equity.

On January 9, 2017, we filed an application with the CPUC for rehearing, reargument or reconsideration of the Commission’s December 19, 2016 decision which reduced our proposed $8.9 million annual revenue increase to $1.2 million. This application was denied by the CPUC on June 9, 2017. We subsequently filed an appeal of this decision with Denver District Court on July 10, 2017. The briefing schedule runs through November 2017. The timing of a ruling is uncertain.
We believe the CPUC made errors in their December decision by demonstrating bias, making decisions not supported by evidence, making findings inconsistent with cost-recovery provisions of the Colorado Clean Air-Clean Jobs Act and the Commission’s own prior decisions, and treating Colorado Electric differently than other regulated utilities in Colorado have been treated in similar situations.

Gas Utilities Rates and Rate Activity

RMNG Rate Review

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



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 Stockton Storage (a)
Gas - storage11/20161/2017$2.6
$2.6
Arkansas MRP/ARMRP (b)
Gas9/20179/2017$2.7
$2.7
Kansas Gas (c)
Gas5/20176/2017$1.4
$1.4
RMNG (d)
Gas - transmission and storage11/20161/2017$2.9
$2.9
Nebraska Gas Dist. (e)
Gas10/20162/2017$6.5
$6.5
____________________
(a)On November 15, 2016, Arkansas Gas filed for the recovery of the Stockton Storage revenue requirement through the Stockton Storage Acquisition Rates regulatory mechanism with the rider effective January 1, 2017. This recovery mechanism was initially approved on October 15, 2015 for the Stockton Storage acquisition.
(b)On September 1, 2017, Arkansas Gas filed for recovery of $2.2 million related to projects for the replacement of eligible mains (MRP) and the recovery of $0.5 million related to projects for the relocation of certain at risk meters (ARMRP). Pursuant to the Arkansas Gas Tariff, the filed rates went into effect on the date of the filing.
(c)On February 21, 2017, Kansas Gas filed with the KCC requesting recovery of $1.4 million, which includes $0.6 million of new revenue related to the Gas System Reliability Surcharge rider (“GSRS”). This GSRS filing was approved by the KCC on May 23, 2017 and went into effect on June 1, 2017.
(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 went into effect on February 1, 2017.

Power Generation
Three Months Ended September 30,Nine Months Ended September 30,
20202019Variance20202019Variance
(in thousands)
Revenue$26,518 $25,811 $707 $78,606 $75,764 $2,842 
Fuel expense2,320 2,283 37 6,692 6,933 (241)
Operations and maintenance10,539 6,946 3,593 24,886 20,817 4,069 
Depreciation and amortization4,921 4,760 161 15,539 14,069 1,470 
Total operating expense17,780 13,989 3,791 47,117 41,819 5,298 
Adjusted operating income$8,738 $11,822 $(3,084)$31,489 $33,945 $(2,456)
50


 Three Months Ended September 30,Nine Months Ended September 30,
 20172016Variance20172016Variance
 (in thousands)
Revenue (a)
$22,927
$23,337
$(410)$68,289
$68,359
$(70)
       
Operations and maintenance7,646
7,465
181
24,228
24,155
73
Depreciation and amortization (a)
1,036
996
40
3,312
3,080
232
Total operating expense8,682
8,461
221
27,540
27,235
305
       
Operating income14,245
14,876
(631)40,749
41,124
(375)
       
Interest expense, net(724)(409)(315)(2,015)(1,343)(672)
Other (expense) income, net(5)(9)4
(36)(5)(31)
Income tax (expense) benefit(3,426)(5,046)1,620
(10,114)(13,467)3,353
       
Net income10,090
9,412
678
28,584
26,309
2,275
Net income attributable to noncontrolling interest(3,935)(3,770)(165)(10,567)(6,402)(4,165)
Net income available for common stock$6,155
$5,642
$513
$18,017
$19,907
$(1,890)

____________
(a)The generating facility located in Pueblo, Colorado is accounted for as a capital lease under GAAP; as such, revenue and depreciation expense are impacted by the accounting for this lease. Under the lease, the original cost of the facility is recorded at Colorado Electric and is being depreciated by Colorado Electric for segment reporting purposes.



On April 14, 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million. Black Hills Electric Generation continues to be the majority owner and operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric. Net income available for common stock for the three and nine months ended September 30, 2017, was reduced by $3.9 million and $11 million, respectively, and reduced by $3.8 million and $6.4 million for the three and nine months ended September 30, 2016, respectively, attributable to this noncontrolling interest.

Results of Operations for Power Generation for the Three Months Ended September 30, 20172020 Compared to the Three Months Ended September 30, 2016: Net income available for common stock for2019:

Revenue increased in the Power Generation segment was $6.2current year driven primarily by increased MWh sold from new wind assets and additional Black Hills Colorado IPP fired-engine hours. Operating expenses increased primarily due to a $3.1 million expense related to the early retirement of certain assets and higher generation costs and depreciation from new wind assets.

Nine Months Ended September 30, 2020 Compared to the Nine Months Ended September 30, 2019:

Revenue increased in the current year driven by an increase in MWh sold from new wind assets and additional Black Hills Colorado IPP fired-engine hours. Operating expenses increased primarily due to a $3.1 million expense related to the early retirement of certain assets and higher generation costs and depreciation from new wind assets. COVID-19 impacts to operations and maintenance expense included $0.4 million of expenses related to the sequestration of essential employees.

Operating Statistics
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
Quantities Sold, Generated and Purchased
(MWh) (a)
Sold
Black Hills Colorado IPP301,934 275,867 830,860 692,156 
Black Hills Wyoming (b)
157,855 162,668 471,073 476,430 
Black Hills Electric Generation65,697 30,912 255,605 112,461 
Total Sold525,486 469,447 1,557,538 1,281,047 
Generated
Black Hills Colorado IPP301,934 275,867 830,860 692,156 
Black Hills Wyoming (b)
139,313 142,219 408,545 407,001 
Black Hills Electric Generation65,697 30,912 255,605 112,461 
Total Generated506,944 448,998 1,495,010 1,211,618 
Purchased
Black Hills Wyoming (b)
18,004 16,865 62,097 56,205 
Total Purchased18,004 16,865 62,097 56,205 
___________
(a)    Company uses and losses are not included in the quantities sold, generated, and purchased.
(b)    Under the 20-year economy energy PPA with the City of Gillette effective September 2014, Black Hills Wyoming purchases energy on behalf of the City of Gillette and sells that energy to the City of Gillette. 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.
51


Three Months Ended September 30,Nine Months Ended September 30,
Contracted Power Plant Fleet Availability (a)
2020201920202019
Coal-fired plant96.1 %98.0 %94.5 %95.2 %
Natural gas-fired plants (b)
99.8 %97.6 %99.6 %98.4 %
Wind90.6 %81.9 %92.8 %93.4 %
Total Availability95.8 %93.6 %96.3 %96.5 %
Wind Capacity Factor19.4 %15.0 %25.7 %22.1 %
___________
(a)    Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.
(b)     2019 included a planned outage at Pueblo Airport Generation.


