BKH 10-Q Quarterly Report Sept. 30, 2020

BLACK HILLS CORP /SD/

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Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2020

☐ 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 ☐

Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer

Accelerated Filer

☐

Non-accelerated Filer

☐

Smaller Reporting Company

☐

Emerging Growth Company

☐

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

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes ☐ No ☒

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common stock of $1.00 par value

BKH

New 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.

Class

Outstanding at October 31, 2020

Common stock, $1.00 par value

62,746,692

Table of Contents


TABLE OF CONTENTS
		Page
Glossary of Terms and Abbreviations		4

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements - unaudited	7
	Condensed Consolidated Statements of Income	7
	Condensed Consolidated Statements of Comprehensive Income	8
	Condensed Consolidated Balance Sheets	9
	Condensed Consolidated Statements of Cash Flows	11
	Condensed Consolidated Statements of Equity	12
	Notes to Condensed Consolidated Financial Statements	14
	Note 1. Management’s Statement	14
	Note 2. Revenue	16
	Note 3. Business Segment Information	18
	Note 4. Selected Balance Sheet Information	20
	Note 5. Regulatory Matters	22
	Note 6. Earnings Per Share	24
	Note 7. Notes Payable, Current Maturities and Debt	24
	Note 8. Equity	25
	Note 9. Risk Management and Derivatives	26
	Note 10. Fair Value Measurements	29
	Note 11. Other Comprehensive Income (Loss)	32
	Note 12. Employee Benefit Plans	33
	Note 13. Commitments and Contingencies	35
	Note 14. Income Taxes	35
	Note 15. Investments	36
	Note 16. Subsequent Events	36

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TABLE OF CONTENTS
		Page
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
	Executive Summary	37
	Results of Operations - Consolidated Summary and Overview	41
	Non-GAAP Financial Measure	42
	Electric Utilities Segment	43
	Gas Utilities Segment	47
	Regulatory Matters	50
	Power Generation Segment	50
	Mining Segment	52
	Corporate and Other	52
	Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax (Expense)	53
	Critical Accounting Policies Involving Significant Accounting Estimates	54
	Liquidity and Capital Resources	55
	Cash Flow Activities	55
	Dividends	56
	Financing Transactions, Short-Term Liquidity and Credit Ratings	56
	Capital Requirements	58
	Contractual Obligations	58
	Off-Balance Sheet Commitments	58
	New Accounting Pronouncements	58
	Forward-Looking Information	59
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	59
Item 4.	Controls and Procedures	60

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	60
Item 1A.	Risk Factors	60

Item 4.	Mine Safety Disclosures	61

Item 6.	Exhibits	61

Signatures		63

Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS

The following terms and abbreviations appear in the text of this report and have the definitions described below:


AFUDC			Allowance for Funds Used During Construction

AOCI			Accumulated Other Comprehensive Income (Loss)

Arkansas Gas			Black 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).


ASC			Accounting Standards Codification
ASU			Accounting Standards Update issued by the FASB
ATM			At-the-market equity offering program

Availability			The availability factor of a power plant is the percentage of the time that it is available to provide energy.

BHC			Black Hills Corporation; the Company



Black Hills Colorado IPP			Black Hills Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Electric Generation
Black Hills Electric Generation			Black 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 Energy			The name used to conduct the business of our utility companies












Black Hills Energy Services			Black Hills Energy Services Company, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas commodity supply for the Choice Gas Programs (doing business as Black Hills Energy).
Black Hills Non-regulated Holdings			Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Power			Black 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 Holdings			Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills Wyoming			Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation







CARES Act			Coronavirus Aid, Relief, and Economic Security Act, signed on March 27, 2020, which is a tax and spending package intended to provide additional economic relief and address the impact of the COVID-19 pandemic.

Cheyenne Light			Cheyenne 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.

Choice Gas Program			Regulator-approved programs in Wyoming and Nebraska that allow certain utility customers to select their natural gas commodity supplier, providing for the unbundling of the commodity service from the distribution delivery service.

