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
☒ QUARTERLY 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
For the quarterly period ended March 31, 2021
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 Filer☐Smaller 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 April 30, 2021
Common stock, $1.00 par value62,871,727 shares

Table of Contents

TABLE OF CONTENTS
Page
4
Forward-Looking Information
7
Item 1.
8
Condensed Consolidated Statements of Income
8
Condensed Consolidated Statements of Comprehensive Income
9
Condensed Consolidated Balance Sheets
10
Condensed Consolidated Statements of Cash Flows
12
Condensed Consolidated Statements of Equity
13
Notes to Condensed Consolidated Financial Statements
14
Note 1. Management’s Statement
14
Note 2. Regulatory Matters
15
Note 3. Commitments, Contingencies and Guarantees
17
Note 4. Revenue
18
Note 5. Financing
19
Note 6. Earnings Per Share
20
Note 7. Risk Management and Derivatives
20
Note 8. Fair Value Measurements
23
Note 9. Other Comprehensive Income
25
Note 10. Employee Benefit Plans
26
Note 11. Income Taxes
27
Note 12. Business Segment Information
28
Note 13. Selected Balance Sheet Information
29
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
6
Item 1.Financial Statements
6
Condensed Consolidated Statements of Income - unaudited
   Three and Nine Months Ended September 30, 2017 and 2016
6
Condensed Consolidated Statements of Comprehensive Income - unaudited
   Three and Nine Months Ended September 30, 2017 and 2016
7
Condensed Consolidated Balance Sheets - unaudited
   September 30, 2017, December 31, 2016 and September 30, 2016
8
Condensed Consolidated Statements of Cash Flows - unaudited
   Nine Months Ended September 30, 2017 and 2016
10
Notes to Condensed Consolidated Financial Statements - unaudited
11
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations
4030
Executive Summary
30
Recent Developments
30
Results of Operations - Consolidated Summary and Overview
32
Non-GAAP Financial Measure
33
Electric Utilities
33
Gas Utilities
36
Regulatory Matters
38
Power Generation
39
Mining
40
Corporate and Other
41
Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax Benefit (Expense)
41
Liquidity and Capital Resources
42
Cash Flow Activities
42
Capital Sources
43
Credit Ratings
43
Capital Requirements
44
Critical Accounting Policies Involving Significant Estimates
45
New Accounting Pronouncements
45
Item 3.
7445
Item 4.
7546
OTHER INFORMATION
76
Item 1.
7646
Item 1A.
7646
Item 2.
7646
Item 4.
7646
Item 5.Other Information6.
46
Item 6.Exhibits
7748
Signatures
79




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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 to our Oil and Gas subsidiary, 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 prices and a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties.
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.
CIACChief Operating Decision Maker (CODM)Contribution In Aid of ConstructionChief Executive Officer
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 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 designedThe 52.5 MW wind farm near Cheyenne, Wyoming, jointly owned by South Dakota Electric and Wyoming Electric, serving as the dedicated wind energy supply to provide long-term natural gas price stabilitythe Renewable Ready program.
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
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CVACredit Valuation Adjustment
Dodd-FrankDodd-Frank Wall Street Reform and Consumer Protection Act
DSMDemand Side Management
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.
Iowa GasBlack Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Iowa (doing business as Black Hills Energy).
IPPIndependent power producer
IRSUnited States Internal Revenue Service


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
McfeMMBtuThousand cubic feet equivalent
MMBtuMillion British thermal units
Moody’s
Moody’sMoody’s Investors Service, Inc.
MRPMeter Relocation Program
MWMegawatts
MWhMegawatt-hours
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)
NGLNOLNatural Gas Liquids (1 barrel equals 6 Mcfe)
NOLNet Operating Loss
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
OCIOther Comprehensive Income
PPAPower Purchase Agreement
PSAPower Sales Agreement
Pueblo Airport GenerationThe 420 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.
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 HoldingsAppliance protection plan that provides 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
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TCATCJATransmission Cost Adjustment -- adjustments passed throughTax Cuts and Jobs Act
UtilitiesBlack Hills’ Electric and Gas Utilities
Wind Capacity FactorMeasures the amount of electricity a wind turbine produces in a given time period relative to the customer based on transmission costsits maximum potential
Winter Storm UriFebruary 2021 winter weather event that are higher or lower than the costs approvedcaused extremely cold temperatures in the rate case.central United States and led to unprecedented fluctuations in customer demand and market pricing for natural gas and energy.
VIEVariable interest entity
Winter Storm AtlasWRDCAn October 2013 blizzard that impacted South Dakota Electric. It was the second most severe blizzard in Rapid City’s history.
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. Black Hills Wyoming owns 76.5% of the facility and Municipal Energy Agency of Nebraska (MEAN) owns the remaining 23.5%.
Wyodak PlantWyodak, aThe 362 MW mine-mouth, coal-fired plant ingeneration facility near Gillette, Wyoming, isjointly owned 80% by PacificorpPacifiCorp (80%) and 20% by Black Hills Energy South Dakota.Dakota Electric (20%). Our WRDC mine supplies all of the fuel for the plant.facility.
Wyoming 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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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 & 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 the statement was made. 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 or Winter Storm Uri, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements described in our 2020 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our 2020 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.


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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,		(unaudited)Three Months Ended March 31,
201720162017201620212020
(in thousands, except per share amounts)(in thousands, except per share amounts)
 
Revenue$342,138
$333,786
$1,244,119
$1,109,186
Revenue$633,432 $537,050 
 
Operating expenses: Operating expenses:
Fuel, purchased power and cost of natural gas sold86,281
80,194
404,222
336,539
Fuel, purchased power and cost of natural gas sold293,147 187,879 
Operations and maintenance114,648
115,103
354,152
334,706
Operations and maintenance129,679 125,466 
Depreciation, depletion and amortization49,434
48,925
146,744
140,637
Depreciation, depletion and amortization57,269 56,402 
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
Taxes - property and productionTaxes - property and production15,022 14,118 
Total operating expenses263,619
275,377
949,223
941,889
Total operating expenses495,117 383,865 
 
Operating income78,519
58,409
294,896
167,297
Operating income138,315 153,185 
 
Other income (expense): 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 expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)(37,825)(35,781)
Interest income402
912
700
2,513
Interest income225 328 
Allowance for funds used during construction - equity696
1,211
1,982
2,900
Impairment of investmentImpairment of investment0 (6,859)
Other income (expense), net189
160
29
801
Other income (expense), net266 2,353 
Total other income (expense), net(33,116)(33,881)(100,279)(94,875)
Total other income (expense)Total other income (expense)(37,334)(39,959)
 
Income before income taxes45,403
24,528
194,617
72,422
Income before income taxes100,981 113,226 
Income tax benefit (expense)(13,805)(6,644)(57,562)(11,205)
Income tax (expense)Income tax (expense)(494)(16,002)
Net income31,598
17,884
137,055
61,217
Net income100,487 97,224 
Net income attributable to noncontrolling interest(3,935)(3,753)(10,674)(6,415)Net income attributable to noncontrolling interest(4,171)(4,050)
Net income available for common stock$27,663
$14,131
$126,381
$54,802
Net income available for common stock$96,316 $93,174 
 
Earnings per share of common stock: Earnings per share of common stock:
Earnings per share, Basic$0.52
$0.27
$2.38
$1.06
Earnings per share, Basic$1.54 $1.51 
Earnings per share, Diluted$0.50
$0.26
$2.29
$1.04
Earnings per share, Diluted$1.54 $1.51 
Weighted average common shares outstanding: Weighted average common shares outstanding:
Basic53,243
52,184
53,208
51,583
Basic62,633 61,778 
Diluted55,432
53,733
55,254
52,893
Diluted62,691 61,856 
 
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
March 31,
20212020
(in thousands)
Net income$100,487 $97,224 
Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (net of tax of $0 and $(17), respectively)0 55 
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $9 and $7, respectively)(16)(23)
Reclassification adjustments of benefit plan liability - net loss (net of tax of $(217) and $(95), respectively)381 502 
Derivative instruments designated as cash flow hedges:
Reclassification of net realized losses on settled/amortized interest rate swaps (net of tax of $(190) and $(170), respectively)523 543 
Net unrealized gains (losses) on commodity derivatives (net of tax of $(35) and $54, respectively)107 (175)
Reclassification of net realized losses on settled commodity derivatives (net of tax of $(8) and $(115), respectively)23 371 
Other comprehensive income, net of tax1,018 1,273 
Comprehensive income101,505 98,497 
Less: comprehensive income attributable to noncontrolling interest(4,171)(4,050)
Comprehensive income available for common stock$97,334 $94,447 
(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 139 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
March 31, 2021December 31, 2020
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents$13,442 $6,356 
Restricted cash and equivalents4,483 4,383 
Accounts receivable, net282,382 265,961 
Materials, supplies and fuel102,603 117,400 
Derivative assets, current1,917 1,848 
Income tax receivable, net18,115 19,446 
Regulatory assets, current129,951 51,676 
Other current assets25,722 26,221 
Total current assets578,615 493,291 
Property, plant and equipment7,415,818 7,305,530 
Less: accumulated depreciation and depletion(1,320,525)(1,285,816)
Total property, plant and equipment, net6,095,293 6,019,714 
Other assets:
Goodwill1,299,454 1,299,454 
Intangible assets, net11,649 11,944 
Regulatory assets, non-current672,306 226,582 
Other assets, non-current38,882 37,801 
Total other assets, non-current2,022,291 1,575,781 
TOTAL ASSETS$8,696,199 $8,088,786 
(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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Table of Contents

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
(unaudited)As of
March 31, 2021December 31, 2020
(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable$160,179 $183,340 
Accrued liabilities230,444 243,612 
Derivative liabilities, current2,526 2,044 
Regulatory liabilities, current13,580 25,061 
Notes payable815,870 234,040 
Current maturities of long-term debt7,000 8,436 
Total current liabilities1,229,599 696,533 
Long-term debt, net of current maturities3,529,158 3,528,100 
Deferred credits and other liabilities:
Deferred income tax liabilities, net428,127 408,624 
Regulatory liabilities, non-current497,810 507,659 
Benefit plan liabilities150,979 150,556 
Other deferred credits and other liabilities135,224 134,667 
Total deferred credits and other liabilities1,212,140 1,201,506 
Commitments, contingencies and guarantees (Note 3)
00
Equity:
Stockholders’ equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 62,909,973 and 62,827,179 shares, respectively62,910 62,827 
Additional paid-in capital1,658,957 1,657,285 
Retained earnings931,538 870,738 
Treasury stock, at cost – 39,940 and 32,492 shares, respectively(2,564)(2,119)
Accumulated other comprehensive income (loss)(26,328)(27,346)
Total stockholders’ equity2,624,513 2,561,385 
Noncontrolling interest100,789 101,262 
Total equity2,725,302 2,662,647 
TOTAL LIABILITIES AND TOTAL EQUITY$8,696,199 $8,088,786 
(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,
 20172016
Operating activities:(in thousands)
Net income$137,055
$54,802
Adjustments to reconcile net income to net cash provided by operating activities:  
Depreciation, depletion and amortization146,744
140,637
Deferred financing cost amortization6,212
4,002
Impairment of long-lived assets—
52,286
Derivative fair value adjustments1,931
(7,308)
Stock compensation7,594
9,124
Deferred income taxes64,672
38,578
Employee benefit plans8,470
11,830
Other adjustments, net(5,550)(2,076)
Changes in certain operating assets and liabilities:  
Materials, supplies and fuel(19,560)(5,166)
Accounts receivable, unbilled revenues and other operating assets107,026
78,869
Accounts payable and other operating liabilities(101,471)(117,631)
Regulatory assets - current1,287
8,453
Regulatory liabilities - current(4,328)(8,181)
Contributions to defined benefit pension plans(27,700)(14,200)
Interest rate swap settlement—
(28,820)
Other operating activities, net(2,952)(5,998)
Net cash provided by (used in) operating activities319,430
209,201
   
Investing activities:  
Property, plant and equipment additions(256,138)(334,098)
Acquisition, net of long term debt assumed—
(1,124,238)
Other investing activities(250)(860)
Net cash provided by (used in) investing activities(256,388)(1,459,196)
   
Financing activities:  
Dividends paid on common stock(71,334)(65,247)
Common stock issued3,562
107,690
Sale of noncontrolling interest—
216,370
Net (payments) borrowings of short-term debt128,570
(1,800)
Long-term debt - issuances—
1,767,608
Long-term debt - repayments(104,307)(1,162,872)
Distributions to noncontrolling interest(12,884)(4,516)
Other financing activities(6,719)(16,285)
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