Mining
Three Months Ended September 30,Nine Months Ended September 30,
20202019Variance20202019Variance
(in thousands)
Revenue$15,236 $15,552 $(316)$45,857 $45,026 $831 
Operations and maintenance8,923 9,900 (977)28,481 28,988 (507)
Depreciation, depletion and amortization2,808 2,278 530 7,384 6,687 697 
Total operating expenses11,731 12,178 (447)35,865 35,675 190 
Adjusted operating income$3,505 $3,374 $131 $9,992 $9,351 $641 


Operating Statistics
Three Months Ended September 30,Nine Months Ended September 30,
(in thousands, except for Revenue per ton)2020201920202019
Tons of coal sold940 969 2,808 2,720 
Cubic yards of overburden moved1,595 2,341 6,073 6,380 
Revenue per ton$15.60 $15.47 $15.64 $15.90 


Corporate and Other
Three Months Ended September 30,Nine Months Ended September 30,
20202019Variance20202019Variance
(in thousands)
Adjusted operating income (loss)$(239)$(34)$(205)$(108)$(439)$331 



52


Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax (Expense)
Three Months Ended September 30,Nine Months Ended September 30,
20202019Variance20202019Variance
(in thousands)(in thousands)
Interest expense, net$(36,041)$(33,487)$(2,554)$(107,039)$(102,469)$(4,570)
Impairment of investment— (19,741)$19,741 (6,859)(19,741)$12,882 
Other income (expense), net(1,193)580 $(1,773)(703)55 $(758)
Income tax (expense)(4,651)(2,508)$(2,143)(25,484)(22,078)$(3,406)

Three Months Ended September 30, 2020 Compared to the Three Months Ended September 30, 2019.

Interest expense, net

The increase in Interest expense, net for the three months ended September 30, 2017,2020, compared to Netthe same period in the prior year, was driven by higher debt balances partially offset by lower interest rates.

Impairment of Investment

For the three months ended September 30, 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 continued adverse changes in future natural gas prices and liquidity concerns at the privately held oil and gas company. The remaining book value of our investment is $1.5 million, and this is our only remaining investment in oil and gas exploration and production activities. See Note 15 of the Notes to Condensed Consolidated Financial Statements for additional details.

Other Income (Expense)

The variance in Other income available(expense), net for common stock of $5.6 millionthe three months ended September 30, 2020, compared to the same period in the prior year, was primarily due to increased costs for our non-qualified benefit plans which were driven by market performance on plan assets and increased non-service pension costs resulting from a change in accounting principle for our defined benefit pension plan effective January 1, 2020.
Income Tax (Expense)

For the three months ended September 30, 2020, the effective tax rate was 10.3% compared to 14.0% for the same period in 2016. Revenue2019. The lower effective tax rate is primarily due to increased tax benefits from federal production tax credits associated with new wind assets and operating expenses were comparablereversal of accrued excess deferred income taxes as part of resolving the last of the Company’s open dockets seeking approval of its TCJA plans.

Nine Months Ended September 30, 2020 Compared to the Nine Months Ended September 30, 2019.

Interest expense, net

The increase in Interest expense, net for the nine months ended September 30, 2020, compared to the same period in the prior year was driven by higher debt balances partially offset by lower interest rates.

Impairment of Investment

For the nine months ended September 30, 2020, we recorded a pre-tax non-cash write-down of $6.9 million in our investment in equity securities of a privately held oil and gas company, compared to a $20 million write-down for the same period in the prior year. The varianceimpairments in both years were triggered by continued adverse changes in future natural gas prices and liquidity concerns at the privately held oil and gas company. The remaining book value of our investment is $1.5 million, and this is our only remaining investment in oil and gas exploration and production activities. See Note 15 of the Notes to the prior year was driven by a lower 2017Condensed Consolidated Financial Statements for additional details.



53



Income Tax (Expense)

The effective tax rate compared to 2016 due to the greater impact of minority interest and higher 2016 adjustments to the filed tax return.

Results of Operationswas 13.6% for Power Generation for the Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016: Net income available for common stock for the Power Generation segment was $18 million forboth the nine months ended September 30, 2017, compared to Net income available for common stock of $20 million for the same period in 2016. Revenue2020 and operating expenses were comparable to the same period in the prior year. The variance to the prior year was due to Black Hills Colorado IPP going from a single member LLC, wholly owned by Black Hills Electric Generation, to a partnership as a result of the sale of 49.9% of its membership interest in April 2016. The effective tax rate reflects the income attributable to the noncontrolling interest for which a tax provision is not recorded. Net income attributable to noncontrolling interest also increased by $4.2 million as a result of the noncontrolling interest sale in April 2016.

The following table summarizes MWh for our Power Generation segment:
 Three Months Ended September 30, Nine Months Ended September 30,
 20172016 20172016
Quantities Sold, Generated and Purchased
(MWh) (a)
     
Sold     
Black Hills Colorado IPP (b)
256,895
327,793
 725,919
972,113
Black Hills Wyoming (c)
163,690
167,670
 476,659
476,677
Total Sold420,585
495,463
 1,202,578
1,448,790
      
Generated     
Black Hills Colorado IPP (b)
256,895
327,793
 725,919
972,113
Black Hills Wyoming (c)
140,081
142,388
 407,775
401,292
Total Generated396,976
470,181
 1,133,694
1,373,405
      
Purchased     
Black Hills Colorado IPP

 

Black Hills Wyoming (c)
20,246
23,558
 52,463
68,797
Total Purchased20,246
23,558
 52,463
68,797
____________
(a)Company uses and losses are not included in the quantities sold, generated, and purchased.
(b)Decrease from the prior year is a result of the 2017 impact of Colorado Electric’s wind generation replacing natural-gas generation.
(c)Under the 20-year economy energy PPA with the City of Gillette effective September 2014, Black Hills Wyoming purchases energy on behalf of the City of Gillette and sells that energy to the City of Gillette. 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.