City of Colorado Springs			Colorado Springs, Colorado
City of Gillette			Gillette, Wyoming


Colorado Electric			Black Hills Colorado Electric, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing electric service to customers in Colorado (doing business as Black Hills Energy).
Colorado Gas			Black 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).

Consolidated Indebtedness to Capitalization Ratio			Any indebtedness outstanding at such time, divided by capital at such time. Capital being consolidated net worth (excluding noncontrolling interest) plus consolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit Facility.
Cooling Degree Day (CDD)			A cooling degree day is equivalent to each degree that the average of the high and low temperatures 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 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.
Corriedale			Wind project near Cheyenne, Wyoming, that will be a 52.5 MW wind farm jointly owned by South Dakota Electric and Wyoming Electric and will serve as the dedicated wind energy supply to the Renewable Ready program.

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COVID-19			The official name for the 2019 novel coronavirus disease announced on February 11, 2020, by the World Health Organization, that is causing a global pandemic

CP Program			Commercial Paper Program
CPUC			Colorado Public Utilities Commission


CVA			Credit Valuation Adjustment

Dodd-Frank			Dodd-Frank Wall Street Reform and Consumer Protection Act
DRSPP			Dividend Reinvestment and Stock Purchase Plan
Dth			Dekatherm. A unit of energy equal to 10 therms or approximately one million British thermal units (MMBtu)






FASB			Financial Accounting Standards Board
FERC			United States Federal Energy Regulatory Commission
Fitch			Fitch Ratings Inc.
GAAP			Accounting principles generally accepted in the United States of America




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 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.
HomeServe			Repair service plans offered to electric and natural gas residential customers that cover parts and labor to repair electrical, gas, heating, cooling, and water systems.
ICFR			Internal Controls over Financial Reporting
Iowa Gas			Black 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).
IPP			Independent Power Producer
IRS			United States Internal Revenue Service

Kansas Gas			Black 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).







MMBtu			Million British thermal units

Moody’s			Moody’s Investors Service, Inc.

MW			Megawatt
MWh			Megawatt-hour
Nebraska Gas			Black Hills Nebraska Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Nebraska (doing business as Black Hills Energy).





NPSC			Nebraska Public Service Commission




OCA			Office of Consumer Advocate


OCC			Office of Consumer Counsel
OCI			Other Comprehensive Income
PPA			Power Purchase Agreement
PRPA			Platte River Power Authority
PSA			Power Sales Agreement
Pueblo Airport Generation			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 Advantage			A 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 Ready			Voluntary renewable energy subscription program for large commercial, industrial and governmental agency customers in South Dakota and Wyoming.

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Revolving Credit Facility			Our $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which was amended and restated on July 30, 2018, and now terminates on July 30, 2023.

SDPUC			South Dakota Public Utilities Commission
SEC			United States Securities and Exchange Commission

Service Guard Comfort Plan			New plan that consolidated Service Guard and Customer Appliance Protection Plan (CAPP) and provides similar home appliance repair services through on-going monthly service agreements to residential utility customers.
S&P			Standard and Poor’s, a division of The McGraw-Hill Companies, Inc.
South Dakota Electric			Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and Wyoming (doing business as Black Hills Energy).
SSIR			System Safety and Integrity Rider


TCJA			Tax Cuts and Jobs Act
Tech Services			Non-regulated product lines within Black Hills Corporation that 1) provide electrical system construction services to large industrial customers of our electric utilities and 2) serve gas transportation customers throughout its service territory by constructing and maintaining customer-owner gas infrastructure facilities, typically through one-time contracts.


Utilities			Black Hills’ Electric and Gas Utilities
Wind Capacity Factor			Measures the amount of electricity a wind turbine produces in a given time period relative to its maximum potential
WPSC			Wyoming Public Service Commission
WRDC			Wyodak Resources Development Corporation, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings (doing business as Black Hills Energy)
Wygen I			A mine-mouth, coal-fired power plant with a total capacity of 90 MW located at our Gillette, Wyoming energy complex. We own 76.5% of the plant and Municipal Energy Agency of Nebraska (MEAN) owns the remaining 23.5%.
Wyodak Plant			Wyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, owned 80% by PacifiCorp and 20% by South Dakota Electric. Our WRDC mine supplies all of the fuel for the plant.
Wyoming Electric			Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in the Cheyenne, Wyoming area (doing business as Black Hills Energy).
Wyoming Gas			Black Hills Wyoming Gas, LLC, an indirect and wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Wyoming (doing business as Black Hills Energy).