(unaudited)Three Months Ended March 31,
20212020
Operating activities:(in thousands)
Net income$100,487 $97,224 
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization57,269 56,402 
Deferred financing cost amortization2,214 2,237 
Impairment of investment0 6,859 
Stock compensation3,257 291 
Deferred income taxes153 21,876 
Employee benefit plans2,304 1,235 
Other adjustments, net6,151 892 
Changes in certain operating assets and liabilities:
Materials, supplies and fuel15,932 19,222 
Accounts receivable and other current assets(11,599)8,171 
Accounts payable and other current liabilities(23,602)(43,297)
Regulatory assets(533,006)20,679 
Regulatory liabilities(5,291)1,316 
Other operating activities, net(355)(1,138)
Net cash provided by (used in) operating activities(386,086)191,969 
Investing activities:
Property, plant and equipment additions(146,302)(171,882)
Other investing activities78 (1,202)
Net cash (used in) investing activities(146,224)(173,084)
Financing activities:
Dividends paid on common stock(35,514)(32,902)
Common stock issued0 99,321 
Term loan - borrowings800,000 0 
Term loan - repayments(200,000)0 
Net (payments) borrowings of Revolving Credit Facility and CP Program(18,170)(30,375)
Long-term debt - repayments(1,436)(4,291)
Distributions to noncontrolling interest(4,644)(4,741)
Other financing activities(740)(1,391)
Net cash provided by financing activities539,496 25,621 
Net change in cash, restricted cash and cash equivalents7,186 44,506 
Cash, restricted cash and cash equivalents at beginning of period10,739 13,658 
Cash, restricted cash and cash equivalents at end of period$17,925 $58,164 
Supplemental cash flow information:
Cash (paid) refunded during the period:
Interest, net of amounts capitalized$(21,232)$(21,776)
Income taxes990 0 
Non-cash investing and financing activities:
Accrued property, plant and equipment purchases at March 3151,914 53,011 
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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Table of Contents

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, 202062,827,179 $62,827 32,492 $(2,119)$1,657,285 $870,738 $(27,346)$101,262 $2,662,647 
Net income— — — — — 96,316 — 4,171 100,487 
Other comprehensive income (loss), net of tax— — — — — — 1,018 — 1,018 
Dividends on common stock ($0.565 per share)— — — — — (35,514)— — (35,514)
Share-based compensation82,794 83 7,448 (445)1,672 — — — 1,310 
Other— — — — — (2)— — (2)
Distributions to noncontrolling interest— — — — — — — (4,644)(4,644)
March 31, 202162,909,973 $62,910 39,940 $(2,564)$1,658,957 $931,538 $(26,328)$100,789 $2,725,302 

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— — — — — 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 

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Table of Contents
BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 20162020 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 America 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 20162020 Annual Report on Form 10-K filed with the SEC.10-K.


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,March 31, 2021, December 31, 2016,2020 and September 30, 2016March 31, 2020 financial information and areinformation. Certain lines of a normal recurring nature. Certain industriesbusiness 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. 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 interim results of operations for the three and nine months ended September 30, 2017 and September 30, 2016, and our financial condition as of September 30, 2017, December 31, 2016, and September 30, 2016, are not necessarily indicative of the results of operations and financial condition to be expected for an entire year.

COVID-19 Pandemic

In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of or for any other period. September 30, 2017 reflectsthe United States declared the outbreak a full nine monthsnational emergency. The U.S. government has deemed the electric and natural gas utilities to be critical infrastructure sectors that provide essential services during this emergency. As a provider of activity fromessential services, the SourceGas AcquisitionCompany has an obligation to provide services to our customers. The Company remains focused on February 12, 2016, as compared toprotecting the nine months ended September 30, 2016health of our customers, employees and the communities in which reflects a partial periodwe operate while assuring the continuity of approximately 7.5 months. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.our business operations.

Revisions

Certain revisions have been made to prior years’ financial information to conform to the current year presentation.
The Company revised its presentationCompany’s Condensed Consolidated Financial Statements reflect estimates and assumptions made by management that affect the reported amounts of cash asassets and liabilities and disclosure 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 accountscontingent assets and liabilities at the same financial institution; therefore, book overdrafts are presented on a combined basis by bank as cash and cash equivalents. Prior year amounts were corrected to conform with the current year presentation, which decreased cash and cash equivalents and accounts payable by $31 million asdate 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 asFinancial Statements and reported amounts of September


30, 2016revenue and toexpenses during the Condensed Consolidated Statementsreporting periods presented. The Company considered the impacts of Cash FlowsCOVID-19 on the assumptions and estimates used and determined that for the ninethree months ended September 30, 2016. There isMarch 31, 2021, there were no impact tomaterial adverse impacts on the Condensed Consolidated StatementsCompany’s results of Income or the Condensed Consolidated Statements of Comprehensive Income for any period reported.operations.


Recently Issued Accounting Standards


Revenue from Contracts with Customers,Facilitation of the Effects of Reference Rate Reform on Financial Reporting, ASU 2014-092020-04


In May 2014,March 2020, the FASB issued ASU 2014-09, Revenue from Contracts with Customers.2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which was subsequently amended by ASU 2021-01. The standard provides relief for companies with a single modelpreparing for usediscontinuation of interest rates, such as LIBOR, and allows optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The amendments in accounting for revenue arising from contracts with customersthis update are elective and supersedes current revenue recognitionare effective upon the ASU issuance through December 31, 2022. We are currently evaluating whether we will apply the optional guidance including industry-specific revenue guidance. The core principleas we assess the impact of the model is to recognize revenue when controldiscontinuance of LIBOR on our current arrangements and 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 thepotential impact that adoption of the new standard will have on our financial position, results of operations and cash flows. A majority



14

Table 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 withContents
Recently Adopted Accounting Standards

Simplifying 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 recognitionAccounting 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.Income Taxes, ASU 2019-12


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

In March 2017,December 2019, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving2019-12, Simplifying the PresentationAccounting for Income Taxes as part of Net Periodic Pension Costits overall simplification initiative to reduce costs and Net Periodic Post-Retirement Benefit Cost. The changescomplexity in applying accounting standards while maintaining or improving the usefulness of the information provided to users of the financial statements. Amendments include removal of certain exceptions to the general principles of ASC 740, Income Taxes, and simplification in several other areas such as accounting for a franchise tax (or similar tax) that is partially based on income. We adopted this 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 appliedprospectively 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 impactJanuary 1, 2021. Adoption 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 willdid not have a materialan 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, 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, ASU 2016-09

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for forfeitures, income taxes, and statutory tax withholding requirements. The ASU was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. Certain amendments of this guidance are to be applied retrospectively and others prospectively. We implemented this ASU effective January 1, 2017, recording a cumulative-effect adjustment 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. Adoption of this ASU did not have a material impact on our consolidated financial position, results of operations or cash flows.


(2)    ACQUISITIONRegulatory Matters


2016 Acquisition 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 billion 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 Notes to the Consolidated Financial Statements in our 2016 Annual Report on Form 10-K for more details.

Pro Forma Results

The following unaudited pro forma financial information reflects the consolidated results of operations as if the SourceGas Acquisition had taken place on January 1, 2015. The unaudited pro forma financial information is presented for illustrative purposes only and is not necessarily indicative 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 results for the three and nine months ended September 30, 2016 exclude approximately $3.8 million and $23 million, respectively, of after-tax transaction costs, including professional fees, employee related expenses and other miscellaneous costs.

 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

Redemption of seller’s noncontrolling interest

As part of the SourceGas Transaction, a seller retained a 0.5% noncontrolling interest and we entered into an associated option agreement with 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.

(3)    BUSINESS SEGMENT INFORMATION

Segment information and Corporate activities included in the accompanying Condensed Consolidated Statements of Income were as follows (in thousands):
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, 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


       
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 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, 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.


(4)    ACCOUNTS RECEIVABLE

Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 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 had the following regulatory assets and liabilities (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
As ofAs of
March 31, 2021December 31, 2020
Regulatory assets
Winter Storm Uri (a)
$480,842 $0 
Deferred energy and fuel cost adjustments (a) (b)
68,402 39,035 
Deferred gas cost adjustments (a) (b)
17,066 3,200 
Gas price derivatives (b)
324 2,226 
Deferred taxes on AFUDC (c)
7,469 7,491 
Employee benefit plans and related deferred taxes (d)
117,886 116,598 
Environmental (b)
1,413 1,413 
Loss on reacquired debt (b)
22,386 22,864 
Deferred taxes on flow through accounting (d)
51,823 47,515 
Decommissioning costs (c)
7,827 8,988 
Gas supply contract termination (b)
1,013 2,524 
Other regulatory assets (b)
25,806 26,404 
Total regulatory assets802,257 278,258 
   Less current regulatory assets(129,951)(51,676)
Regulatory assets, non-current$672,306 $226,582 
Regulatory liabilities
Deferred energy and gas costs (b)
$426 $13,253 
Employee benefit plan costs and related deferred taxes (d)
40,471 40,256 
Cost of removal (b)
177,003 172,902 
Excess deferred income taxes (d)
271,492 285,259 
Other regulatory liabilities (d)
21,998 21,050 
Total regulatory liabilities511,390 532,720 
   Less current regulatory liabilities(13,580)(25,061)
Regulatory liabilities, non-current$497,810 $507,659 
__________
(a)    We are in discussions with our regulators regarding the timing of Winter Storm Uri incremental cost recovery. See further information below.
(b)    Recovery of costs, but we are not allowed a rate of return.
(c)    In addition to recovery of costs, we are allowed a rate of return.
(d)    In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base.

Regulatory Activity

Except as discussed below, there have been no other significant changes to our Regulatory Matters from those previously disclosed in Note 2 of the Notes to the Consolidated Financial Statements in our 2020 Annual Report on Form 10-K.
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Winter Storm Uri

In February 2021, a prolonged period of historic cold temperatures across the central United States, which covered all of our Utilities’ service territories, caused a significant increase in heating and energy demand and contributed to unforeseeable and unprecedented market prices for natural gas and electricity. As a result of Winter Storm Uri, our net pre-tax incremental fuel, purchased power and natural gas costs during the three months ended March 31, 2021 were approximately $571 million. This amount does not include potential pipeline transportation charges for certain suppliers who have requested and received approval from FERC to delay billings.

Our Utilities have regulatory mechanisms to recover approximately $559 million of incremental costs from Winter Storm Uri. However, given the extraordinary impact of these higher costs to our customers, our regulators are performing a heightened review. We are engaged with our regulators to identify appropriate periods over which to recover incremental costs with consideration of the impacts to our customers’ bills. We expect to recover most of the Winter Storm Uri incremental costs through a separately tracked regulatory mechanism but we also anticipate recovery of a portion of the costs through existing mechanisms.

For the three months ended March 31, 2021, we expensed $12.5 million of Winter Storm Uri net incremental costs as a result of negative impacts to our Utilities and financing costs partially offset by favorable impacts to our Power Generation segment. Our Electric Utilities incurred a $3.2 million negative impact to our regulated wholesale power margins due to higher fuel costs and $2.1 million of incremental fuel costs that are not recoverable through our fuel cost recovery mechanisms. Black Hills Energy Services offers fixed contract pricing for non-regulated gas supply services to our regulated natural gas customers and the $8.2 million increase in cost of natural gas sold during Winter Storm Uri is not recoverable through the regulatory construct. Additionally, we incurred $0.7 million of interest expense for the three months ended March 31, 2021, related to our $800 million term loan which is discussed in Note 5. Our non-regulated Power Generation segment benefited from a $1.7 million favorable impact to operating income from Winter Storm Uri.

Winter Storm Uri Costs by Jurisdiction

As of March 31, 2021, our estimate of incremental costs from Winter Storm Uri which was recorded to a regulatory asset is shown below by jurisdiction. This information is based on anticipated filings that we expect to complete in the second quarter of 2021 and is subject to adjustments as applications are submitted and final decisions are issued.

Costs by Jurisdiction(in thousands)
Gas Utilities:
Arkansas Gas$137,500 
Colorado Gas77,850 
Iowa Gas95,450 
Kansas Gas87,900 
Nebraska Gas79,750 
Wyoming Gas29,409 
Gas Utilities Total$507,859 
Electric Utilities:
Colorado Electric$25,500 
South Dakota Electric22,200 
Wyoming Electric3,266 
Electric Utilities Total$50,966 
Total Winter Storm Uri Incremental Costs Recorded to Regulatory Asset$558,825 
Costs by Regulatory Asset
Winter Storm Uri (a)
$480,842 
Deferred energy and fuel cost adjustments27,166 
Deferred gas cost adjustments (b)
50,817 
$558,825 
__________
(a)    We expect to recover most of the Winter Storm Uri incremental costs through a separately tracked regulatory mechanism but also expect to recover a portion through our existing mechanisms.
(b)    Incremental natural gas costs from Winter Storm Uri are reflected as an increase in the Deferred gas cost adjustments regulatory asset, net of existing Deferred energy and gas cost regulatory liabilities, for the three months ended March 31, 2021.
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TCJA

On December 30, 2020, an administrative law judge approved a settlement of Colorado Electric’s plan to provide $9.3 million of TCJA-related bill credits to its customers. The bill credits, which represent a disposition of excess deferred income tax benefits resulting from the TCJA, were delivered to customers in February 2021. These bill credits, which resulted in a reduction in revenue, were offset by a reduction in income tax expense and resulted in a minimal impact to Net Income for the three months ended March 31, 2021.