The following table provides certain operating statistics for our plants within the Power Generation segment:
 Three Months Ended September 30, Nine Months Ended September 30,
 20172016 20172016
Contracted power plant fleet availability:     
Coal-fired plant97.1%98.7% 95.8%94.1%
Natural gas-fired plants99.2%99.1% 99.1%99.2%
Total availability98.7%99.0% 98.3%97.9%

Mining
 Three Months Ended September 30,Nine Months Ended September 30,
 20172016Variance20172016Variance
 (in thousands)
Revenue$17,493
$16,820
$673
$48,985
$44,149
$4,836
       
Operations and maintenance11,235
10,465
770
32,162
29,186
2,976
Depreciation, depletion and amortization2,004
2,342
(338)6,231
7,269
(1,038)
Total operating expenses13,239
12,807
432
38,393
36,455
1,938
       
Operating income4,254
4,013
241
10,592
7,694
2,898
       
Interest (expense) income, net(47)(100)53
(146)(283)137
Other income, net567
559
8
1,644
1,625
19
Income tax benefit (expense)(1,297)(1,165)(132)(3,042)(2,067)(975)
       
Net income$3,477
$3,307
$170
$9,048
$6,969
$2,079

The following table provides certain operating statistics for our Mining segment (in thousands, except for Revenue per ton):

 Three Months Ended September 30, Nine Months Ended September 30,
 20172016 20172016
Tons of coal sold1,151
1,106
 3,127
2,722
Cubic yards of overburden moved (a)
2,316
2,065
 6,381
5,516
      
Revenue per ton$15.20
$15.20
 $15.67
$16.21
____________
(a)Increase is driven by mining in areas with more overburden than in the prior year as well as higher production.



Results of Operations for Mining for the Three Months Ended September 30, 2017 Compared to the Three Months Ended September 30, 2016: Net income available for common stock for the Mining segment was $3.5 million for the three months ended September 30, 2017, compared to Net income available for common stock of $3.3 million for the same period in 2016 as a result of:

Revenue increased due to a 4% increase in tons sold, with comparable pricing to the same period last year. The increased tons sold were driven primarily by Wyodak plant generating requirements. During the current period, approximately 47% of the mine’s production was sold under contracts that include price adjustments based on actual mining costs, including income taxes.

Operations and maintenance increased2019, primarily due to increased overburden removaltax benefits from forecasted federal production tax credits associated with new wind assets and higher royalties and productionreversal of accrued excess deferred income taxes on increased revenues.

Depreciation, depletion and amortization decreased primarily due to a reduction in asset retirement obligation costs.

Interest (expense) income, net was comparable toas part of resolving the same period inlast of the prior year.

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

Income tax benefit (expense): The effective tax rate is comparable to the same period last year.

ResultsCompany’s open dockets seeking approval of Operations for Mining for the Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016: Net income available for common stock for the Mining segment was $9.0 million for the nine months ended September 30, 2017, compared to Net income available for common stock of $7.0 million for the same period in 2016 as a result of:

Revenue increased due to a 15% increase in tons sold, partiallyits TCJA plans offset by a 3% decrease in price per ton sold. The increased tons sold were driven primarily by an 11-week outage at the Wyodak plant in the prior year. The decrease in price per ton sold was driven by higher volumes sold under fixed price contracts. During the current period, approximately 46% of the mine’s production was sold under contracts that include price adjustments based on actual mining costs, including income taxes.

Operations and maintenance increased primarily due to increased overburden removal and higher royalties and production taxes on increased revenues.

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

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

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

Incomeyear discrete tax benefit (expense): The effective tax rate increased reflecting a prior year tax benefit of percentage depletion.



Oil and Gas
 Three Months Ended September 30,Nine Months Ended September 30,
 20172016Variance20172016Variance
 (in thousands)
Revenue$6,527
$9,639
$(3,112)$19,151
$25,660
$(6,509)
       
Operations and maintenance6,076
7,592
(1,516)20,385
24,539
(4,154)
Depreciation, depletion and amortization2,391
3,483
(1,092)6,300
11,415
(5,115)
Impairment of long-lived assets
12,293
(12,293)
52,286
(52,286)
Total operating expenses8,467
23,368
(14,901)26,685
88,240
(61,555)
       
Operating (loss)(1,940)(13,729)11,789
(7,534)(62,580)55,046
       
Interest income (expense), net(1,269)(1,295)26
(3,459)(3,529)70
Other income (expense), net(3)16
(19)14
85
(71)
Income tax benefit (expense)500
6,180
(5,680)3,370
30,747
(27,377)
       
Net (loss)$(2,712)$(8,828)$6,116
$(7,609)$(35,277)$27,668

Results of Operations for Oil and Gas for the Three Months Ended September 30, 2017 Compared to the Three Months Ended September 30, 2016: Net loss available for common stock for the Oil and Gas segment was $(2.7) million for the three months ended September 30, 2017, compared to Net loss available for common stock of $(8.8) million for the same period in 2016 as a result of:

Revenue decreased primarily due to a 9% production decrease compared to the same period in the prior year. Natural gas production decreased primarily due to the 2016 sales of non-core properties, and the intentional limiting of gas production to the minimum daily quantities required to meet contractual processing commitments in the Piceance Basin. Crude oil production also decreased due to non-core property sales in the fourth quarter of 2016. The average hedged price received for crude oil sold decreased 11%. The average hedged price received for natural gas sold decreased by 15%.

Operations and maintenance decreased primarily due to lower employee costs and lower production and ad valorem taxes on lower revenue.

Depreciation, depletion and amortization decreased primarily due to the reduction in our full cost pool resulting from the ceiling test impairments incurred in the prior year.

Impairment of long-lived assets represents a prior year 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 prior year ceiling test write-down of $12 million used a trailing 12 month average NYMEX natural gas price of $2.28 per Mcf, adjusted to $1.03 per Mcf at the wellhead, and $41.68 per barrel for crude oil, adjusted to $35.88 per barrel at the wellhead.

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

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

Income tax (expense) benefit: Each period represents a tax benefit. The current period effective tax rate is lower due primarily to a reduction to the marginal well credit compared to the same period last year.



Results of Operations for Oil and Gas for the Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016: Net loss available for common stock for the Oil and Gas segment was $(7.6) million for the nine months ended September 30, 2017, compared to Net loss available for common stock of $(35) million for the same period in 2016 as a result of:

Revenue decreased primarily due to a 17% production decrease compared to the same period in the prior year. Natural gas production decreased primarily due to the 2016 sales of non-core properties and the intentional limiting of gas production to the minimum daily quantities required to meet contractual processing commitments in the Piceance Basin. Crude oil production also decreased due to non-core property sales in the fourth quarter of 2016. The average hedged price received for crude oil sold decreased 14%. The lower production volumes and crude oil pricing were partially offset by a 21% increase in the average hedged price received for natural gas sold.

Operations and maintenance decreased primarily due to lower employee costs and lower production and ad valorem taxes on lower revenue.

Depreciation, depletion and amortization decreased primarily due to the reduction in our full cost pool resulting from the ceiling test impairments incurred in the prior year.

Impairment of long-lived assets represents a prior year 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 prior year write down of $52 million included a $14 million write-down of depreciable properties excluded from our full-cost pool and a ceiling test write-down of $38 million. The ceiling test write-down for the nine months ended September 30, 2016 used an average NYMEX natural gas price of $2.28 per Mcf, adjusted to $1.03 per Mcf at the well head, and $41.68 per barrel for crude oil, adjusted to $35.88 per barrel at the wellhead.