Table of Contents

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,
	2020		2019		2020		2019
	(in thousands, except per share amounts)

Revenue	$	346,590	$	325,548	$	1,210,554	$	1,257,246

Operating expenses:
Fuel, purchased power and cost of natural gas sold	71,686		73,544		331,194		413,486
Operations and maintenance	122,759		116,583		365,533		365,116
Depreciation, depletion and amortization	56,348		51,884		169,413		154,507
Taxes - property and production	13,563		12,986		42,062		39,454

Total operating expenses	264,356		254,997		908,202		972,563

Operating income	82,234		70,551		302,352		284,683

Other income (expense):

Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	( 36,521 )		( 34,000 )		( 108,067 )		( 103,677 )
Interest income	480		513		1,028		1,208
Impairment of investment	—		( 19,741 )		( 6,859 )		( 19,741 )
Other income (expense), net	( 1,193 )		580		( 703 )		55
Total other income (expense)	( 37,234 )		( 52,648 )		( 114,601 )		( 122,155 )

Income before income taxes	45,000		17,903		187,751		162,528
Income tax (expense)	( 4,651 )		( 2,508 )		( 25,484 )		( 22,078 )
Net income	40,349		15,395		162,267		140,450
Net income attributable to noncontrolling interest	( 4,066 )		( 3,655 )		( 11,844 )		( 10,319 )
Net income available for common stock	$	36,283	$	11,740	$	150,423	$	130,131


Earnings per share of common stock:
Earnings per share, Basic	$	0.58	$	0.19	$	2.41	$	2.15
Earnings per share, Diluted	$	0.58	$	0.19	$	2.41	$	2.15

Weighted average common shares outstanding:
Basic	62,575		60,976		62,310		60,458
Diluted	62,630		61,104		62,362		60,578

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


(unaudited)	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in thousands)

Net income	$	40,349	$	15,395	$	162,267	$	140,450

Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (net of tax of $ 0 ,$ 0 , $( 17 ) and $ 0 , respectively)	—		—		55		—
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $ 6 , $ 3 , $ 19 and $ 13 , respectively)	( 18 )		( 16 )		( 60 )		( 45 )
Reclassification adjustments of benefit plan liability - net gain (net of tax of $( 149 ), $( 92 ), $( 426 ) and $( 197 ), respectively)	448		( 9 )		1,365		327
Derivative instruments designated as cash flow hedges:
Reclassification of net realized losses on settled/amortized interest rate swaps (net of tax of $( 168 ), $( 165 ), $( 508 ) and $( 500 ), respectively)	544		548		1,630		1,639
Net unrealized gains (losses) on commodity derivatives (net of tax of $( 112 ), $ 35 , $( 44 ) and $ 100 , respectively)	401		( 115 )		181		( 334 )
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $( 41 ), $( 5 ), $( 172 ), and $ 142 , respectively)	137		124		562		( 366 )
Other comprehensive income, net of tax	1,512		532		3,733		1,221

Comprehensive income	41,861		15,927		166,000		141,671
Less: comprehensive income attributable to noncontrolling interest	( 4,066 )		( 3,655 )		( 11,844 )		( 10,319 )
Comprehensive income available for common stock	$	37,795	$	12,272	$	154,156	$	131,352

See Note 11 for additional disclosures.