On January 26, 2021, the NPSC approved Nebraska Gas’s plan to provide $2.9 million of TCJA-related bill credits to its customers. The bill credits, which represent a disposition of excess deferred income tax benefits resulting from the TCJA, are expected to be delivered to customers in the second quarter of 2021. These bill credits, which will result in a reduction in revenue, will be offset by a reduction in income tax expense and will result in a minimal impact to Net income.

Colorado Gas

Rate Review

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. On January 6, 2021, the CPUC issued an Order dismissing the rate review. Colorado Gas plans to file a rate review in the second quarter of 2021.

On September 11, 2020, in accordance with the final order from the earlier rate review filed February 1, 2019, Colorado Gas filed a SSIR proposal with the CPUC that would recover safety and integrity focused investments in its system for five years. A decision from the CPUC is expected by mid-2021.

Nebraska Gas

Jurisdictional Consolidation and Rate Review

On January 26, 2021, Nebraska Gas received approval from the NPSC to consolidate rate schedules into a new, single statewide structure and recover infrastructure investments in its 13,000-mile natural gas pipeline system. Final rates were enacted on March 1, 2021, which replaced interim rates effective September 1, 2020. The approval shifted $4.6 million of SSIR revenue to base rates and is expected to generate $6.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and an authorized return on equity of 9.5%. The approval also includes an extension of the SSIR for five years and an expansion of this mechanism across the consolidated jurisdictions.


(3)    Commitments, Contingencies and Guarantees

There have been no significant changes to commitments, contingencies and guarantees from those previously disclosed in Note 3 of our Notes to the Consolidated Financial Statements in our 2020 Annual Report on Form 10-K except for those described below.

Power Purchase Agreement - Colorado Electric Renewable Advantage

On February 19, 2021, Colorado Electric entered into a PPA with TC Colorado Solar, LLC to purchase up to 200 MW of renewable energy upon construction of a new solar facility, to be owned by TC Colorado Solar, LLC, which is expected to be completed by the end of 2023. This agreement will expire 15 years after construction completion. The solar project represents Colorado Electric’s preferred bid in a competitive solicitation process completed in September 2020 through its Renewable Advantage plan.


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(4)    Revenue

Our revenue contracts generally provide for performance obligations that are: fulfilled and transfer control to customers over time; represent a series of distinct services that are substantially the same; involve the same pattern of transfer to the customer; and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice. The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reportable segments for the three months ended March 31, 2021 and 2020. Sales tax and other similar taxes are excluded from revenues.
(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 for these costs will increase annual amortization expense by approximately $2.7 million.


(6)    MATERIALS, SUPPLIES AND FUEL

The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 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


(7)    EARNINGS PER SHARE

A reconciliation of share amounts used to compute Earnings (loss) 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,
 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.

Three Months Ended March 31, 2021 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer types:(in thousands)
Retail$198,500 $341,605 $0 $14,083 $(7,107)$547,081 
Transportation0 47,951 0 0 (110)47,841 
Wholesale5,922 0 28,692 0 (24,451)10,163 
Market - off-system sales7,656 73 0 0 (2,884)4,845 
Transmission/Other15,193 10,390 0 0 (5,296)20,287 
Revenue from contracts with customers$227,271 $400,019 $28,692 $14,083 $(39,848)$630,217 
Other revenues137 2,500 471 589 (482)3,215 
Total revenues$227,408 $402,519 $29,163 $14,672 $(40,330)$633,432 
Timing of revenue recognition:
Services transferred at a point in time$0 $0 $0 $14,083 $(7,107)$6,976 
Services transferred over time227,271 400,019 28,692 0 (32,741)623,241 
Revenue from contracts with customers$227,271 $400,019 $28,692 $14,083 $(39,848)$630,217 

Three Months Ended March 31, 2020 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer Types:
Retail$148,640 $298,247 $0 $14,403 $(7,839)$453,451 
Transportation0 44,108 0 0 (139)43,969 
Wholesale5,552 0 25,467 0 (23,612)7,407 
Market - off-system sales4,867 138 0 0 (2,639)2,366 
Transmission/Other14,857 12,572 0 0 (4,413)23,016 
Revenue from contracts with customers$173,916 $355,065 $25,467 $14,403 $(38,642)$530,209 
Other revenues223 5,708 499 802 (391)6,841 
Total Revenues$174,139 $360,773 $25,966 $15,205 $(39,033)$537,050 
Timing of Revenue Recognition:
Services transferred at a point in time$0 $0 $0 $14,403 $(7,839)$6,564 
Services transferred over time173,916 355,065 25,467 0 (30,803)523,645 
Revenue from contracts with customers$173,916 $355,065 $25,467 $14,403 $(38,642)$530,209 

Contract Balances

The following outstanding securities were excludednature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands):our Accounts Receivable further discussed in Note 13.

18

 Three Months Ended September 30, Nine Months Ended September 30,
 20172016 20172016
      
Equity compensation—
2
 —
4
Anti-dilutive shares—
2
 —
4
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(5)    Financing


(8)    NOTES PAYABLE AND LONG-TERM DEBTShort-term debt


We had the following notesNotes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
March 31, 2021December 31, 2020
Balance Outstanding
Letters of Credit (a)
Balance Outstanding
Letters of Credit (a)
Term Loan$600,000 $0 $0 $0 
Revolving Credit Facility0 16,629 0 24,730 
CP Program215,870 0 234,040 0 
Total Notes payable$815,870 $16,629 $234,040 $24,730 
_______________
 September 30, 2017December 31, 2016September 30, 2016
 Balance OutstandingLetters of CreditBalance OutstandingLetters of CreditBalance OutstandingLetters of Credit
Revolving Credit Facility$—
$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.


Term Loan

On February 24, 2021, we entered into a nine-month, $800 million unsecured term loan to provide additional liquidity and meet our cash needs related to the incremental fuel, purchased power and natural gas costs from Winter Storm Uri. The term loan, which matures on November 24, 2021, has an interest rate based on LIBOR plus 75 basis points, carries 0 prepayment penalty and is subject to the same covenant requirements as our Revolving Credit Facility. We repaid $200 million of this term loan in the first quarter of 2021. The interest rate on term loan borrowings on March 31, 2021 was 0.86%.

We expect to refinance a portion of the term loan with longer-term debt prior to maturity. In the event we are unable to refinance the remaining obligation, we believe it is probable that our current plans to manage liquidity would be sufficient to meet our obligations.

Revolving Credit Facility and CP Program


On August 9, 2016, we amended and restatedOur net short-term borrowings related to 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. Our net amount borrowed under the CP Program during the ninethree months ended September 30, 2017 and our notes outstanding as of September 30, 2017 were $225March 31, 2021 decreased by $18 million. As of September 30, 2017, theThe weighted average interest rate on CP Programshort-term borrowings was 1.46%.

Debt Covenants

On December 7, 2016, we amendedrelated to our Revolving Credit Facility and term loan agreements, allowing the exclusion of the Remarketable Junior Subordinated Notes (RSNs) fromCP Program at March 31, 2021 was 0.23%.

Debt Covenants

Under our Consolidated Indebtedness to Capitalization Ratio covenant calculation. Under the amended and restated Revolving Credit Facility and term loan agreements, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Our Consolidated 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 March 31, 2021:

As of March 31, 2021Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio62.6%Less than65%
Long-Term Debt


On May 16, 2017, we paid down $50 million on our Corporate term loan due August 9, 2019. On July 17, 2017, we paid down an additional $50 million on the same term loan. Short-term borrowings from our CP program were
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(6)    Earnings Per Share

A reconciliation of share amounts used to fund the payments on the Corporate term loan.


(9)    EQUITY

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, 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. The renewed program, which allows us to sell shares of our common stock, is the same as the prior year program other than the aggregate value increased from $200 million to $300 million. The shares may be offered from time to time pursuant to a sales agreement dated August 4, 2017. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. We did not issue any common shares during the nine months ended September 30, 2017 under the ATM equity offering program. During the three months ended September 30, 2016, we sold 819,442 shares of common stock for $49 million, net of $0.5 million in commissions, under the ATM equity offering program. During the nine months ended September 30, 2016, we sold and issued under the ATM equity offering program an aggregate of 1,750,091 shares of common stock, with settlement dates through September 30, 2016, for $106 million, net of $1.1 million in commissions.

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 reportedcompute earnings per share in the equity sectionaccompanying Condensed Consolidated Statements of a company’s balance sheet. Distributions of net income attributable to the noncontrolling interest are due within 30 daysIncome was as follows (in thousands):
Three Months Ended March 31,
20212020
Net income available for common stock$96,316 $93,174 
Weighted average shares - basic62,633 61,778 
Dilutive effect of:
Equity compensation58 78 
Weighted average shares - diluted62,691 61,856 
Earnings per share of common stock:
Earnings per share, Basic$1.54 $1.51 
Earnings per share, Diluted$1.54 $1.51 

The 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 supportsecurities were excluded from the Company outsidediluted earnings per share computation because of pre-existing contractual arrangements during the reporting period. Black Hills Colorado IPP does not have any debttheir anti-dilutive nature (in thousands):
Three Months Ended March 31,
20212020
Equity compensation14 12 
Restricted stock19 26 
Anti-dilutive shares33 38 


(7)    Risk Management and its cash flows from operations are sufficient to support its ongoing operations.Derivatives


We have recorded the following assetsMarket and liabilities on our consolidated balance sheets related to the VIE described above as of:Credit Risk Disclosures

 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



(10)    RISK MANAGEMENT ACTIVITIES

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 and natural gas reserves and production, our retail natural gas and wholesale electric power marketing activities, andas well as our fuel procurement for certainseveral of our gas-fired generation assets.assets, which include market fluctuations due to unpredictable factors such as Winter Storm Uri, 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.


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


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 118.

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’ generationgenerating facilities plants or those plantsfacilities under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to volatility in natural gas prices.price volatility. Therefore, as allowed or required by state utilityregulatory commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, options, over-the-counter swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP.


For our regulated utilities’Utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Condensed Consolidated Balance Sheets in accordance with the state regulatory commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Condensed Consolidated Statements of Income.


We periodically use wholesale power purchase and sale contracts to manage purchased power costs and load requirements associated with serving our electric customers that are considered derivative instruments due to not qualifying for the normal purchases and normal sales exception to derivative accounting. Changes in the fair value of these commodity derivatives are 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/orand sales during time frames ranging from October 2017April 2021 through December 2020.August 2023. 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 Utilities 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, 2016March 31, 2021December 31, 2020
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 purchasedMMBtus0 0620,000 3
Natural gas options purchased, net7,360,000
 17 3,020,000
 5 6,540,000
 17Natural gas options purchased, netMMBtus0 03,160,000 3
Natural gas basis swaps purchased9,170,000
 39 12,250,000
 48 13,650,000
 51Natural gas basis swaps purchasedMMBtus0 0900,000 3
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)
MMBtus3,590,000 293,850,000 17
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)
MMBtus3,107,817 1217,513,061 22
Electric wholesale contracts (c)
Electric wholesale contracts (c)
MWh183,025 9219,000 12
__________
(a)
(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.

Based on September 30, 2017 prices,(b)    As of March 31, 2021, 442,900 MMBtus of natural gas over-the-counter swaps purchases were designated as cash flow hedges.
(c)    Volumes exclude derivative contracts that qualify for the normal purchases and normal sales exception permitted by GAAP.

We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a $0.3 million loss 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 millionnegotiated line of unsecured ten-year senior notes on August 10, 2016. The effective portion ofcredit. At March 31, 2021, 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 $1.0Company posted $1.4 million related to the timing of the debt issuance, was recognizedsuch provisions, which is included 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 reflectedOther current assets on the Condensed Consolidated Balance Sheets were as follows (dollarsSheets.

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Derivatives by Balance Sheet Classification

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

The following table presents the fair value and balance sheet classification of our derivative instruments (in thousands) as of:
Balance Sheet LocationMarch 31, 2021December 31, 2020
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivativesDerivative assets, current$285 $181 
Noncurrent commodity derivativesOther assets, non-current4 43 
Liability derivative instruments:
Current commodity derivativesDerivative liabilities, current0 (108)
Noncurrent commodity derivativesOther deferred credits and other liabilities0 0 
Total derivatives designated as hedges$289 $116 
Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivativesDerivative assets, current$1,632 $1,667 
Noncurrent commodity derivativesOther assets, non-current32 151 
Liability derivative instruments:
Current commodity derivativesDerivative liabilities, current(2,526)(1,936)
Noncurrent commodity derivativesOther deferred credits and other liabilities(43)0 
Total derivatives not designated as hedges$(905)$(118)
 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.