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

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

Income tax (expense) benefit: Each period represents a tax benefit. The effective tax rate for the nine months ended September 30, 2016 reflects 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 were 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.

The following tables provide certain operating statistics for our Oil and Gas segment:
 Three Months Ended September 30, Nine Months Ended September 30,
 20172016 20172016
Production:     
Bbls of oil sold45,240
89,569
 139,642
263,788
Mcf of natural gas sold2,379,189
2,426,892
 6,392,999
7,148,952
Bbls of NGL sold30,810
27,640
 82,539
105,535
Mcf equivalent sales2,835,487
3,130,147
 7,726,083
9,364,891
 Three Months Ended September 30, Nine Months Ended September 30,
 20172016 20172016
Average price received: (a)
     
Oil/Bbl$50.22
$56.64
 $46.95
$54.38
Gas/Mcf  
$1.39
$1.63
 $1.55
$1.28
NGL/Bbl$21.79
$11.31
 $19.99
$10.95
      
Depletion expense/Mcfe$0.52
$0.81
 $0.46
$0.86
__________
(a)Net of hedge settlement gains and losses.




The following is a summary of certain average operating expenses per Mcfe:
 Three Months Ended September 30, 2017 Three Months Ended September 30, 2016
Producing BasinLOE
Gathering,
 Compression,
  Processing and Transportation (a)
Production TaxesTotal LOE
Gathering,
 Compression,
  Processing and Transportation (a)
Production TaxesTotal
San Juan$1.60
$1.04
$0.36
$3.00
 $1.69
$1.19
$0.38
$3.26
Piceance0.20
1.65
0.06
1.91
 0.24
1.84
0.16
2.24
Powder River1.78

0.68
2.46
 1.89

0.20
2.09
Williston



 0.84

1.64
2.48
All other properties1.00

0.28
1.28
 0.30

0.22
0.52
Total weighted average$0.75
$1.25
$0.22
$2.22
 $0.84
$1.19
$0.33
$2.36

          
 Nine Months Ended September 30, 2017 Nine Months Ended September 30, 2016
Producing BasinLOE
Gathering,
 Compression,
  Processing and Transportation (a)
Production TaxesTotal LOE
Gathering,
 Compression,
  Processing and Transportation (a)
Production TaxesTotal
San Juan$1.67
$1.11
$0.38
$3.16
 $1.65
$1.11
$0.31
$3.07
Piceance0.42
1.83
0.05
2.30
 0.31
1.86
0.13
2.30
Powder River2.30

0.72
3.02
 2.52

0.45
2.97
Williston



 1.22

1.02
2.24
All other properties1.39

0.30
1.69
 0.37

0.12
0.49
Total weighted average$1.03
$1.34
$0.23
$2.60
 $1.00
$1.18
$0.27
$2.45
__________
(a)These costs include both third-party costs and operations costs.

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, while 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.

We have a ten-year gas gathering and processing contract for our natural gas production in the Piceance Basin which became effective in March of 2014. This take-or-pay contract requires us to pay a fee on a minimum of 20,000 Mcf per day, regardless of the volume delivered. Our gathering, compression and processing costs on a per Mcfe basis, as shown in the table above, will be higher in periods when we are not meeting the minimum contract requirements.



Corporate Activity

Results of Operations for Corporate activities for the Three Months Ended September 30, 2017 Compared to the Three Months Ended September 30, 2016: Net loss available for common stock for Corporate was $(2.3) million for the three months ended September 30, 2017, compared to Net loss available for common stock of $(7.2) million for the three months ended September 30, 2016. The variance from the prior year was primarily due to higher corporate expenses incurred in the prior year related to the SourceGas Acquisition. The third quarter of 2017 included approximately $0.2 million of non-recurring after-tax acquisitionrepairs and transition costs compared to approximately $4.0 million of after-tax non-recurring acquisition and transition costs in the third quarter of 2016. The third quarter of 2016 included $1.7 million of after-tax internal labor related to the SourceGas Acquisition that otherwise would have been charged to other business segments and also included lower income tax expense compared to the third quarter of 2017.certain indirect costs.


Results of Operations for Corporate activities for the Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016: Net loss available for common stock for Corporate was $(2.9) million for the nine months ended September 30, 2017, compared to Net loss available for common stock of $(29) million for the nine months ended September 30, 2016. The variance from the prior year was primarily due to higher corporate expenses incurred in the prior year related to the SourceGas Acquisition. Current year corporate expenses included approximately $1.5 million of after-tax non-recurring acquisition and transition costs, compared to a total of approximately $24 million of after-tax non-recurring acquisition and transition costs and approximately $7.4 million of after-tax internal labor related to the SourceGas Acquisition that otherwise would have been charged to other business segments. During the nine months ended September 30, 2017, we recognized a tax benefit of approximately $1.4 million tax benefit from a carryback claim for specified liability losses involving prior years. The same period in the prior year included a tax benefit of approximately $4.4 million recognized as a result of an agreement reached with IRS Appeals relating to the release of the reserve for after-tax interest expense previously accrued with respect to the liability for uncertain tax positions involving a like-kind exchange transaction from 2008.

Critical Accounting Policies Involving Significant Accounting Estimates


There have been no material changes in our critical accounting estimates from those reported in our 20162019 Annual Report on Form 10-K filed with the SEC.SEC except for Pension and Other Postretirement Benefits provided below. We continue to closely monitor the rapidly evolving and uncertain impact of COVID-19 on our critical accounting estimates including, but not limited to, collectibility of customer receivables, recoverability of regulatory assets, impairment risk of goodwill and long-lived assets, valuation of pension assets and liabilities, and contingent liabilities. For more information on our critical accounting estimates, see Part II, Item 7 of our 20162019 Annual Report on Form 10-K.


Pension and Other Postretirement Benefits

As described in Note 18 of the Notes to the Consolidated Financial Statements in our 2019 Annual Report on Form 10-K filed with the SEC, we have one defined benefit pension plan, one defined post-retirement healthcare plan and several non-qualified retirement plans. A Master Trust holds the assets for the pension plan. A trust for the funded portion of the post-retirement healthcare plan has also been established.

Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rates, healthcare cost trend rates, expected return on plan assets, compensation increases, retirement rates and mortality rates. The determination of our obligation and expenses for pension and other postretirement benefits is dependent on the assumptions determined by management and used by actuaries in calculating the amounts. Although we believe our assumptions are appropriate, significant differences in our actual experience or significant changes in our assumptions may materially affect our pension and other postretirement obligations and our future expense.

Effective January 1, 2020, the Company changed its method of accounting for net periodic benefit cost. Prior to the change, the Company used a calculated value for determining market-related value of plan assets which amortized the effects of gains and losses over a five-year period. Effective with the accounting change, the Company will use a calculated value for the return-seeking assets (equities) in the portfolio and fair value for the liability-hedging assets (fixed income). The Company considers the fair value method for determining market-related value of liability-hedging assets to be a preferable method of accounting because asset-related gains and losses are subject to amortization into pension cost immediately. Additionally, the fair value for liability-hedging assets allows for the impact of gains and losses on this portion of the asset portfolio to be reflected in tandem with changes in the liability which is linked to changes in the discount rate assumption for re-measurement.