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


(unaudited)	As of
	September 30, 2020		December 31, 2019
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	6,955	$	9,777
Restricted cash and equivalents	4,257		3,881
Accounts receivable, net	160,478		255,805
Materials, supplies and fuel	126,358		117,172
Derivative assets, current	2,001		342
Income tax receivable, net	20,828		16,446
Regulatory assets, current	49,493		43,282
Other current assets	33,287		26,479
Total current assets	403,657		473,184

Investments	15,659		21,929

Property, plant and equipment	7,128,387		6,784,679
Less: accumulated depreciation and depletion	( 1,276,410 )		( 1,281,493 )
Total property, plant and equipment, net	5,851,977		5,503,186

Other assets:
Goodwill	1,299,454		1,299,454
Intangible assets, net	12,242		13,266
Regulatory assets, non-current	221,743		228,062
Other assets, non-current	24,318		19,376
Total other assets, non-current	1,557,757		1,560,158

TOTAL ASSETS	$	7,829,050	$	7,558,457

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Continued)


(unaudited)	As of
	September 30, 2020		December 31, 2019
	(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	152,010	$	193,523
Accrued liabilities	244,010		226,767
Derivative liabilities, current	1,439		2,254
Regulatory liabilities, current	22,282		33,507
Notes payable	84,320		349,500
Current maturities of long-term debt	9,871		5,743
Total current liabilities	513,932		811,294

Long-term debt, net of current maturities	3,526,894		3,140,096

Deferred credits and other liabilities:
Deferred income tax liabilities, net	398,136		360,719
Regulatory liabilities, non-current	505,317		503,145
Benefit plan liabilities	144,049		154,472
Other deferred credits and other liabilities	120,522		124,662
Total deferred credits and other liabilities	1,168,024		1,142,998

Commitments and contingencies (See Notes 7, 9, 12, 13)

Equity:
Stockholders’ equity —
Common stock $ 1 par value; 100,000,000 shares authorized; issued 62,773,015 and 61,480,658 shares, respectively	62,773		61,481
Additional paid-in capital	1,655,912		1,552,788
Retained earnings	828,993		778,776
Treasury stock, at cost – 24,897 and 3,956 shares, respectively	( 1,710 )		( 267 )
Accumulated other comprehensive income (loss)	( 26,922 )		( 30,655 )
Total stockholders’ equity	2,519,046		2,362,123
Noncontrolling interest	101,154		101,946
Total equity	2,620,200		2,464,069

TOTAL LIABILITIES AND TOTAL EQUITY	$	7,829,050	$	7,558,457

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,
	2020		2019
Operating activities:	(in thousands)
Net income	$	162,267	$	140,450
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	169,413		154,507
Deferred financing cost amortization	5,523		6,326
Impairment of investment	6,859		19,741
Stock compensation	2,696		8,332
Deferred income taxes	28,502		24,381
Employee benefit plans	9,294		7,965
Other adjustments, net	7,910		9,192
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	( 10,905 )		( 4,126 )
Accounts receivable and other current assets	75,960		115,325
Accounts payable and other current liabilities	( 11,136 )		( 83,436 )
Regulatory assets - current	1,954		12,455
Regulatory liabilities - current	( 17,686 )		( 15,644 )
Contributions to defined benefit pension plans	( 12,700 )		( 12,700 )
Other operating activities, net	1,508		3,307
Net cash provided by operating activities	419,459		386,075

Investing activities:
Property, plant and equipment additions	( 535,993 )		( 592,537 )
Other investing activities	6,269		( 735 )
Net cash (used in) investing activities	( 529,724 )		( 593,272 )

Financing activities:
Dividends paid on common stock	( 99,999 )		( 91,779 )
Common stock issued	99,316		101,361
Net (payments) borrowings of short-term debt	( 265,180 )		109,280
Long-term debt - issuances	400,000		400,000
Long-term debt - repayments	( 7,163 )		( 304,307 )
Distributions to noncontrolling interest	( 12,636 )		( 12,736 )
Other financing activities	( 6,519 )		( 1,992 )
Net cash provided by financing activities	107,819		199,827

Net change in cash, restricted cash and cash equivalents	( 2,446 )		( 7,370 )

Cash, restricted cash and cash equivalents at beginning of period	13,658		24,145
Cash, restricted cash and cash equivalents at end of period	$	11,212	$	16,775

Supplemental cash flow information:
Cash (paid) refunded during the period:
Interest (net of amounts capitalized)	$	( 87,453 )	$	( 99,375 )
Income taxes	$	1,256	$	2,255
Non-cash investing and financing activities:
Accrued property, plant and equipment purchases at September 30	$	86,474	$	86,661