Derivatives Designated as Hedge Instruments




Cash Flow Hedges

The impacts of cash flow hedges on our Condensed Consolidated Statements of Comprehensive Income isand Condensed Consolidated Statements of Income are presented below for the three and nine months ended September 30, 2017March 31, 2021 and 2016 (in thousands).2020. 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 March 31,Three Months Ended March 31,
2021202020212020
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$713 $713 Interest expense$(713)$(713)
Commodity derivatives173 257 Fuel, purchased power and cost of natural gas sold(31)(486)
Total$886 $970 $(744)$(1,199)

As of March 31, 2021, $0.9 million of net losses related to our interest rate swaps and commodity derivatives are expected to be reclassified from AOCI into earnings within the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

22

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)   $—

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 componentTable 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.Contents
 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 Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2017March 31, 2021 and 2016 (in thousands).2020. 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,
  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) $(342)
Three Months Ended March 31,
20212020
Derivatives Not Designated as Hedging InstrumentsIncome Statement LocationAmount of Gain/(Loss) on Derivatives Recognized in Income
(in thousands)
Commodity derivatives - ElectricFuel, purchased power and cost of natural gas sold$(1,524)$1,362 
Commodity derivatives - Natural GasFuel, purchased power and cost of natural gas sold366 766 
$(1,158)$2,128 

  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 utilitiesGas Utilities are not designated as cash flow hedges. However, thereThere is no earnings impact 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 related to the hedges in our Gas Utilities were $11 million, $8.8$0.3 million and $14$2.2 million at September 30, 2017,as of March 31, 2021 and December 31, 20162020, 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.







(8)    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.

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.

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
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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 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 ratingadditional information, see Note 1 of our counterparty.Notes to the Consolidated Financial Statements in our 2020 Annual Report on Form 10-K.

As of March 31, 2021
Level 1Level 2Level 3Cash Collateral and Counterparty
Netting		Total
(in thousands)
Assets:
Commodity derivatives — Gas Utilities$0 $1,389 $0 $0 $1,389 
Commodity derivatives — Electric Utilities$0 $564 $0 $0 $564 
Total$0 $1,953 $0 $0 $1,953 
Liabilities:
Commodity derivatives — Gas Utilities$0 $625 $0 $0 $625 
Commodity derivatives — Electric Utilities$0 $1,944 $0 $0 $1,944 
Total$0 $2,569 $0 $0 $2,569 



As of December 31, 2020
Level 1Level 2Level 3Cash Collateral and Counterparty
Netting		Total
(in thousands)
Assets:
Commodity derivatives — Gas Utilities$0 $2,504 $0 $(1,527)$977 
Commodity derivatives — Electric Utilities$0 $1,065 $0 $0 $1,065 
Total$0 $3,569 $0 $(1,527)$2,042 
Liabilities:
Commodity derivatives — Gas Utilities$0 $2,675 $0 $(1,552)$1,123 
Commodity derivatives — Electric Utilities$0 $921 $0 $0 $921 
Total$0 $3,596 $0 $(1,552)$2,044 
Recurring Fair Value Measurements

Pension and Postretirement Plan Assets
There have been no significant transfers between Level 1 and Level 2 derivative balances. Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties.

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 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

 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 1815 to the Consolidated Financial Statements included in our 20162020 Annual Report on Form 10-K.




24
(12)    FAIR VALUE OF FINANCIAL INSTRUMENTS
Table of Contents

Other fair value measures

The estimatedcarrying amount of cash and cash equivalents, restricted cash and equivalents, and short-term borrowings approximates fair value due to their liquid or short-term nature. Cash, cash equivalents, and restricted cash are classified in Level 1 in the fair value hierarchy. Notes payable consist of commercial paper borrowings and since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy.

The following 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
March 31, 2021December 31, 2020
Carrying
Amount		Fair ValueCarrying
Amount		Fair Value
Long-term debt, including current maturities (a)
$3,536,158 $3,938,977 $3,536,536 $4,208,167 
__________
(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)


(9)    Other Comprehensive Income

We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges, commodity contracts designated as cash flow hedges and the amortization of components of our defined benefit plans. Deferred gains (losses) for our commodity contracts designated as cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized.


The following table details reclassifications out of AOCI and into netNet income. The amounts in parentheses below indicate decreases to netNet 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 AOCI
Three Months Ended March 31,
20212020
Gains and (losses) on cash flow hedges:
Interest rate swapsInterest expense$(713)$(713)
Commodity contractsFuel, purchased power and cost of natural gas sold(31)(486)
(744)(1,199)
Income taxIncome tax benefit198 285 
Total reclassification adjustments related to cash flow hedges, net of tax$(546)$(914)
Amortization of components of defined benefit plans:
Prior service costOperations and maintenance$25 $30 
Actuarial gain (loss)Operations and maintenance(598)(597)
(573)(567)
Income taxIncome tax benefit208 88 
Total reclassification adjustments related to defined benefit plans, net of tax$(365)$(479)
Total reclassifications$(911)$(1,393)
25

Table of Contents
 Location on the Condensed Consolidated Statements of IncomeAmount Reclassified from AOCI
Three Months Ended Nine Months Ended
September 30, 2017September 30, 2016 September 30, 2017September 30, 2016
Gains and (losses) on cash flow hedges:      
Interest rate swapsInterest expense$(713)$(840) $(2,228)$(2,530)
Commodity contractsRevenue295
2,201
 954
9,140
Commodity contracts
Fuel, purchased power and cost of natural gas sold

(34)128
 (20)(23)
  (452)1,489
 (1,294)6,587
Income taxIncome tax benefit (expense)154
(566) 435
(2,450)
Total reclassification adjustments related to cash flow hedges, net of tax $(298)$923
 $(859)$4,137
       
Amortization of components of defined benefit plans:      
Prior service costOperations and maintenance$49
$55
 $146
$165
Actuarial gain (loss)Operations and maintenance(414)(494) (1,242)(1,483)
  (365)(439) (1,096)(1,318)
Income taxIncome tax benefit (expense)128
152
 393
460
Total reclassification adjustments related to defined benefit plans, net of tax $(237)$(287) $(703)$(858)
Total reclassifications $(535)$636
 $(1,562)$3,279




Balances by classification included within AOCI, net of tax on the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):
Derivatives Designated as Cash Flow Hedges
Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
As of December 31, 2020$(12,558)$2 $(14,790)$(27,346)
Other comprehensive income (loss)
before reclassifications0 107 0 107 
Amounts reclassified from AOCI523 23 365 911 
As of March 31, 2021$(12,035)$132 $(14,425)$(26,328)
Derivatives Designated as Cash Flow Hedges
Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
As of December 31, 2019$(15,122)$(456)$(15,077)$(30,655)
Other comprehensive income (loss)
before reclassifications0 (175)55 (120)
Amounts reclassified from AOCI543 371 479 1,393 
As of March 31, 2020$(14,579)$(260)$(14,543)$(29,382)


(10)    Employee Benefit Plans
 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

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)




(15)    EMPLOYEE BENEFIT PLANS


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 March 31,
20212020
Service cost$1,259 $1,353 
Interest cost2,328 3,357 
Expected return on plan assets(5,219)(5,648)
Net loss (gain)1,829 2,093 
Net periodic benefit cost$197 $1,155 
 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



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 March 31,
20212020
Service cost$559 $514 
Interest cost265 412 
Expected return on plan assets(34)(45)
Prior service cost (benefit)(109)(137)
Net loss (gain)117 5 
Net periodic benefit cost$798 $749 

26

 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
Table of Contents

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 March 31,
20212020
Service cost$693 $(1,370)
Interest cost177 275 
Net loss (gain)439 426 
Net periodic benefit cost$1,309 $(669)
 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 quarter of 2021 and anticipated contributions for 20172021 and 20182022 are as follows (in thousands):
Contributions MadeAdditional ContributionsContributions
Three Months Ended March 31, 2021Anticipated for 2021Anticipated for 2022
Defined Benefit Pension Plan$0 $0 $3,788 
Non-pension Defined Benefit Postretirement Healthcare Plan$1,382 $4,145 $5,241 
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans$482 $1,445 $1,967 


(11)    Income Taxes
 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


Winter Storm Uri

(16)    COMMITMENTS AND CONTINGENCIESAs discussed in Note 2 above, $559 million of the incremental costs from Winter Storm Uri are recoverable through our Utilities’ regulatory mechanisms, and we recorded these costs as regulatory assets at March 31, 2021. We expect to recover these costs from customers over several years. Winter Storm Uri costs, which will be deductible in our 2021 tax return, created a net deferred tax liability of approximately $132 million at March 31, 2021. The deferred tax liability will reverse with the same timing as the costs are recovered from our customers.


There have beenThe income tax deduction recognized from Winter Storm Uri will create an NOL in our 2021 federal and state income tax returns. Our federal NOL carryforwards no significantlonger expire due to the TCJA; however, our state NOL carryforwards expire at various dates from 2021 to 2040. We do not anticipate material changes to commitmentsour valuation allowance against the state NOL carryforwards from Winter Storm Uri. Therefore, we did not record an additional valuation allowance against the state NOL carryforwards as of March 31, 2021.

Income Tax Benefit (Expense) and contingencies from those previously disclosed in Note 19 of our NotesEffective Tax Rates

Three Months Ended March 31, 2021 Compared to the Consolidated Financial StatementsThree Months Ended March 31, 2020

Income tax (expense) for the three months ended March 31, 2021 was $(0.5) million compared to $(16) million reported for the same period in our 2016 Annual Report on Form 10-K.

Dividend Restrictions

Our Revolving Credit Facility and other debt obligations contain restrictions on2020. For the paymentthree months ended March 31, 2021 the effective tax rate was 0.5% compared to 14.1% for the same period in 2020. The lower effective tax rate is primarily due to $7.6 million of cash dividends upon a default or eventincreased tax benefits from Colorado Electric’s TCJA-related bill credits to customers (which is offset by reduced revenue), $1.5 million of default. Asincreased tax benefits from amortization of September 30, 2017, we were in compliance with the debt covenants.

Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our stockholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries.

Our utilities are generally limited to the amount of dividends allowed to be paid to 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 relatedexcess deferred income taxes and $1.3 million of increased tax benefits from federal production tax credits associated with new wind assets.


27

Table of Contents
(12)    Business Segment Information

Our reportable segments are subject to a ceiling testbased on our method of internal reporting, which limitsis generally segregated by differences in products, services and regulation. All of our operations and assets are located within the pooledUnited States.

Accounting standards for presentation of segments require an approach based on the way we organize the segments for making operating decisions and how the Chief Operating Decision Maker (CODM) assesses performance. The CODM assesses the performance of our segments using adjusted operating income, which recognizes intersegment revenues, 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 offassets for Colorado Electric’s PPA with Black Hills Colorado IPP on an accrual basis rather than as a non-cash charge.finance lease. This presentation of segment information does not impact consolidated financial results.


There were no impairments for the nine months ended September 30, 2017. In determining the ceiling value of our assets 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 priceSegment information 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. During the three and nine months ended September 30, 2016, we recorded pre-tax non-cash impairments of oil and gas assets included in our Oil and Gas segment of $12 million and $38 million, respectively.as follows (in thousands):

Total assets (net of intercompany eliminations) as of:March 31, 2021December 31, 2020
Electric Utilities$3,217,474 $3,120,928 
Gas Utilities4,900,939 4,376,204 
Power Generation406,742 404,220 
Mining76,097 77,085 
Corporate and Other94,947 110,349 
Total assets$8,696,199 $8,088,786 



Three Months Ended March 31, 2021External Operating RevenueInter-company Operating RevenueTotal Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities$220,500 $137 $6,771 $0 $227,408 
Gas Utilities398,499 2,408 1,520 92 402,519 
Power Generation4,241 421 24,451 50 29,163 
Mining6,977 249 7,106 340 14,672 
Inter-company eliminations— — (39,848)(482)(40,330)
Total$630,217 $3,215 $0 $0 $633,432 
During the second quarter of 2016, certain non-core assets were identified that were not suitable for inclusion in a possible Cost of Service Gas program. We assessed these assets for impairment in accordance with ASC 360. We valued the assets applying a market method approach utilizing assumptions consistent with similar known and measurable transactions and determined that the carrying amount exceeded the fair value. As a result, we recorded a pre-tax impairment of depreciable properties at June 30, 2016 of $14 million, in addition to the impairments noted above.

Three Months Ended March 31, 2020External Operating RevenueInter-company Operating Revenue Total Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities$167,503 $223 $6,413 $0 $174,139 
Gas Utilities354,287 5,708 778 0 360,773 
Power Generation1,855 443 23,612 56 25,966 
Mining6,564 467 7,839 335 15,205 
Inter-company eliminations— — (38,642)(391)(39,033)
Total$530,209 $6,841 $0 $0 $537,050 
(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.