See Note 12 of the Notes to Condensed Consolidated Financial Statements for additional information.


54


Liquidity and Capital Resources


OVERVIEWThere have been no material changes in Liquidity and Capital Resources from those reported in Item 7 of our 2019 Annual Report on Form 10-K filed with the SEC except as described below and within the “COVID-19 Pandemic” discussion in the Executive Summary section above.


Collateral Requirements

Our Company requires significant cash to support and grow our business. Our predominant source of cash is supplied by 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.

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


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 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 Utilitiesutilities 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 September 30, 2017,2020, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts. For the nine months ended September 30, 2020, we did not experience any requests to post additional collateral, including for concerns over a potential deterioration of our financial condition due to COVID-19.



Cash Flow Activities


The following table summarizes our cash flows for the nine months ended September 30, (in thousands)millions):

Cash provided by (used in):20202019Variance
Operating activities$419.5 $386.1 $33.4 
Investing activities$(529.7)$(593.3)$63.6 
Financing activities$107.8 $199.8 $(92.0)
Cash provided by (used in):20172016Increase (Decrease)
Operating activities$319,430
$209,201
$110,229
Investing activities$(256,388)$(1,459,196)$1,202,808
Financing activities$(63,112)$840,948
$(904,060)


Year-to-Date 20172020 Compared to Year-to-Date 20162019


Operating Activities


Net cash provided by operating activities was $319$419 million for the nine months ended September 30, 2017,2020, compared to net cash provided by operating activities of $209$386 million for the same period in 20162019, for a variancean increase of $110$33 million. The variance was primarily attributable to:


Cash earnings (net income plus non-cash adjustments) were $65$22 million higher for the nine months ended September 30, 20172020 compared to the same period in the prior year;year primarily driven by higher operating income at the Gas Utilities segment;


Net cash outflowsinflows from changes in operating assets and liabilities were $17$27 million for the nine months ended September 30, 2017,2020, compared to net cash outflowsinflows of $44$15 million in the same period in the prior year. This $27$12 million varianceincrease was primarily due to:

Cash outflows decreased due to an increase in cash inflows of approximately $14 million for the nine months ended September 30, 2017 primarily as a result of changes in our accounts receivable, partially offset by higher natural gas in storage for the nine months ended September 30, 2017 compared to the same period in the prior year;

Cash outflows decreased by approximately $16 million as a result of changes in accounts payable and accrued liabilities driven by changes in working capital requirements, primarily related to acquisition and transaction costs that took place in the prior year;

Cash outflows increased by approximately $3.3 million as a result of changes in our current regulatory assets and liabilities driven by differences in fuel cost adjustments and commodity price impacts on working capital compared to the same period in the prior year;


Net cashCash inflows decreased by $46 million primarily as a result of changes in accounts receivable driven by lower commodity prices and increased materials and supplies purchases;

Cash outflows decreased by approximately $29$72 million as a result of a prior yearchanges in accounts payable and accrued liabilities driven by the impact of lower commodity prices, lower outside services expenses, timing of interest rate settlement;payments, deferral of payroll taxes under the CARES Act and other working capital requirements; and




Net cashCash outflows increased by $14$13 million dueprimarily as a result of changes in our regulatory assets and liabilities driven by timing of recovery and returns for fuel costs adjustments partially offset by the TCJA tax rate change that was returned to additional pension contributions madecustomers in the currentprior year.


55



Investing Activities


Net cash used in investing activities was $256$530 million for the nine months ended September 30, 2017,2020, compared to net cash used in investing activities of $1.5 billion$593 million for the same period in 2016 for2019, a variancedecrease of $1.2 billion. This variance was$64 million primarily due to:

The prior year’s cash outflows included $1.124 billion for the acquisition of SourceGas, net of $760 million of long term debt assumed (see Note 2 of our Notes to the Consolidated Financial Statements in our 2016 Annual Report on Form 10-K for more details); andfollowing:


Capital expenditures of approximately $256$536 million for the nine months ended September 30, 20172020 compared to $334$593 million for the nine months ended September 30, 2016. The variance tosame period in the prior year was due primarily to higheryear. Higher prior year capital expenditures were driven by large prior year projects such as the Natural Bridge pipeline project, the Busch Ranch II wind project and construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota to Stegall, Nebraska. These large prior year expenditures were partially offset by the current year Corriedale wind project at our Electric Utilities primarily from generation investments at Colorado Electric, partially offset by higher current year capital expenditures at our Gas Utilities.segment.


Financing Activities


Net cash used inprovided by financing activities for the nine months ended September 30, 20172020 was $63$108 million, compared to $841$200 million of net cash provided by financing activities for the same period in 2016 for2019, a variancedecrease of $904 million. This variance was$92 million primarily driven by:

Long-term borrowings decreased by $1.8 billion due to the 2016 financings which consistedfollowing:

$374 million of $693higher repayments of short-term debt;

Increase of $297 million in net proceeds due to issuances of long-term debt in excess of maturities;

Cash dividends on common stock of $100 million were paid in the current year compared to $92 million paid in the prior year;

Cash outflows for other financing activities increased $4.5 million driven primarily by current year financing costs in the June 17, 2020 debt offering; and

Decrease of $2.0 million in net proceeds from the August 19, 2016 public debt offering used to refinance the debt assumed in the SourceGas Acquisition, $500 millionissuance of proceeds from the August 9, 2016 term loan, $546 million of net proceeds from our January 13, 2016 public debt offering used to partially finance the SourceGas Acquisition and proceeds from a $29 million term loan used to fund the early settlement of a gas gathering contract;common stock;


Payments on long-term debt decreased by $1.1 billion due to the 2016 refinancing of the $760 million of long-term debt assumed in the SourceGas Acquisition and lower current year payments on term loans, $104 million paid on term loans in 2017 compared to $400 million paid on term loans in 2016.

Proceeds of $216 million from the sale of a 49.9% noncontrolling interest of Colorado IPP that took place in the prior year;

Net short-term borrowings increased by $130 million primarily due to CP borrowings used to pay down long-term debt;

Proceeds from common stock decreased by approximately $104 million due to prior year stock issuances under our ATM equity offering program;

Distributions to noncontrolling interests increased by $8.4 million compared to the prior year;

Increased dividend payments of approximately $6.1 million; and

Lower other financing activities of approximately $10 million driven primarily by higher financing costs incurred in the prior year from the 2016 debt offerings and refinancings compared to a payment of $5.6 million for a redeemable noncontrolling interest in March 2017.