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY


(unaudited)	Common Stock			Treasury Stock
(in thousands except share amounts)	Shares	Value		Shares	Value		Additional Paid in Capital		Retained Earnings		AOCI		Non controlling Interest		Total
December 31, 2019	61,480,658	$	61,481	3,956	$	( 267 )	$	1,552,788	$	778,776	$	( 30,655 )	$	101,946	$	2,464,069
Net income available for common stock	—	—		—	—		—		93,174		—		4,050		97,224
Other comprehensive income (loss), net of tax	—	—		—	—		—		—		1,273		—		1,273


Dividends on common stock ($ 0.535 per share)	—	—		—	—		—		( 32,902 )		—		—		( 32,902 )
Share-based compensation	69,378	69		20,700	( 1,658 )		2,263		—		—		—		674

Issuance of common stock	1,222,942	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, 2020	62,772,978	$	62,773	24,656	$	( 1,925 )	$	1,652,861	$	838,841	$	( 29,382 )	$	101,255	$	2,624,423
Net income available for common stock	—	—		—	—		—		20,966		—		3,728		24,694
Other comprehensive income (loss), net of tax	—	—		—	—		—		—		948		—		948


Dividends on common stock ($ 0.535 per share)	—	—		—	—		—		( 33,538 )		—		—		( 33,538 )
Share-based compensation	18	—		1,743	46		1,781		—		—		—		1,827


Issuance costs	—	—		—	—		( 79 )		—		—		—		( 79 )





Distributions to noncontrolling interest	—	—		—	—		—		—		—		( 3,779 )		( 3,779 )
June 30, 2020	62,772,996	$	62,773	26,399	$	( 1,879 )	$	1,654,563	$	826,269	$	( 28,434 )	$	101,204	$	2,614,496
Net income available for common stock	—	—		—	—		—		36,283		—		4,066		40,349
Other comprehensive income, net of tax	—	—		—	—		—		—		1,512		—		1,512
Dividends on common stock ( 0.535 per share)	—	—		—	—		—		( 33,559 )		—		—		( 33,559 )
Share-based compensation	19	—		( 1,502 )	169		1,468		—		—		—		1,637


Issuance costs	—	—		—	—		( 119 )		—		—		—		( 119 )
Distributions to noncontrolling interest	—	—		—	—		—		—		—		( 4,116 )		( 4,116 )
September 30, 2020	62,773,015	$	62,773	24,897	$	( 1,710 )	$	1,655,912	$	828,993	$	( 26,922 )	$	101,154	$	2,620,200

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	Common Stock			Treasury Stock
(in thousands except share amounts)	Shares	Value		Shares	Value		Additional Paid in Capital		Retained Earnings		AOCI		Non controlling Interest		Total
December 31, 2018	60,048,567	$	60,049	44,253	$	( 2,510 )	$	1,450,569	$	700,396	$	( 26,916 )	$	105,835	$	2,287,423
Net income available for common stock	—	—		—	—		—		103,808		—		3,554		107,362
Other comprehensive income (loss), net of tax	—	—		—	—		—		—		457		—		457


Dividends on common stock ($ 0.505 per share)	—	—		—	—		—		( 30,332 )		—		—		( 30,332 )
Share-based compensation	48,956	49		( 20,497 )	1,078		( 589 )		—		—		—		538
Tax effect of share-based compensation	—	—		—	—		—		—		—		—		—
Issuance of common stock	280,497	280		—	—		19,719		—		—		—		19,999
Issuance costs	—	—		—	—		( 289 )		—		—		—		( 289 )