In the first quarter
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Table of 2016, 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 TransactionContents
Three Months Ended March 31,
20212020
Adjusted operating income:
Electric Utilities$21,813 $35,650 
Gas Utilities102,094 102,897 
Power Generation14,269 11,349 
Mining3,261 3,129 
Corporate and Other(3,122)160 
Operating income138,315 153,185 
Interest expense, net(37,600)(35,453)
Impairment of investment0 (6,859)
Other income (expense), net266 2,353 
Income tax (expense)(494)(16,002)
Net income100,487 97,224 
Net income attributable to noncontrolling interest(4,171)(4,050)
Net income available for common stock$96,316 $93,174 


(13)    Selected Balance Sheet Information

Accounts Receivable and the Aquila Transaction.  An agreement in principle was also reached with respect to research and development credits and deductions.  Both issues were the subjectAllowance for Credit Losses

Following is a summary of an IRS Appeals process involving the 2007 to 2009 tax years. We reversed approximately $35 million of the liability 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 liabilitiesAccounts receivable, net included in the first quarteraccompanying Condensed Consolidated Balance Sheets (in thousands) as of:
March 31, 2021December 31, 2020
Accounts receivable, trade$199,548 $146,899 
Unbilled revenue91,085 126,065 
Less: Allowance for credit losses(8,251)(7,003)
Accounts receivable, net$282,382 $265,961 

Changes to allowance for credit losses for the three months ended March 31, 2021 and 2020, respectively, were as follows (in thousands):

Balance at Beginning of YearAdditions Charged to Costs and ExpensesRecoveries and Other AdditionsWrite-offs and Other DeductionsBalance at March 31,
2021$7,003 $1,877 $1,014 $(1,643)$8,251 
2020$2,444 $3,519 $922 $(1,723)$5,162 

Materials, Supplies and Fuel

The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
March 31, 2021December 31, 2020
Materials and supplies$88,088 $85,250 
Fuel - Electric Utilities1,590 1,531 
Natural gas in storage12,925 30,619 
Total materials, supplies and fuel$102,603 $117,400 

29

Table of 2016. The cash taxes due as a result of the agreement in principle with IRS Appeals is estimated to be $8.0 million excluding interest.Contents


Accrued Liabilities

(19)    ACCRUED LIABILITIES


The following amounts by major classification are included in Accrued liabilities inon the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:

March 31, 2021December 31, 2020
Accrued employee compensation, benefits and withholdings$57,347 $77,806 
Accrued property taxes49,267 47,105 
Customer deposits and prepayments50,194 52,185 
Accrued interest45,896 31,520 
Other (none of which is individually significant)27,740 34,996 
Total accrued liabilities$230,444 $243,612 


 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 Oil and Gas Business

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. Effective in the fourth quarter of 2017, our Oil and Gas segment assets and liabilities will be classified as held for sale, and the Oil and Gas results 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.

Revenue and net loss for our Oil and Gas segment for the three and nine months ended September 30, 2017 and 2016 were as follows:
 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

The following discussions should be read in conjunction with the Notes contained herein and Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in the 2020 Form 10-K.


Executive Summary

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

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

Gas Utilities: Our Gas Utilities conduct natural gas utility operations through ourcompany with a mission of Improving Life with Energy and a vision to be the Energy Partner of Choice. The Company provides electric and natural gas utility service to 1.3 million customers over 800 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming subsidiaries. Our Gas Utilities distributeWyoming.

Recent Developments

Winter Storm Uri

In February 2021, a prolonged period of historic cold temperatures across the central United States, which covered all of our Utilities’ service territories, caused a significant increase in heating and transportenergy demand and contributed to unforeseeable and unprecedented market prices for natural gas and electricity. As a result of Winter Storm Uri, our net pre-tax incremental fuel, purchased power and natural gas costs during the three months ended March 31, 2021 were approximately $571 million. This amount does not include potential pipeline transportation charges from certain suppliers who have requested and received approval from the FERC to delay billings. The pre-tax incremental costs for the three months ended March 31, 2021 from Winter Storm Uri were as follows:
(in millions)
Incremental fuel, purchased power and natural gas costs recorded to regulatory assets$558.8 
Electric Utilities wholesale power margin sharing$3.2 
Electric Utilities non-recoverable fuel costs2.1 
Black Hills Energy Services non-recoverable natural gas costs8.2 
Interest expense from $800 million term loan0.7 
Less Power Generation favorable net impact(1.7)
Incremental costs recorded as expenses, net$12.5 
Total incremental costs related to Winter Storm Uri, net$571.3 

On February 24, 2021, we entered into a nine-month, $800 million unsecured term loan to provide additional liquidity and meet our cash needs related to the incremental fuel, purchased power and natural gas costs from Winter Storm Uri. The nine-month term loan has no prepayment penalty and is subject to the same covenants as our Revolving Credit Facility. As of March 31, 2021, we have repaid $200 million of this term loan and expect to refinance a portion with longer-term debt later in 2021. See Note 5 of the Notes to Condensed Consolidated Financial Statements for additional term loan information.

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Our Utilities have regulatory mechanisms to recover approximately $559 million of incremental costs from Winter Storm Uri. However, given the extraordinary impact of these higher costs to our customers, our regulators are performing a heightened review. We are engaged with our regulators to determine appropriate recovery periods for Winter Storm Uri incremental costs with consideration of the impacts to our customers’ bills. Our estimate of the recoverable incremental costs is based on anticipated filings that we expect to complete in the second quarter of 2021 and is subject to adjustments as applications are submitted and final decisions are issued. See Note 2 of the Notes to Condensed Consolidated Financial Statements for information regarding estimated Winter Storm Uri incremental costs by jurisdiction.

For the three months ended March 31, 2021, we expensed $12.5 million of Winter Storm Uri net incremental costs as a result of negative impacts to our Utilities and financing costs partially offset by favorable impacts to our Power Generation segment. Our Electric Utilities incurred a $3.2 million negative impact to regulated wholesale power margins due to higher fuel costs and $2.1 million of incremental fuel costs that are not recoverable through our pipeline network to approximately 1,030,800 natural gas customers. Additionally, we sell temporarily-available, contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates.

We also provide non-regulated services through Black Hills Energy Services.fuel cost recovery mechanisms. Black Hills Energy Services provides approximately 55,000 retail distribution customers in Nebraska and Wyoming with unbundledoffers fixed contract pricing for non-regulated gas supply services to our regulated natural gas commodity offerings undercustomers and $8.2 million of increased cost of natural gas sold during Winter Storm Uri is not recoverable through 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 and CAPP primarily provide appliance repair servicesregulatory construct. Additionally, we incurred $0.7 million of interest expense for the three months ended March 31, 2021, related to approximately 61,000 and 33,000 residential customers, respectively, through Company technicians and third-party service providers, typically through on-going monthly service agreements. Tech Services primarily serves gas transportation customers throughout our service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.

Power Generation:$800 million term loan. Our non-regulated Power Generation segment produces electric powerbenefited from its generating plantsa $1.7 million favorable impact to operating income from Winter Storm Uri. We expect opportunities in 2021 to mitigate these negative impacts through cost management and sells the electric capacity and energy principally to our utilities under long-term contracts.regulatory actions.


Mining: Our Mining segment produces coal at our coal mine near Gillette, Wyoming and sells the coal primarily to on-site, mine-mouth power generation facilities.COVID-19 Update


Oil and Gas: Our Oil and Gas segment engages in the production 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 forFor 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, asMarch 31, 2021, we did not meetexperience significant impacts to our financial results, liquidity or operational activities due to COVID-19. We continue to monitor loads, customers’ ability to pay, the criteriapotential for classifying assetssupply chain disruption that may impact our capital and maintenance project plans, the availability of third-party resources to execute our business plans and the capital markets to ensure we have the liquidity necessary to support our financial needs. State orders lifting temporarily suspended disconnections have been issued in all of our jurisdictions.

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

As we look forward, our operating results from COVID-19 could be affected as held for sale and presentingdiscussed in the segment’s activities as discontinued operations during the quarter. See Note 20“Risk Factors” section in Part I, Item 1A of the Condensed Consolidated Financial Statements in this Quarterlyour 2020 Annual Report on Form 10-Q10-K.

Business Segment Highlights and Corporate Activity

Electric Utilities Segment

•On February 19, 2021, Colorado Electric entered into a PPA with TC Colorado Solar, LLC to purchase up to 200 MW of renewable energy upon construction of a new solar facility, to be owned by TC Colorado Solar, LLC, which is expected to be completed by the end of 2023. This agreement will expire 15 years after construction completion. The utility-scale solar project represents Colorado Electric’s preferred bid in a competitive solicitation process completed in September 2020 through its Renewable Advantage plan. With the addition of 200 MW of solar energy on its system, more than half of the Colorado Electric’s generation is forecasted to be sourced from renewable energy resources by 2023, leading to a 70% reduction in carbon emissions by 2024 compared to the 2005 base year.

•On February 11, 2021, South Dakota Electric set a new winter peak load of 326 MW, surpassing the previous winter peak of 320 MW set in February 2019.

Gas Utilities Segment

•On January 26, 2021, Nebraska Gas received approval from the NPSC to consolidate rate schedules into a new, single statewide structure and recover infrastructure investments in its 13,000-mile natural gas pipeline system. Final rates were enacted on March 1, 2021 and are expected to generate $6.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and an authorized return on equity of 9.5%. The approval also includes an extension of the SSIR for more information.five years and an expansion of this mechanism across the consolidated jurisdictions.


•On September 11, 2020, Colorado Gas filed a rate review with the CPUC seeking recovery on infrastructure investments in its 7,000-mile natural gas pipeline system. On January 6, 2021, the CPUC issued an Order dismissing the rate review. Colorado Gas plans to file a rate review in the second quarter of 2021.

On September 11, 2020, in accordance with the final order from the earlier rate review filed February 1, 2019, Colorado Gas filed a SSIR proposal with the CPUC that would recover safety and integrity focused investments in its system for five years. A decision from the CPUC is expected by mid-2021.


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Table of Contents
Results of Operations

The segment information does not include inter-company eliminations. Minor differences in amounts may result due to rounding. All amounts are presented on a pre-tax basis unless otherwise indicated.

Certain industrieslines of business 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, 2017March 31, 2021 and 2016,2020, and our financial condition as of September 30, 2017,March 31, 2021 and December 31, 2016 and September 30, 2016,2020, 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.


Consolidated Summary and Overview
See Forward-Looking Information in the Liquidity and Capital Resources section
Three Months Ended March 31,
20212020
(in thousands except per share amounts)
Adjusted operating income (a)
Electric Utilities$21,813 $35,650 
Gas Utilities102,094 102,897 
Power Generation14,269 11,349 
Mining3,261 3,129 
Corporate and Other(3,122)160 
Operating income138,315 153,185 
Interest expense, net(37,600)(35,453)
Impairment of investment— (6,859)
Other income (expense), net266 2,353 
Income tax (expense)(494)(16,002)
Net income100,487 97,224 
Net income attributable to noncontrolling interest(4,171)(4,050)
Net income available for common stock96,316 93,174 
Total earnings per share of common stock, Diluted$1.54 $1.51 
__________
(a)    Adjusted operating income recognizes intersegment 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 this Item 2, beginning on Page 73.

The segment information does not include inter-company eliminations. Minor differences in amounts may result due to rounding. All amounts are presented on a pre-tax basis unless otherwise indicated.impact consolidated financial results.




Results of Operations

Executive Summary, Significant Events and Overview

Three Months Ended September 30, 2017March 31, 2021 Compared to Three Months Ended September 30, 2016. Net income available for common stock 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. March 31, 2020

The variance to the prior year included the following:


A decrease in non-cash after-tax impairment charges of approximately $7.9•Electric Utilities’ adjusted operating income decreased $14 million primarily due to Colorado Electric’s TCJA-related bill credits to customers, impacts from Winter Storm Uri and unfavorable mark-to-market adjustments on our oilwholesale energy contracts partially offset by increased rider revenues and gas properties;lower operating expenses;
•Gas Utilities’ adjusted operating income decreased $0.8 million primarily due to Winter Storm Uri costs incurred by Black Hills Energy Services and higher operating expenses mostly offset by new rates and higher heating demand from colder winter weather;
•Power Generation’s adjusted operating income increased $2.9 million primarily due to favorable impacts from Winter Storm Uri;
•Corporate and Other expenses decreasedincreased $3.3 million 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 duefavorable true-up of employee costs allocated 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 periodour subsidiaries in the priorcurrent year, primarilywhich is offset in our reportable segments;
•A $2.1 million increase in interest expense 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,debt balances 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 therates;
•A prior year included the following:$6.9 million pre-tax non-cash impairment of our investment in equity securities of a privately held oil and gas company;

32
Earnings at our Oil and Gas segment increased $28
Table of Contents
•A $2.1 million decrease in other income primarily due to prior year non-cash after-tax impairmentscredits for our non-qualified benefit plan driven by market performance on our oilplan assets; and gas properties of approximately $33
•A $15.5 million partially offset bydecrease in income tax expense due to lower pre-tax income and a prior year $5.8 millionlower effective tax benefit recognized from additional percentage depletion deductions claimed with respect to our oil and gas properties;
Corporate expenses decreased $27 million compared to the same period in the prior yearrate driven primarily by a $23 million reductiontax benefits from Colorado Electric’s TCJA-related bill credits, amortization of after-tax acquisitionexcess deferred income taxes and transition costs;federal production tax credits associated with new wind assets.
Gas Utilities’ earnings increased $11 million with a full nine months of earnings from our acquired SourceGas utilities compared to approximately 7.5 months 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 segment 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 stock 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, 2017 compared to the three and nine months ended September 30, 2016. Cooling degree days for the three and nine months ended September 30, 2017 were both 15% higher than normal, compared to 15% and 26% higher than normal for the same periods in 2016. Compared to the same periods in 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% and 11% lower than normal, respectively, compared to 34% and 13% lower than normal for the same periods in 2016.