Dividends


Dividends paid on our common stock totaled $71$100 million for the nine months ended September 30, 2017,2020, or $0.445$0.535 per share per quarter. On November 1, 2017,October 27, 2020, our board of directors declared a quarterly dividend of $0.475$0.565 per share payable December 1, 2017, which brings our total2020, equivalent to an annual dividend for 2017 to $1.81of $2.26 per share. The amount of any future cash dividends to be declared and paid, if any, will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our Revolving Credit Facility and our future business prospects.




Debt


Financing Transactions and Short-Term Liquidity

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


Revolving Credit Facility and CP Program


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. This facility is similar to the former agreement, which includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents, 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. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our most favorable Corporate credit rating from S&P or Moody’s for our unsecured debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.250%, 1.250%, and 1.250%, respectively, at September 30, 2017. A 0.200% commitment fee is charged on the unused amount of the Revolving Credit Facility.

On December 22, 2016, we implemented a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under theOur Revolving Credit Facility and the CP Program either individually or in the aggregate, cannot exceed $750 million. The notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration exemption.

Our Revolving Credit Facility had the following borrowings, outstanding letters of credit, and available capacity (in millions):
CurrentRevolver Borrowings atCP Program Borrowings at
Letters of Credit (a) at
Available Capacity at
Credit FacilityExpirationCapacitySeptember 30, 2020September 30, 2020September 30, 2020September 30, 2020
Revolving Credit Facility and CP ProgramJuly 30, 2023$750 $— $84 $25 $641 
_______________
(a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility.

56


  CurrentRevolver Borrowings atCP Program Borrowings atLetters of Credit atAvailable Capacity at
Credit FacilityExpirationCapacitySeptember 30, 2017September 30, 2017September 30, 2017September 30, 2017
Revolving Credit FacilityAugust 9, 2021$750
$
$225
$25
$500

The weighted average interest rate on CP Program borrowings at September 30, 2017 was 1.46%. Revolving Credit Facility and CP Program financingborrowing activity for the nine months ended September 30, 20172020 was (dollars in millions):
 For the Nine Months Ended September 30, 2017
Maximum amount outstanding - commercial paper (based on daily outstanding balances)$238
Maximum amount outstanding - revolving credit facility (based on daily outstanding balances)$97
Average amount outstanding - commercial paper (based on daily outstanding balances) (a)
$107
Average amount outstanding - revolving credit facility (based on daily outstanding balances) (a)
$55
Weighted average interest rates - commercial paper (a)
1.28%
Weighted average interest rates - revolving credit facility (a)
2.07%
__________
(a)Averages forFor the Nine Months Ended September 30, 2020
Maximum amount outstanding - Revolving Credit Facility are for the first 29 days of the year after which all borrowings were through the(based on daily outstanding balances)$220 
Maximum amount outstanding - CP Program.Program (based on daily outstanding balances)$366 
Average amount outstanding - Revolving Credit Facility (based on daily outstanding balances)$109 
Average amount outstanding - CP Program (based on daily outstanding balances)$170 
Weighted average interest rates - Revolving Credit Facility1.75 %
Weighted average interest rates - CP Program1.10 %


Covenant Requirements

The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on certain liens, restrictions on certain transactions, and maintenance of a certain Consolidated Indebtedness to Capitalization Ratio. Under the Revolving Credit Facility, our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness, which includes letters of credit, certain guarantees issued and excludes RSNs by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interests in subsidiaries and includes the aggregate outstanding amount of the RSNs. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. We were in compliance with these covenants as of September 30, 2017.



The Revolving Credit Facility prohibits us from paying cash dividends if a default or an event of default exists prior to, or would result after, paying a dividend. Although these contractual restrictions exist, we do not anticipate triggering any default measures or restrictions.

Financing Activities

Financing activities for the nine months ended September 30, 2017 consisted of short-term borrowings from our Revolving Credit Facility and CP Program. We also made principal payments of $50 million each on May 16, 2017 and July 17, 2017 on our Corporate term loan due August 9, 2019. Short-term borrowings from our CP program were used to fund the payments on the Corporate term loan. On August 4, 2017, we renewed the ATM equity offering program initiated in 2016 which reset the size2020. See Note 7 of the ATM equity offering programNotes to an aggregate value of up to $300 million. We did not issue any shares of common stock under our ATM equity offering program.Condensed Consolidated Financial Statements for more information.


Financing activities from the prior year consisted of completing the permanent financing for the SourceGas Acquisition. In addition to the net proceeds of $536 million from our November 2015 equity issuances, we completed the Acquisition financing with $546 million of net proceeds from our January 2016 debt offering. We also refinanced the long-term debt assumed with the SourceGas Acquisition primarily through $693 million of net proceeds from our August 19, 2016 debt offerings. In addition to our debt refinancings, we issued a total of 1.97 million shares of common stock throughout 2016 for net proceeds of approximately $119 million through our ATM equity offering program, and sold a 49.9% noncontrolling interest in Black Hills Colorado IPP for $216 million in April 2016.

Future Financing Plans

We anticipate the following financing activities:

Remarketing the junior subordinated notes maturing in 2018;

Evaluating a one-to-two year extension of our Revolving Credit Facility and CP program to be completed in 2018; and

Evaluating refinancing options for term loan and short-term borrowings under our Revolving Credit Facility and CP program.

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, Nebraska andCovenants within Wyoming 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 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 of 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. As of September 30, 2017, the restricted net assets at our Electric Utilities and Gas Utilities were approximately $257 million.


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 meet certain financial covenants. The only financial covenant under our Revolving Credit Facility and existing term loans is a Consolidated Indebtedness to Capitalization Ratio, which requires us to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00 at the end of any fiscal quarter. 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. Additionally, covenants within Cheyenne Light’sElectric’s financing agreements require Cheyenne LightWyoming Electric to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of September 30, 2017,2020, we were in compliance with these covenants.

Financing Activities
There have been no other material changes in
See Notes 7 and 8 of the Notes to Condensed Consolidated Financial Statements for information concerning significant financing activities for the nine months ended September 30, 2020.

Future Financing Plans

We will continue to assess debt and equity needs to support our financing transactions and short-term liquidity from those reported in Item 7 of our 2016 Annual Report on Form 10-K filed with the SEC.capital expenditure plan.


Credit Ratings


Financing for operational needs and capital expenditure requirements not satisfied by operating cash flows depends upon the cost and availability of external funds through both short and long-term financing. The inability to raise capital on favorable terms could negatively affect our ability to maintain or expand our businesses. 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 the 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 and outlook and risk profile of BHC at September 30, 2017:
2020:
Rating AgencySenior Unsecured RatingOutlook
S&P (a)
BBBBBB+Stable
Moody’s (b)
Baa2Stable
Fitch (c)
  BBB+Stable
__________
(a)On July 21, 2017, S&P affirmed BBB rating and maintained a Stable outlook.
(b)On December 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.
(c)On October 4, 2017, Fitch affirmed BBB+ rating and maintained a Stable outlook.