Implementation of ASU 2016-02 Leases	—	—		—	—		—		3,390		—		—		3,390


Distributions to noncontrolling interest	—	—		—	—		—		—		—		( 4,846 )		( 4,846 )
March 31, 2019	60,378,020	$	60,378	23,756	$	( 1,432 )	$	1,469,410	$	777,262	$	( 26,459 )	$	104,543	$	2,383,702
Net income available for common stock	—	—		—	—		—		14,583		—		3,110		17,693
Other comprehensive income, net of tax	—	—		—	—		—		—		232		—		232
Dividends on common stock ($ 0.505 per share)	—	—		—	—		—		( 30,620 )		—		—		( 30,620 )
Share-based compensation	54,767	54		1,603	( 112 )		3,948		—		—		—		3,890
Tax effect of share-based compensation	—	—		—	—		—		—		—		—		—
Issuance of common stock	658,598	659		—	—		49,342		—		—		—		50,001
Issuance costs	—	—		—	—		( 492 )		—		—		—		( 492 )
Implementation of ASU 2016-02 Leases	—	—		—	—		—		( 3 )		—		—		( 3 )
Distributions to noncontrolling interest	—	—		—	—		—		—		—		( 4,405 )		( 4,405 )
June 30, 2019	61,091,385	$	61,091	25,359	$	( 1,544 )	$	1,522,208	$	761,222	$	( 26,227 )	$	103,248	$	2,419,998
Net income available for common stock	—	—		—	—		—		11,740		—		3,655		15,395
Other comprehensive income, net of tax	—	—		—	—		—		—		532		—		532
Dividends on common stock ($ 0.505 per share)	—	—		—	—		—		( 30,827 )		—		—		( 30,827 )
Share-based compensation	18	—		1,213	( 92 )		1,769		—		—		—		1,677
Tax effect of share-based compensation	—	—		—	—		—		—		—		—		—
Issuance of common stock	389,237	390		—	—		29,611		—		—		—		30,001
Issuance costs	—	—		—	—		( 398 )		—		—		—		( 398 )
Implementation of ASU 2016-02 Leases	—	—		—	—		—		3		—		—		3
Distributions to noncontrolling interest	—	—		—	—		—		—		—		( 3,485 )		( 3,485 )
September 30, 2019	61,480,640	$	61,481	26,572	$	( 1,636 )	$	1,553,190	$	742,138	$	( 25,695 )	$	103,418	$	2,432,896

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BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s 2019 Annual Report on Form 10-K)

(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” 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 GAAP 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 included in our 2019 Annual Report on Form 10-K filed with the SEC.

Segment Reporting

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

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, 2020, December 31, 2019 and September 30, 2019 financial information. Certain industries in which we operate are highly seasonal and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements. In particular, the normal peak usage season for electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and nine months ended September 30, 2020 and September 30, 2019, and our financial condition as of September 30, 2020 and December 31, 2019 are not necessarily indicative of the results of operations and financial condition to be expected for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

Reclassification

We changed certain classifications of operating expenses on the Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2019 to conform with current year presentation. The prior year reclassifications, which are shown in the table below, did not impact previously reported operating income or net income.


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

COVID-19 Pandemic

In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the outbreak a national emergency. The U.S. government has deemed electric and natural gas utilities to be critical infrastructure sectors that provide essential services during this emergency. As a provider of essential services, the Company has an obligation to provide services to our customers. The Company remains focused on protecting the health of our employees and the communities in which we operate while assuring the continuity of our business operations.

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The Company’s Condensed Consolidated Financial Statements reflect estimates and assumptions made by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Condensed Consolidated Financial Statements and reported amounts of revenue and expenses during the reporting periods presented. The Company considered the impacts of COVID-19 on the assumptions and estimates used and determined that for the three and nine months ended September 30, 2020, there were no material adverse impacts on the Company’s results of operations.

Change in Accounting Principle - Pension Accounting Asset Method

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

Recently Issued Accounting Standards

Simplifying the Accounting for Income Taxes, ASU 2019-12

In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes, as part of its overall simplification initiative to reduce costs and complexity in applying accounting standards while maintaining or improving the usefulness of the information provided to users of the financial statements. Amendments include removal of certain exceptions to the general principles of ASC 740, Income Taxes , and simplification in several other areas such as accounting for a franchise tax (or similar tax) that is partially based on income. The new guidance is effective for interim and annual periods beginning after December 15, 2020 with early adoption permitted. We are currently reviewing this standard to assess the impact on our financial position, results of operations and cash flows.