On January 17, 2017, Colorado Electric received approval from the CPUC on a settlement agreement for its electric resource plan which provides for the addition of 60 megawatts of renewable energy to be in service by 2019. The resource plan was filed June 3, 2016, to meet requirements under the Colorado Renewable Energy Standard. In the second quarter of 2017, Colorado Electric issued a request for proposals to 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 appeal of this decision with Denver County District Court 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, Wyoming Electric set a new summer load peak of 249 MW, exceeding the previous summer peak of 236 MW set in July 2016.

Gas Utilities Segment

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.

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 sale 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 commitments in the Piceance. Crude oil production also decreased due to non-core property sales 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.

Corporate Activities

On August 4, 2017, 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. The renewed program, which allows us to sell shares of our common stock, is the same as the prior year program with the exception that the aggregate value increased $100 million.

We utilized favorable 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 May and an additional $50 million paid in July.

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

On October 4, 2017, Fitch affirmed Black Hills’ credit rating at BBB+ rating and changed its outlook from Negative to Stable, citing successful integration of SourceGas, a low business risk profile focused on utility operations and expected improvement of credit metrics.

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 as to the ultimate legislation that will be enacted into law.  We are evaluating the proposed legislation; any impact on our future results of operations, financial position and cash flows as a result of the potential changes cannot yet be determined and such changes could be material.

Operating Results


A discussion of operating results from our business segments and Corporate activities follows.



Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, gross margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of depreciation and amortization from the measure. The presentation of gross margin is intended to supplement investors’ understanding of our operating performance.


Gross margin for our Electric Utilities is calculated as operating revenue less cost of fuel and purchased power. Gross margin for our Gas Utilities is calculated as operating 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. Furthermore, this measure is not intended to replace operating income, as determined in accordance with GAAP, as an indicator of operating performance.





Electric Utilities

 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 OperationsOperating results for the Electric Utilities for the were as follows (in thousands):
Three Months Ended March 31,
20212020Variance
Revenue$227,408 $174,139 $53,269 
Total fuel and purchased power132,069 64,460 67,609 
Gross margin (non-GAAP)95,339 109,679 (14,340)
Operations and maintenance48,577 50,499 (1,922)
Depreciation and amortization24,949 23,530 1,419 
Total operating expenses73,526 74,029 (503)
Adjusted operating income$21,813 $35,650 $(13,837)

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Table of Contents
Three Months Ended September 30, 2017March 31, 2021 Compared to the Three Months Ended September 30, 2016: Net income available for common stock for the Electric Utilities was $27 millionMarch 31, 2020:

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, as a result of:

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 increased primarily due to $1.4 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 millionMarch 31, 2021 decreased as a result of the following:
(in millions)
TCJA-related bill credits (a)
$(9.3)
Winter Storm Uri impacts (b)
(5.3)
Mark-to-market on wholesale energy contracts(2.9)
Rider recovery1.3 
Weather1.1 
Residential customer growth0.3 
Other0.5 
Total change in Gross margin (non-GAAP)$(14.3)
________________
(a)    In February 2021, Colorado Electric delivered TCJA-related bill credits to its customers. These bill credits were offset by a reduction in income tax expense and resulted in a minimal impact to Net Income.
(b)    As a result of Winter Storm Uri, our Electric Utilities incurred a $3.2 million negative impact to our regulated wholesale power margins due to higher fuel costs and $2.1 million of incremental fuel costs that are not recoverable through our fuel cost recovery mechanisms.

Operations and maintenance expense decreased primarily due to prior year integration activities and transition expenses chargedrelated to the Corporate segment. In addition, operating expenses increased $0.4 million from the addition of the Peak View Wind Project and the 40-megawatt gas turbine at themunicipalization efforts in Pueblo, Airport Generating Station.Colorado.


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

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





Results of Operations for the Electric Utilities 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 Electric Utilities was $68 million 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, as a result of:

Gross margin increased over the prior year reflecting a $7.5 million return on investment from the Peak View Wind Project, a $6.4 million increase in rider revenues primarily related to transmission investment recovery and a $3.3 million increase in commercial and industrial margins driven by increased demand largely associated with data centers in Cheyenne, Wyoming. A variety of smaller items contribute to the remainder of the increase.

Operations and maintenance increased primarily due to $4.2 million of higher employee costs as a result of prior year integration activities and transition expenses charged to the Corporate segment, $2.0 million increase in generation outage and major maintenance expenses with increased scope of work, $1.9 million of higher property taxes with an increased asset base, and $1.3 million of higher operating expenses from the Peak View Wind Project and 40-megawatt gas turbine at the Pueblo Airport Generating Station.

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

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

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

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.



 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
__________
(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.



 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.


Operating Statistics

Revenue (in thousands)Quantities Sold (MWh)
Three Months Ended
March 31,		Three Months Ended
March 31,
2021202020212020
Residential$72,760 $54,505 396,086 373,150 
Commercial77,007 57,823 492,955 494,308 
Industrial43,009 32,169 415,191 460,632 
Municipal5,020 3,878 36,242 36,399 
Subtotal Retail Revenue - Electric197,796 148,375 1,340,474 1,364,489 
Contract Wholesale (a)
8,465 5,553 156,995 131,778 
Off-system/Power Marketing Wholesale5,113 4,867 127,583 165,785 
Other16,034 15,344 — — 
Total Revenue and Energy Sold227,408 174,139 1,625,052 1,662,052 
Other Uses, Losses or Generation, net— — 130,975 90,871 
Total Revenue and Energy227,408 174,139 1,756,027 1,752,923 
Less cost of fuel and purchased power132,069 64,460 
Gross Margin (non-GAAP)$95,339 $109,679 
34

Table of Contents
 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
Three Months Ended March 31,Revenue
(in thousands)		Gross Margin (non-GAAP) (in thousands)
Quantities Sold (MWh)(a)
202120202021202020212020
Colorado Electric$79,741 $58,558 $24,091 $32,270 606,343 550,771 
South Dakota Electric95,336 71,611 49,550 55,624 657,779 685,224 
Wyoming Electric52,331 43,970 21,698 21,785 491,905 516,928 
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold$227,408 $174,139 $95,339 $109,679 1,756,027 1,752,923 
__________________________
(a)    Year over year increases are driven by new load supporting data centers in Cheyenne, Wyoming.Includes company uses, line losses, and excess exchange production.
Three Months Ended
March 31,
Quantities Generated and Purchased (MWh)20212020
Generated:
Coal482,978 547,829 
Natural Gas and Oil132,105 167,744 
Wind62,295 73,550 
Total Generated677,378 789,123 
Purchased1,078,649 963,800 
Total Generated and Purchased1,756,027 1,752,923 

Three Months Ended
March 31,
Quantities Generated and Purchased (MWh)20212020
Generated:
Colorado Electric90,256 94,051 
South Dakota Electric434,322 472,966 
Wyoming Electric152,800 222,106 
Total Generated677,378 789,123 
Purchased:
Colorado Electric516,087 456,720 
South Dakota Electric223,457 212,258 
Wyoming Electric339,105 294,822 
Total Purchased1,078,649 963,800 
Total Generated and Purchased1,756,027 1,752,923 
(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.



 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.


Three Months Ended March 31,
20212020
Heating Degree DaysActualVariance from
Normal		ActualVariance from
Normal
Colorado Electric2,731 3 %2,456 (7)%
South Dakota Electric3,324 3 %3,111 (3)%
Wyoming Electric3,261 8 %2,999 (1)%
Combined (a)
3,040 4 %2,789 (4)%

____________________
(a)    Combined actuals are calculated based on the weighted average number of total customers by state.
35

Table of Contents

Three Months Ended March 31,
Contracted generating facilities availability by fuel type (a)
20212020
Coal (b)
83.7 %90.8 %
Natural Gas and diesel oil (b) (c)
87.6 %83.5 %
Wind93.5 %99.0 %
Total availability87.2 %87.1 %
Wind capacity factor43.1 %45.6 %
____________________
(a)    Availability and wind capacity factor are calculated using a weighted average based on capacity of our generating fleet.
(b)     2021 included a planned outage at Wygen II and unplanned outages at Neil Simpson II and Pueblo Airport Generation.
(c)    2020 included an unplanned outage at Pueblo Airport Generation.


Gas Utilities

 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 OperationsOperating results for the Gas Utilities for the were as follows (in thousands):
Three Months Ended March 31,
20212020Variance
Revenue:
Natural gas - regulated$378,077 $335,897 $42,180 
Other - non-regulated services24,442 24,876 (434)
Total revenue402,519 360,773 41,746 
Cost of sales:
Natural gas - regulated182,967 153,999 28,968 
Other - non-regulated services10,083 1,363 8,720 
Total cost of sales193,050 155,362 37,688 
Gross margin (non-GAAP)209,469 205,411 4,058 
Operations and maintenance82,200 77,293 4,907 
Depreciation and amortization25,175 25,221 (46)
Total operating expenses107,375 102,514 4,861 
Adjusted operating income$102,094 $102,897 $(803)

36

Table of Contents
Three Months Ended September 30, 2017March 31, 2021 Compared to the Three Months Ended September 30, 2016: Net loss available for common stock for the Gas Utilities was $(4.3) millionMarch 31, 2020

Gross margin for the three months ended September 30, 2017, compared to Net loss available for common stock of $(3.0) million for the three months ended September 30, 2016,March 31, 2021 increased as a result of:

(in millions)
New rates$9.2 
Weather7.5 
Black Hills Energy Services Winter Storm Uri costs (a)
(8.2)
Non-utility Gas Supply Services(1.2)
Mark-to-market on non-utility natural gas commodity contracts(0.4)
Other(2.8)
Total increase in Gross margin (non-GAAP)$4.1 
Gross margin decreased primarily due__________
(a)    Black Hills Energy Services offers fixed contract pricing for non-regulated gas supply services to our regulated natural gas customers. The increased cost of natural gas sold during Winter Storm Uri is not recoverable through a $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 as compared to the same period in the prior year. This is partially offset by gas utilities' customer growth and higher rider revenue.regulatory mechanism.


Operations and maintenance expense increased primarily due to $1.2$5.5 million of higher employee related costs and outside services expenses as a result of prior year integration activitiesdriven by higher headcount and transition expenses chargedhigher stock compensation expense related to the Corporate segment,market performance partially offset by $1.0 million of lower pensiontravel and training expenses.


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

Interest expense, net decreased primarilyyear due to the August 2016 refinancing of the debt assumed in the SourceGas Acquisition.

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, 2017 Compared to the Nine Months Ended September 30, 2016: Net income available for common stock for the Gas Utilities was $41 million for the nine months ended September 30, 2017, compared to Net income available for common stock of $30 million 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 2017 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 primarilydepreciation rates approved in the Nebraska service territoryGas and Colorado Gas rate reviews mostly offset by increased depreciation due to cooler summer temperatures anda 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 ofasset base driven by 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.capital expenditures.

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 comparable to the same period in the prior year.



 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 primarily driven by lower irrigation load in 2017 compared to the prior year.
 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 is primarily driven by lower irrigation load in 2017 compared to the prior year.