(a)    On April 10, 2020, 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 20, 2020, Fitch affirmed our BBB+ rating and maintained a Stable outlook.

57


The following table represents the credit ratings of Black Hills PowerSouth Dakota Electric at September 30, 2017:

2020:
Rating AgencySenior Secured Rating
S&P(a)
A-A
Moody’s(b)
A1
Fitch(c)
A

__________
There were no rating changes for Black Hills Power from previously disclosed ratings.(a)    On April 16, 2020, S&P affirmed A rating.


(b)    On December 20, 2019, Moody’s affirmed A1 rating.

(c)    On August 20, 2020, Fitch affirmed A rating.


Capital Requirements


Capital Expenditures

Actual and forecasted capital requirements are as follows (in thousands):
ActualPlanned
Expenditures for the Total Total Total
Nine Months Ended September 30, 2017 (a)
 
2017 Planned
Expenditures (b)
 
2018 Planned
Expenditures
 
2019 Planned
Expenditures
Capital Expenditures by SegmentCapital Expenditures by Segment
Nine Months Ended September 30, 2020 (a)
2020 (b)
2021202220232024
(in millions)(in millions)
Electric Utilities$113,199
 $134,000
 $149,000
 $193,000
Electric Utilities$179 $262 $240 $180 $143 $156 
Gas Utilities122,482
 187,000
 263,000
 279,000
Gas Utilities329 434 363 334 327 317 
Power Generation1,899
 1,000
 2,000
 14,000
Power Generation12 10 10 
Mining4,315
 7,000
 7,000
 7,000
Mining
Oil and Gas (c)
16,951
 21,000
 
 
Corporate5,075
 7,000
 9,000
 13,000
Corporate and OtherCorporate and Other10 19 11 12 13 
$263,921
 $357,000
 $430,000
 $506,000
$536 $733 $633 $537 $497 $499 
__________
(a)    Expenditures for the nine months ended September 30, 20172020 include the impact of accruals for property, plant and equipment.
(b)    Includes actual capital expenditures for the nine months ended September 30, 2017.2020.
(c)Expenditures reflect the completion of two wells previously drilled in 2015 to meet minimum daily quantity requirements for the Piceance Basin gathering and processing contract.


We are monitoring supply chains, including lead times for key materials and supplies, availability of resources, and statuses of large capital projects. To date, there have updated our planned 2018been limited impacts from COVID-19 on supply chains including the availability of supplies and 2019 capital expendituresmaterials and lead times. Capital projects are ongoing without material disruption to primarily reflect the following:

additional planned transmission and distribution investments at our Electric Utilities in 2018 and 2019; and
additional planned growth and integrity investments in our Gas utilities, primarily as a result of gaining further knowledge of the SourceGas utilities.

Weschedules. Our third party resources continue to evaluate potential future acquisitions and other growth opportunities when they arise. Assupport our business plans without disruption. Contingency plans are ready to be executed if significant disruption to supply chain occurs; however, we currently do not anticipate a result,significant impact from COVID-19 on our capital expenditures may vary significantly from the estimates identified above.investment plan for 2020.


Contractual Obligations


There have been no significant changes in contractual obligations from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 20162019 Annual Report on Form 10-K except for thosethe items described in Note 1613 of the Notes to Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report on Form 10-Q.


GuaranteesOff-Balance Sheet Commitments


There have been no significant changes to guaranteesoff-balance sheet commitments from those previously disclosed in Item 7 of our 2019 Annual Report on Form 10-K filed with the SEC except for the items described in Note 207 of the Notes to theCondensed Consolidated Financial Statements in our 2016 Annualthis Quarterly Report on Form 10-K.10-Q.


New Accounting Pronouncements


Other than the pronouncements reported in our 20162019 Annual Report on Form 10-K filed with the SEC and those discussed in Note 1 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements that are expected to have a material effect on our financial position, results of operations, or cash flows.




58


FORWARD-LOOKING INFORMATION


This Quarterly Report on Form 10-Q 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 2 - Management’s Discussion &and Analysis of Financial Condition and Results of Operations.


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


Any forward-looking statement contained in this document speaks only as of the date on which the statement was made, and themade. 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 was made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, such as the COVID-19 pandemic, 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 described in our 20162019 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our 20162019 Annual Report on Form 10-K, Part II, Item 1A of this Quarterly Report on Form 10-Q and other reports that we file with the SEC from time to time.





ITEM 3.
ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


Utilities

Our utility customers are exposed to natural gas price volatility. Therefore, as allowed or required by state utility commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, optionsInformation regarding our quantitative and basis swaps to reduce our customers’ underlying exposure to these fluctuations. The fair valuequalitative disclosures about market risk is disclosed in Item 7A of our Utilities Group’s derivative contracts is summarized below (in thousands) as of:
 September 30, 2017 December 31, 2016 September 30, 2016
Net derivative (liabilities) assets$(6,541) $(4,733) $(10,800)
Cash collateral offset in Derivatives5,452
 7,882
 11,584
Cash collateral included in Other current assets2,841
 4,840
 4,602
Net asset (liability) position$1,752
 $7,989
 $5,386

Annual Report on Form 10-K. See
Oil and Gas Activities

We have entered into agreements to hedge a portion of our estimated 2017 and 2018 natural gas and crude oil production from the Oil and Gas segment. The hedge agreements in place at September 30, 2017, were as follows:

Natural Gas
 March 31June 30September 30December 31Total Year
2017     
Swaps - MMBtu


540,000
540,000
Weighted Average Price per MMBtu$
$
$
$3.04
$3.04

Crude Oil
 March 31June 30September 30December 31Total Year
2017     
Swaps - Bbls


18,000
18,000
Weighted Average Price per Bbl$
$
$
$52.33
$52.33
      
Calls - Bbls


9,000
9,000
Weighted Average Price per Bbl$
$
$
$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 is summarized below (in thousands) as of:

 September 30, 2017 December 31, 2016 September 30, 2016
Net derivative (liabilities) assets$110
 $(1,433) $2,177
Cash collateral offset in Derivatives544
 2,733
 
Net asset (liability) position$654
 $1,300
 $2,177



Financing Activities

We engage in activities to manage risks associated with changes in interest rates. Historically, we have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations and anticipated long-term refinancings. Further details of the swap agreements are set forth in Note 9 of the Notes to Consolidated Financial Statements in our 2016 Annual Report on Form 10-K and in Note 10 of the Notes to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.for updates to market risks during the nine months ended September 30, 2020.


The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of:
 September 30, 2017 December 31, 2016 September 30, 2016
 Designated 
Interest Rate
Swaps
 
Designated
Interest Rate
Swap
 (a)
 
Designated
Interest Rate
Swaps
(a)
Notional$
 $50,000
 $75,000
Weighted average fixed interest rate% 4.94% 4.97%
Maximum terms in months0
 1
 4
Derivative assets, non-current$
 $
 $
Derivative liabilities, current$
 $90
 $654
Derivative liabilities, non-current$
 $
 $
Pre-tax accumulated other comprehensive income (loss)$
 $(90) $(654)
__________
(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.