Recently Adopted Accounting Standards

Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, ASU 2016-13

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

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

Simplifying the Test for Goodwill Impairment, ASU 2017-04

In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment, by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit. We adopted this standard prospectively on January 1, 2020. Adoption of this guidance did not have an impact on our financial position, results of operations or cash flows.

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

In August 2018, the FASB issued ASU 2018-15, Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract , which aligns the requirements for recording implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. As a result, certain categories of implementation costs that previously would have been charged to expense as incurred are now capitalized as prepayments and amortized over the term of the arrangement. We adopted this standard prospectively on January 1, 2020. Adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

(2) Revenue

Our revenue contracts generally provide for performance obligations that: are fulfilled and transfer control to customers over time; represent a series of distinct services that are substantially the same; involve the same pattern of transfer to the customer; and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice. 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 and nine months ended September 30, 2020 and 2019. Sales tax and other similar taxes are excluded from revenues.


Three Months Ended September 30, 2020	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues		Total
Customer types:	(in thousands)
Retail	$	169,505	$	94,367	$	—	$	14,668	$	( 8,100 )	$	270,440
Transportation	—		38,196		—		—		( 139 )		38,057
Wholesale	5,925		—		26,049		—		( 24,521 )		7,453
Market - off-system sales	9,535		36		—		—		( 1,904 )		7,667
Transmission/Other	15,653		10,277		—		—		( 5,235 )		20,695
Revenue from contracts with customers	$	200,618	$	142,876	$	26,049	$	14,668	$	( 39,899 )	$	344,312
Other revenues	224		1,053		469		568		( 36 )		2,278
Total revenues	$	200,842	$	143,929	$	26,518	$	15,236	$	( 39,935 )	$	346,590

Timing of revenue recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	14,668	$	( 8,100 )	$	6,568
Services transferred over time	200,618		142,876		26,049		—		( 31,799 )		337,744
Revenue from contracts with customers	$	200,618	$	142,876	$	26,049	$	14,668	$	( 39,899 )	$	344,312

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Three Months Ended September 30, 2019	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues		Total
Customer Types:
Retail	$	162,214	$	89,810	$	—	$	14,992	$	( 8,146 )	$	258,870
Transportation	—		29,019		—		—		( 195 )		28,824
Wholesale	8,210		—		16,119		—		( 14,414 )		9,915
Market - off-system sales	6,452		139		—		—		( 1,488 )		5,103
Transmission/Other	14,274		10,965		—		—		( 4,206 )		21,033
Revenue from contracts with customers	$	191,150	$	129,933	$	16,119	$	14,992	$	( 28,449 )	$	323,745
Other revenues	234		811		9,692		560		( 9,494 )		1,803
Total Revenues	$	191,384	$	130,744	$	25,811	$	15,552	$	( 37,943 )	$	325,548

Timing of Revenue Recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	14,992	$	( 8,146 )	$	6,846
Services transferred over time	191,150		129,933		16,119		—		( 20,303 )		316,899
Revenue from contracts with customers	$	191,150	$	129,933	$	16,119	$	14,992	$	( 28,449 )	$	323,745


Nine Months Ended September 30, 2020	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues		Total
Customer types:	(in thousands)
Retail	$	459,949	$	513,208	$	—	$	43,917	$	( 23,855 )	$	993,219
Transportation	—		113,096		—		—		( 416 )		112,680
Wholesale	14,947		—		77,234		—		( 72,609 )		19,572
Market - off-system sales	17,940		197		—		—		( 6,123 )		12,014
Transmission/Other	43,271		32,038		—		—		( 14,080 )		61,229
Revenue from contracts with customers	$	536,107	$	658,539	$	77,234	$	43,917	$	( 117,083 )	$	1,198,714
Other revenues	2,074		7,273		1,372		1,940		( 819 )		11,840
Total revenues	$	538,181	$	665,812	$	78,606	$	45,857	$	( 117,902 )	$	1,210,554