 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
__________
(a)Certain prior year revenue classes have been revised to conform to current year presentation.
Operating Statistics
Revenue
(in thousands)		Gross Margin (non-GAAP)
(in thousands)		Quantities Sold & Transported (Dth)
Three Months Ended
March 31,		Three Months Ended
March 31,		Three Months Ended
March 31,
202120202021202020212020
Residential$234,397 $207,231 $110,148 $103,121 30,568,738 28,230,795 
Commercial91,089 80,236 35,484 33,519 13,812,321 12,834,803 
Industrial4,902 5,200 1,789 2,043 898,289 1,061,052 
Other(472)(1,242)(472)(1,242)— — 
Total Distribution329,916 291,425 146,949 137,441 45,279,348 42,126,650 
Transportation and Transmission48,161 44,472 48,161 44,457 45,314,438 45,055,507 
Total Regulated378,077 335,897 195,110 181,898 90,593,786 87,182,157 
Non-regulated Services24,442 24,876 14,359 23,513 
Total Gas Revenue & Gross Margin (non-GAAP)$402,519 $360,773 $209,469 $205,411 
37

Table of Contents
Revenue
(in thousands)
Gross Margin (non-GAAP)
(in thousands)
Gas Utilities Quantities Sold & Transported (Dth)
Three Months Ended
March 31,		Three Months Ended
March 31,		Three Months Ended
March 31,
202120202021202020212020
Arkansas Gas$86,994 $74,845 $51,949 $48,855 13,306,734 10,962,948 
Colorado Gas79,122 72,606 38,212 38,006 13,366,015 13,096,405 
Iowa Gas56,754 54,824 22,631 21,328 14,313,973 14,280,273 
Kansas Gas40,063 33,494 18,766 18,603 10,462,797 9,914,858 
Nebraska Gas93,098 83,666 49,932 51,666 27,284,101 26,509,036 
Wyoming Gas46,488 41,338 27,979 26,953 11,860,166 12,418,637 
Total Gas Revenue & Gross Margin (non-GAAP)$402,519 $360,773 $209,469 $205,411 90,593,786 87,182,157 
(b)Decrease for the three months ended September 30, 2017 is primarily driven by lower irrigation load in 2017 compared to the prior year.


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.



 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)%
          
 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)%
__________
(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.



Three Months Ended March 31,
20212020
Heating Degree Days:ActualVariance
from Normal		ActualVariance
from Normal
Arkansas Gas (a)
2,1211%1,659(21)%
Colorado Gas2,9651%2,829(3)%
Iowa Gas3,4221%3,181(6)%
Kansas Gas (a)
2,5765%2,304(7)%
Nebraska Gas3,0972%2,835(7)%
Wyoming Gas3,4257%3,2171%
Combined Gas (b)
3,1863%2,918(6)%

__________
(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 partially 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 2 of the Notes to Condensed Consolidated Financial Statements and Part I, Items 1 and 2 and Part II, Item 8 of our 20162020 Annual Report on Form 10-K filed with the SEC.10-K.


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:
38

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 quarterTable 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.Contents

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,
 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 forOur Power Generation for the segment operating results were as follows (in thousands):
Three Months Ended March 31,
20212020Variance
Revenue$29,163 $25,966 $3,197 
Fuel expense2,671 2,285 386 
Operations and maintenance7,358 6,997 361 
Depreciation and amortization4,865 5,335 (470)
Total operating expense14,894 14,617 277 
Adjusted operating income$14,269 $11,349 $2,920 

Three Months Ended September 30, 2017March 31, 2021 Compared to the Three Months Ended March 31, 2020:

Operating income increased $1.7 million due to Winter Storm Uri’s favorable impact to Black Hills Wyoming under the economy energy PSA. Revenue also increased due to higher Wygen I MWh sold driven by a prior year planned outage.

Operating Statistics
Revenue (in thousands)
Quantities Sold (MWh) (a)
Three Months Ended March 31,2021202020212020
Black Hills Colorado IPP$14,254 $14,179 239,194 265,225 
Black Hills Wyoming (b)
13,433 10,158 164,957 156,352 
Black Hills Electric Generation1,476 1,629 96,294 97,279 
Total Power Generation Revenue and Quantities Sold$29,163 $25,966 500,445 518,856 
Three Months Ended March 31,
Quantities Generated and Purchased (MWh) (a)
Fuel Type20212020
Generated
Black Hills Colorado IPPNatural Gas239,194 265,225 
Black Hills Wyoming (b)
Coal136,104 126,485 
Black Hills Electric GenerationWind96,294 97,279 
Total Generated471,592 488,989 
Purchased
Black Hills Wyoming (b)
Various29,567 29,856 
Total Purchased29,567 29,856 
____________
(a)    Company uses and losses are not included in the quantities sold, generated, and purchased.
(b)    Under the 20-year economy energy PSA with the City of Gillette effective September 30, 2016: Net2014, 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 that Black Hills Wyoming has with South Dakota Electric to cover energy imbalances.
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Table of Contents

Three Months Ended March 31,
Contracted generating facilities availability by fuel type (a)
20212020
Coal (b)
97.0 %89.3 %
Natural gas98.6 %99.5 %
Wind94.2 %99.3 %
Total availability96.7 %97.8 %
Wind capacity factor32.6 %30.4 %
____________________
(a)    Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.
(b)     2020 included a planned outage at Wygen I.


Mining

Our Mining segment operating results were as follows (in thousands):
Three Months Ended March 31,
20212020Variance
Revenue$14,672 $15,205 $(533)
Operations and maintenance9,197 9,826 (629)
Depreciation, depletion and amortization2,214 2,250 (36)
Total operating expenses11,411 12,076 (665)
Adjusted operating income$3,261 $3,129 $132 

Three Months Ended March 31, 2021 Compared to the Three Months Ended March 31, 2020:

Adjusted operating income available for common stock for the Power Generation segment was $6.2 million for the three months ended September 30, 2017, compared to Net income available for common stock of $5.6 million for the same period in 2016. Revenue and operating expenses were comparable to the same period in the prior year. The variance to the prior year was driven by a lower 2017 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 Operations 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 for the nine months ended September 30, 2017, compared to Net income available for common stock of $20 million for the same period in 2016. Revenue 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.Operating Statistics

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 March 31,
20212020
Tons of coal sold875 896 
Cubic yards of overburden moved1,822 2,267 
Revenue per ton$16.09 $16.08 


40

 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
Table of Contents
____________
(a)Increase is driven by mining in areas with more overburden than in the prior year as well as higher production.

Corporate and Other



Corporate and Other operating results were as follows (in thousands):
Results of Operations for Mining for the
Three Months Ended March 31,
20212020Variance
Adjusted operating income (loss)$(3,122)$160 $(3,282)

Three Months Ended September 30, 2017March 31, 2021 Compared to the Three Months Ended September 30, 2016: NetMarch 31, 2020:

The variance in Adjusted operating income available for common stock for the Mining segment(loss) 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 increased primarily due to increased overburden removal and higher royalties and production taxes on increased revenues.

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

Interest (expense) income, netprior year favorable true-up of employee costs which was comparableallocated to the same periodour subsidiaries in the priorcurrent year. This allocation was offset in our reportable segments and had no impact to consolidated results.



Consolidated Interest Expense, Impairment of Investment, Other income, net was comparable to the same period in the prior year.Income (Expense) and Income Tax (Expense)


Income tax benefit (expense): The effective tax rate is comparable to the same period last year.
Three Months Ended March 31,
20212020Variance
(in thousands)
Interest expense, net$(37,600)$(35,453)$(2,147)
Impairment of investment— (6,859)$6,859 
Other income (expense), net266 2,353 $(2,087)
Income tax (expense)(494)(16,002)$15,508 


Results 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, partially 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.

Income 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, 2017March 31, 2021 Compared to the Three Months Ended September 30, 2016: Net loss availableMarch 31, 2020.

Interest Expense

The increase in Interest expense, net was due to higher debt balances driven by the February 2021 term loan and the June 2020 senior unsecured notes partially offset by lower interest rates.

Impairment of Investment

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

Other Income (Expense)

The decrease in Other income was primarily due to prior year credits for common stock for the Oil and Gas segment was $(2.7) million forour non-qualified benefit plan driven by market performance on plan assets.

Income Tax (Expense)

For the three months ended September 30, 2017,March 31, 2021, the effective tax rate was 0.5% compared to Net loss available for common stock of $(8.8) million14.1% 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 2016.2020. 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$7.6 million of increased tax benefits from Colorado Electric’s TCJA-related bill credits 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 partiallycustomers (which is 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 acquisition 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.

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 approximatelyrevenue), $1.5 million of after-tax non-recurring acquisitionincreased tax benefits from amortization of excess deferred income taxes and transition costs, compared to a total of approximately $24$1.3 million of after-tax non-recurring acquisitionincreased tax benefits from federal production tax credits associated with new wind assets.


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Table of Contents
Liquidity 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.Capital Resources


Critical Accounting Estimates

There have been no material changes in our critical accounting estimatesLiquidity and Capital Resources from those reported in Item 7 of our 20162020 Annual Report on Form 10-K filed withexcept as described below.

For the SEC. For more information onthree months ended March 31, 2021, we did not experience significant impacts to our critical accounting estimates, see Part II, Item 7 ofliquidity or financial condition due to the COVID-19 pandemic.

In response to the February 2021 Winter Storm Uri, we took steps to maintain adequate liquidity to operate our 2016 Annual Report on Form 10-K.

Liquiditybusinesses and Capital Resources

OVERVIEW

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 arefund our capital expenditures,investment program as discussed in the purchase of natural gas for our Gas UtilitiesRecent Developments above and our Power Generation segment, as well as the payment of dividends to our shareholders. We experience significant cash requirements during peak monthsin further detail in Note 5 of the winter heating season dueNotes to higher natural gas consumption and during periods of high natural gas prices, as well as during the summer construction season.Condensed Consolidated Financial Statements.


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 Utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas which have performance assurance provisions that allow the counterparty to require collateral postings under certain conditions, including when requested on a reasonable basis due to a deterioration in our financial condition or nonperformance. A significant downgrade in our credit ratings, such as a downgrade to a level below investment grade, could result in counterparties requiring collateral postings under such adequate assurance provisions. The amount of credit support that we may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions and the amounts owed by or to the counterparty. At September 30, 2017, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts.

Cash Flow Activities


The following table summarizes our cash flows for the ninethree months ended September 30March 31, (in thousands):

Cash provided by (used in):20212020Variance
Operating activities$(386,086)$191,969 $(578,055)
Investing activities$(146,224)$(173,084)$26,860 
Financing activities$539,496 $25,621 $513,875 

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 2017Three Months Ended March 31, 2021 Compared to Year-to-Date 2016Three Months Ended March 31, 2020


Operating ActivitiesActivities:


Net cash provided by operating activities was $319$578 million for the nine months ended September 30, 2017, compared to net cash provided by operating activities of $209 million forlower than the same period in 2016 for a2020. The variance of $110 million. The varianceto the prior year was primarily attributable to:


•Cash earnings (net income plus non-cash adjustments) were $65$15 million higherlower for the ninethree months ended September 30, 2017March 31, 2021 compared to the same period in the prior year;year primarily driven by lower operating income at our Electric Utilities;


•Net cash outflowsinflows from changes in certain operating assets and liabilities were $17$563 million for the nine months ended September 30, 2017, compared to net cashlower, primarily attributable to:

◦Cash outflows of $44 million in the same period in the prior year. This $27 million variance 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 cash outflows decreased by approximately $29$560 million as a result of changes in our regulatory assets and liabilities primarily driven by incremental costs from Winter Storm Uri;

◦Cash inflows decreased by $23 million primarily as a prior year interest rate settlement;result of changes in natural gas in storage and lower collections of accounts receivable; and



◦Cash outflows decreased by $20 million as a result of increases in accounts payable and accrued liabilities primarily driven by payment timing of natural gas and power purchases and other working capital requirements.


Net cash outflows•Cash inflows increased by $14$0.8 million due to additional pension contributions made in the current year.for other operating activities.


Investing ActivitiesActivities:


Net cash used in investing activities was $256$27 million for the nine months ended September 30, 2017, compared to net cash used in investing activities of $1.5 billion forlower than the same period in 2016 for a variance of $1.2 billion. This variance was 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); and

Capital expenditures of approximately $256 million for the nine months ended September 30, 2017 compared to $334 million for the nine months ended September 30, 2016.2020. The variance to the prior year was due primarily attributable to:

•Capital expenditures of $146 million for the three months ended March 31, 2021 compared to higher$172 million for the same period in the prior year. Lower current year expenditures are driven by lower programmatic safety, reliability and integrity spending at our Gas Utilities and Electric Utilities segments and the prior year capital expendituresCorriedale wind project at our Electric Utilities primarily from generation investments at Colorado Electric, partially offsetsegment.

•Cash outflows decreased by higher current year capital expenditures at our Gas Utilities.$1.3 million for other investing activities.


42

Table of Contents
Financing ActivitiesActivities:


Net cash used in financing activities for the nine months ended September 30, 2017 was $63 million, compared to $841 million of net cash provided by financing activities forwas $514 million higher than the same period in 2016 for a2020. The variance to the prior year was primarily attributable to:

•Cash inflows increased $615 million due to borrowings of $904 million.short-term debt in excess of short-term and long-term debt repayments. This varianceincrease was primarily driven by:by $600 million net borrowings from our term loan;


Long-term borrowings•Cash inflows decreased by $1.8 billion$99 million due to the 2016 financings which consistedprior year issuance of $693common stock;

•Cash outflows increased $2.6 million due to increased dividends paid on common stock; and

•Cash outflows decreased by $0.7 million for other financing activities.


Capital Sources

Term Loan

See Note 5 of the Notes to Condensed Consolidated Financial Statements for information relating to our term loan.