ITEM 4.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)1934, as amended (the “Exchange Act”)) as of September 30, 2017.2020. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at September 30, 2017.2020.


Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Security Exchange Act of 1934, as amended, is recorded, processed, summarized and reported, within the time periods specified in the Commission’sSEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.


Changes in Internal Control over Financial Reporting


During the quarter ended September 30, 2017,2020, there have been no changes in our internal controlcontrols over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. Although we have altered some work routines due to the COVID-19 pandemic, the changes in our work environment (i.e. remote work arrangements) have not materially impacted our internal controls over financial reporting and have not adversely affected the Company’s ability to maintain operations, including financial reporting systems, ICFR, and disclosure controls and procedures.






59
BLACK HILLS CORPORATION


Part II — Other InformationPART II.    OTHER INFORMATION



ITEM 1.Legal Proceedings

ITEM 1.LEGAL PROCEEDINGS

For information regarding legal proceedings, see Note 19 in Item 8 of our 20162019 Annual Report on Form 10-K and Note 1613 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 1613 is incorporated by reference into this item.


ITEM 1A.Risk Factors

ITEM 1A.RISK FACTORS

There are no material changes to the risk factors previously disclosed in Item 1A of Part I in our 20162019 Annual Report on Form 10-K filed with the SEC except those statedas shown below:


While we plan to sell Black Hills Exploration and Production, Inc. (”BHEP”), our oil and gas explorationOur business, and we have initiated a sales process and retained advisors to facilitate the process, there is no assurance that we can complete the transaction or recognize any particular levelresults of proceeds.

We plan to divest all of our oil and gas assets and fully exit our oil and gas business. Such a divestiture and exit is subject to various risks, including: suitable purchasers may not be available or willing to purchase the assets on terms and conditions reasonable to us or may only be interested in acquiring a portion of the assets; we may incur substantial costs in connection with the marketing and sale of the assets; uncertainties associated with the sale may cause a loss of key management personnel at BHEP which could make it more difficult to sell the assets or operate the business in the event that we are unable to sell it; and we may be required to record an additional impairment charge that could have an adverse effect on ouroperations, financial condition and resultscash flows could be adversely affected by the recent coronavirus (COVID-19) pandemic.

We have responded to the global pandemic of operations.COVID-19 by taking steps to mitigate the potential risks to us posed by its spread.


ITEM 2.Unregistered Sales of Equity Securities and Use of Proceeds

There were no unregistered securities sold duringFor the nine months ended September 30, 2017.2020, the COVID-19 pandemic had a limited financial impact on our business, operations, financial condition and cash flows. In particular, we experienced:

Increased allowance for credit losses and bad debt expense due to anticipated customer non-payment as a result of suspended disconnections;
Increased costs due to sequestration of mission-critical and essential employees;
Lower commercial and certain transport volumes partially offset by higher electric and natural gas residential usage;
Reduced availability of our employees;
Increased costs for personal protection equipment and cleaning supplies;
Limited cash flow impacts from delayed payments from residential, commercial and industrial customers;
Minimal disruptions receiving the materials and supplies necessary to maintain operations and continue executing our capital investment plan;
Minimal impacts to the availability of our third-party resources;
Minimal decline in the funded status of our pension plan;
Minimal interest expense increase due to disruptions in the Commercial Paper markets; and
Reduced training, travel, employee, outside services and employee related expenses.

Should the COVID-19 pandemic continue for a prolonged period or impact the areas we serve more significantly than it has to date, our business, operations, financial condition and cash flows could be impacted in more significant ways. In addition to exacerbating the impacts described above, we could experience:

Adverse impacts on our strategic business plans, growth strategy and capital investment plans;
Increased adverse impacts to electricity and natural gas demand from our customers, particularly from commercial and industrial customers;
Further reduction in the availability of our employees and third-party resources;
Increased costs as a result of our emergency measures;
Increased allowance for credit losses and bad debt expense as a result of delayed or non-payment from our customers, both of which could be magnified by Federal or state government legislation that requires us to extend suspensions of disconnections for non-payment;
Delays and disruptions in the availability, timely delivery and cost of materials and components used in our operations;
Disruptions in the commercial operation dates of certain projects impacting qualification criteria for certain tax credits and triggering potential damages under our power purchase agreements;
Deterioration of the credit quality of our counterparties, including gas commodity contract counterparties, power purchase agreement counterparties, contractors or retail customers, that could result in credit losses;
Impairment of goodwill or long-lived assets;
Adverse impacts on our ability to develop, construct and operate facilities;
Inability to meet the requirements of the covenants in our existing credit facilities, including covenants regarding Consolidated Indebtedness to Capitalization Ratio;
Deterioration in our financial metrics or the business environment that adversely impacts our credit ratings;
60


Delay in the permitting process of certain development projects, affecting the timing of final investment decisions and start dates of construction;

Adverse impact on our liquidity position and cost of and ability to access funds from financial institutions and capital markets;
Delays in our ability to change rates through regulatory proceedings; and
Other risks that impact us, such as the risks described in the “Risk Factors” section of our 2019 Annual Report on Form 10-K and our ability to meet our financial obligations.

To date, we have experienced limited impacts to our results of operations, financial condition, cash flows or business plans. However, the situation remains fluid and it is difficult to predict with certainty the potential impact of COVID-19 on our business, results of operations, financial condition and cash flows.

ITEM 4.Mine Safety Disclosures

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 Quarterly Report on Form 10-Q.


ITEM 5.Other Information

None.


ITEM 6.    EXHIBITS
ITEM 6.Exhibit NumberExhibitsDescription

Exhibit NumberDescription
Exhibit 2.1*
Exhibit 2.2*
Exhibit 2.3*
Exhibit 3.1*
Exhibit 3.2*
Exhibit 4.1*
Exhibit 4.2*
61




Exhibit 4.5*4.4*
Exhibit 4.6*
Exhibit 4.7*
Exhibit 10.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2
Exhibit 95
Exhibit 101Financial Statements for XBRL Format.
__________
*101.INSPreviously filed as part ofXBRL Instance Document - the filing indicated and incorporated by reference herein.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
104Indicates a board of director or management compensatory plan.Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)


__________
*    Previously filed as part of the filing indicated and incorporated by reference herein.

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SIGNATURES




Pursuant to the requirements 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
/s/ Linden R. Evans
Linden R. Evans, President and
  Chief Executive Officer
/s/ David R. Emery
David R. Emery, Chairman and
  Chief Executive Officer
/s/ Richard W. Kinzley
Richard W. Kinzley, Senior Vice President and
  Chief Financial Officer
Dated:November 3, 20172020



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