Revolving Credit Facility and CP Program

Our Revolving Credit Facility and CP Program had the following borrowings, outstanding letters of credit, and available capacity (in millions):
CurrentShort-term borrowings at
Letters of Credit (a) at
Available Capacity at
Credit FacilityExpirationCapacityMarch 31, 2021March 31, 2021March 31, 2021
Revolving Credit Facility and CP ProgramJuly 30, 2023$750 $216 $17 $517 
__________
(a)    Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility.

The weighted average interest rate on short-term borrowings related to our Revolving Credit Facility and CP Program at March 31, 2021 was 0.23%. Short-term borrowing activity related to our Revolving Credit Facility and CP Program for the three months ended March 31, 2021 was:
(dollars in millions)
Maximum amount outstanding (based on daily outstanding balances)$311 
Average amount outstanding (based on daily outstanding balances)$199 
Weighted average interest rates0.24 %

Covenant Requirements

The Revolving Credit Facility and Wyoming Electric’s financing agreements contain covenant requirements. We were in compliance with these covenants as of March 31, 2021 See Note 5 of the Notes to Condensed Consolidated Financial Statements for more information.

Future Financing Plans

We will continue to assess debt and equity needs to support our capital investment plans and other key strategic objectives. In 2021, we expect to fund our capital plan and strategic objectives by using cash generated from operating activities, our Revolving Credit Facility and CP Program, and issuing $100 million to $120 million of net proceeds fromcommon stock under the August 19, 2016 public debt offering used to refinance the debt assumedATM. As discussed in the SourceGas Acquisition, $500 millionRecent Developments above and in further detail in Note 5 of proceeds from the August 9, 2016 term loan, $546 million of net proceeds from our January 13, 2016 public debt offering usedNotes to partially finance the SourceGas Acquisition and proceeds from a $29Condensed Consolidated Financial Statements, on February 24, 2021, we entered into an $800 million term loan usedmaturing on November 24, 2021. We expect to fundrefinance a portion of the early settlementterm loan with longer-term debt.


43

Table of a gas gathering contract;Contents

Credit Ratings
Payments on long-term debt decreased by $1.1 billion due
After assessing the current operating performance, liquidity and the credit ratings of the Company, management believes that the Company will have access to the 2016 refinancingcapital markets at prevailing market rates for companies with comparable credit ratings.

The following table represents the credit ratings and outlook and risk profile of BHC at March 31, 2021:
Rating AgencySenior Unsecured RatingOutlook
S&P (a)
BBB+Stable
Moody’s (b)
Baa2Stable
Fitch (c)
BBB+Stable
__________
(a)    On April 10, 2020, S&P reported BBB+ rating and maintained a Stable outlook.
(b)    On December 21, 2020, Moody’s reported Baa2 rating and maintained a Stable outlook.
(c)    On August 20, 2020, Fitch reported BBB+ rating and maintained a Stable outlook.

The following table represents the $760 millioncredit ratings of long-term debt assumedSouth Dakota Electric at March 31, 2021:
Rating AgencySenior Secured Rating
S&P (a)
A
Moody’s (b)
A1
Fitch (c)
A
__________
(a)    On April 16, 2020, S&P reported A rating.
(b)    On December 21, 2020, Moody’s reported A1 rating.
(c)    On August 20, 2020, Fitch reported A rating.


Capital Requirements

Capital Expenditures
ActualForecasted
Capital Expenditures by Segment
Three Months Ended March 31, 2021 (a)
2021 (b)
2022202320242025
(in millions)
Electric Utilities$52 $240 $180 $143 $156 $154 
Gas Utilities73 377 347 339 330 326 
Power Generation3 10 9 6 4 5 
Mining1 9 9 9 9 10 
Corporate and Other3 11 5 13 13 13 
Incremental Projects (c)
— — 50 100 100 100 
$132 $647 $600 $610 $612 $608 
__________
(a)    Includes accruals for property, plant and equipment as disclosed in supplemental cash flow information 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.

ProceedsCondensed Consolidated Statements of $216 million from the sale of a 49.9% noncontrolling interest of Colorado IPP that took placeCash Flows in the prior year;Condensed Consolidated Financial Statements.

(b)    Includes actual capital expenditures for the three months ended March 31, 2021.
Net short-term borrowings increased(c)    These represent projects that are being evaluated by $130 million primarily due to CP borrowings used to pay down long-term debt;our segments for timing, cost and other factors.

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$36 million for the ninethree months ended September 30, 2017,March 31, 2021, or $0.445$0.565 per share per quarter. On November 1, 2017,April 26, 2021, our board of directors declared a quarterly dividend of $0.475$0.565 per share payable DecemberJune 1, 2017, which brings our total2021, 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.


44


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

Our Revolving Credit Facility had the following borrowings, outstanding letters of credit, and available capacity (in millions):
Contents
  CurrentRevolver Borrowings atCP Program Borrowings atLetters of Credit atAvailable Capacity at
Credit 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 financing activity for the nine months ended September 30, 2017 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 for the Revolving Credit Facility are for the first 29 days of the year after which all borrowings were through the CP Program.

The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on certain liens, restrictions on certain transactions, and maintenance of a certain Consolidated Indebtedness to Capitalization Ratio. Under the Revolving Credit Facility, our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness, which includes letters of credit, certain guarantees issued and excludes RSNs by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interests in subsidiaries and includes the aggregate outstanding amount of the RSNs. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. We were in compliance with these covenants as of 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 size of the ATM equity offering program to an aggregate value of up to $300 million. We did not issue any shares of common stock under our ATM equity offering program.

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 and 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’s financing agreements require Cheyenne Light to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of September 30, 2017, we were in compliance with these covenants.

There have been no other material changes in 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.

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:
Rating AgencySenior Unsecured RatingOutlook
S&P (a)
BBBStable
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.

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

Rating AgencySenior Secured Rating
S&PA-
Moody’sA1
FitchA

There were no rating changes for Black Hills Power from previously disclosed ratings.



Capital Requirements

Capital Expenditures

Actual and forecasted capital requirements are as follows (in thousands):
 Expenditures for the Total Total Total
 
Nine Months Ended September 30, 2017 (a)
 
2017 Planned
Expenditures (b)
 
2018 Planned
Expenditures
 
2019 Planned
Expenditures
Electric Utilities$113,199
 $134,000
 $149,000
 $193,000
Gas Utilities122,482
 187,000
 263,000
 279,000
Power Generation1,899
 1,000
 2,000
 14,000
Mining4,315
 7,000
 7,000
 7,000
Oil and Gas (c)
16,951
 21,000
 —
 —
Corporate5,075
 7,000
 9,000
 13,000
 $263,921
 $357,000
 $430,000
 $506,000
__________
(a)    Expenditures for the nine months ended September 30, 2017 include the impact of accruals for property, plant and equipment.
(b)    Includes actual capital expenditures for the nine months ended September 30, 2017.
(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 have updated our planned 2018 and 2019 capital expenditures 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.

We continue to evaluate potential future acquisitions and other growth opportunities when they arise. As a result, capital expenditures may vary significantly from the estimates identified above.

ContractualUnconditional Purchase Obligations


There have been no significant changes in contractual obligations from those previously disclosed in See Note 19 of our Notes to the Consolidated Financial Statements in our 2016 Annual Report on Form 10-K except for those described in Note 163 of the Notes to Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report on Form 10-Q.for recent updates to our purchase obligations.



Guarantees

Critical Accounting Policies Involving Significant Estimates

There have been no significantmaterial changes to guaranteesin our critical accounting estimates from those previously disclosed in Note 20 of the Notes to the Consolidated Financial Statementsreported in our 20162020 Annual Report on Form 10-K. We continue to closely monitor the impacts of COVID-19 and Winter Storm Uri on our critical accounting estimates including, but not limited to, collectibility of customer receivables, recoverability through 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 2020 Annual Report on Form 10-K.



New Accounting Pronouncements


Other than the pronouncements reported in our 20162020 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.





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 & 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 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, 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 2016 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our 2016 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 exposedThere have been no material changes 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, optionsour quantitative and basis swaps to reduce our customers’ underlying exposure to these fluctuations. The fair valuequalitative disclosures about market risk previously 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

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.10-K.


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.March 31, 2021. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at September 30, 2017.March 31, 2021.


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,March 31, 2021, 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.






45
BLACK HILLS CORPORATION

Table of Contents
Part II — Other InformationPART II.    OTHER INFORMATION



ITEM 1.Legal Proceedings

ITEM 1.LEGAL PROCEEDINGS

For information regarding legal proceedings, see Note 193 in Item 8 of our 20162020 Annual Report on Form 10-K and Note 163 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 16 is incorporated by reference into this item.10-Q.


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 20162020 Annual Report on Form 10-K filed with the SEC, except those stated below:10-K.


While we plan to sell Black Hills Exploration and Production, Inc. (”BHEP”), our oil and gas exploration 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 level 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 our financial condition and results of operations.

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

ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
There were no unregistered
The following table contains monthly information about our acquisitions of equity securities sold duringfor the ninethree months ended September 30, 2017.March 31, 2021:
Period
Total Number of Shares Purchased (a)
Average Price Paid per ShareTotal Number of Shares Purchased as Part of Publicly Announced Plans or ProgramsMaximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
January 1, 2021 - January 31, 2021116.0$60.06 — — 
February 1, 2021 - February 28, 202111,696.061.92 — — 
March 1, 2021 - March 31, 20211.459.86 — — 
Total11,813 $61.90 — — 
_____________
(a)    Shares were acquired under the share withholding provisions of the Omnibus Incentive Plan for payment of taxes associated with the vesting of various equity compensation plans.



ITEM 4.Mine Safety Disclosures

ITEM 4.        MINE SAFETY DISCLOSURES

Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 95 of this Quarterly Report on Form 10-Q.


ITEM 5.Other Information

None.


ITEM 6.        EXHIBITS

Exhibits filed herewithin are designated by an asterisk (*). All exhibits not so designated are incorporated by reference to a prior filing, as indicated.

ITEM 6.Exhibit NumberExhibitsDescription

Exhibit NumberDescription
Exhibit 2.1*
Purchase and Sale Agreement by and among Alinda Gas Delaware LLC, Alinda Infrastructure Fund I, L.P. and Aircraft Services Corporation, as Sellers, and Black Hills Utility Holdings, Inc., as Buyer dated as of July 12, 2015 (filed as Exhibit 2.1 to the Registrant’s Form 8-K filed on July 14, 2015). First Amendment to Purchase and Sale Agreement effective December 10, 2015, by and among, Alinda Gas Delaware LLC, Alinda Infrastructure Fund I L.P. and Aircraft Services Corporation, as Sellers, and Black Hills Utility Holdings, Inc., as Buyer (filed as Exhibit 2.2 to the Registrant’s Form 10-K for 2015).
Exhibit 2.2*
Option Agreement by and among Aircraft Services Corporation, as ASC, SourceGas Holdings LLC, as the Company and Black Hills Utility Holdings, Inc., as Buyer (filed as Exhibit 2.2 to the Registrant’s Form 8-K filed on July 14, 2015).
Exhibit 2.3*
Guaranty of Black Hills Corporation in favor of Alinda Gas Delaware LLC, Alinda Infrastructure Fund I, L.P. and Aircraft Services Corporation, dated as of July 12, 2015 (filed as Exhibit 2.3 to the Registrant’s Form 8-K filed on July 14, 2015).
Exhibit 3.1*3.1
Exhibit 3.2*3.2
Exhibit 4.1*4.1
4.1.1
4.1.2
4.1.3
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Table of Contents
4.1.4
4.1.5
4.1.6
4.1.7
Exhibit 4.2*4.1.8
4.2
4.2.1
4.2.2
4.2.3
Exhibit 4.3*4.3
4.3.1
4.3.2
Exhibit 4.4*4.4

Exhibit 4.5*
Purchase Contract and Pledge Agreement dated as of November 23, 2015 between Black Hills Corporation and U.S. Bank National Association, as purchase contract agent, collateral agent, custodial agent and securities intermediary (filed as Exhibit 4.4 to the Registrant’s Form 8-K filed on November 23, 2015).
Exhibit 4.6*
Indenture dated as of April 16, 2007 between SourceGas LLC and U.S. Bank National Association, as Trustee (relating to $325 million, 5.90% Senior Notes due 2017) (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on March 18, 2016).
Exhibit 4.7*
Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the Registrant’s Form 10-K for 2000).
10.1
Exhibit 31.131.1*
Exhibit 31.231.2*
Exhibit 32.132.1*
Exhibit 32.232.2*
Exhibit 9595*
101.INS*XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*XBRL Taxonomy Extension Schema Document
101.CAL*XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*XBRL Taxonomy Extension Label Linkbase Document
101.PRE*XBRL Taxonomy Extension Presentation Linkbase Document
104*Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101Financial Statements for XBRL Format.101)
__________
*Previously filed as part of the filing indicated and incorporated by reference herein.
†Indicates a board of director or management compensatory plan.



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Table of Contents
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, 2017May 5, 2021



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