Timing of revenue recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	43,917	$	( 23,855 )	$	20,062
Services transferred over time	536,107		658,539		77,234		—		( 93,228 )		1,178,652
Revenue from contracts with customers	$	536,107	$	658,539	$	77,234	$	43,917	$	( 117,083 )	$	1,198,714

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Nine Months Ended September 30, 2019	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues		Total
Customer Types:
Retail	$	455,409	$	567,715	$	—	$	43,249	$	( 23,315 )	$	1,043,058
Transportation	—		102,159		—		—		( 903 )		101,256
Wholesale	23,334		—		46,650		—		( 40,923 )		29,061
Market - off-system sales	16,592		517		—		—		( 5,047 )		12,062
Transmission/Other	42,865		35,767		—		—		( 12,608 )		66,024
Revenue from contracts with customers	$	538,200	$	706,158	$	46,650	$	43,249	$	( 82,796 )	$	1,251,461
Other revenues	2,465		1,135		29,114		1,777		( 28,706 )		5,785
Total Revenues	$	540,665	$	707,293	$	75,764	$	45,026	$	( 111,502 )	$	1,257,246

Timing of Revenue Recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	43,249	$	( 23,315 )	$	19,934
Services transferred over time	538,200		706,158		46,650		—		( 59,481 )		1,231,527
Revenue from contracts with customers	$	538,200	$	706,158	$	46,650	$	43,249	$	( 82,796 )	$	1,251,461

Contract Balances

The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable further discussed in Note 4 .

(3) Business Segment Information

Segment and Corporate and Other information is as follows (in thousands):


Three Months Ended September 30, 2020	External Operating Revenue				Inter-company Operating Revenue				Total Revenues
	Contract Customers		Other Revenues		Contract Customers		Other Revenues
Segment:
Electric Utilities	$	194,941	$	224	$	5,677	$	—	$	200,842
Gas Utilities	141,275		863		1,601		190		143,929
Power Generation	1,528		414		24,521		55		26,518
Mining	6,568		777		8,100		( 209 )		15,236
Inter-company eliminations	—		—		( 39,899 )		( 36 )		( 39,935 )
Total	$	344,312	$	2,278	$	—	$	—	$	346,590

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Three Months Ended September 30, 2019	External Operating Revenue				Inter-company Operating Revenue				Total Revenues
	Contract Customers		Other Revenues		Contract Customers		Other Revenues
Segment:
Electric Utilities	$	185,811	$	234	$	5,339	$	—	$	191,384
Gas Utilities	129,385		810		549		—		130,744
Power Generation	1,703		531		14,415		9,162		25,811
Mining	6,846		228		8,146		332		15,552
Inter-company eliminations	—		—		( 28,449 )		( 9,494 )		( 37,943 )
Total	$	323,745	$	1,803	$	—	$	—	$	325,548



Nine Months Ended September 30, 2020	External Operating Revenue				Inter-company Operating Revenue				Total Revenues
	Contract Customers		Other Revenues		Contract Customers		Other Revenues
Segment:
Electric Utilities	$	518,641	$	2,074	$	17,466	$	—	$	538,181
Gas Utilities	655,386		7,083		3,153		190		665,812
Power Generation	4,625		1,206		72,609		166		78,606
Mining	20,062		1,477		23,855		463		45,857
Inter-company eliminations	—		—		( 117,083 )		( 819 )		( 117,902 )
Total	$	1,198,714	$	11,840	$	—	$	—	$	1,210,554



Nine Months Ended September 30, 2019	External Operating Revenue				Inter-company Operating Revenue				Total Revenues
	Contract Customers		Other Revenues		Contract Customers		Other Revenues
Segment:
Electric Utilities	$	521,614	$	2,465	$	16,586	$	—	$	540,665
Gas Utilities	704,188		1,134		1,971		—		707,293
Power Generation	5,725		1,401		40,924		27,714		75,764
Mining	19,934		785		23,315		992		45,026
Inter-company eliminations	—		—		( 82,796 )		( 28,706 )		( 111,502 )
Total	$	1,251,461	$	5,785	$	—	$	—	$	1,257,246

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Adjusted operating income (a) :
Electric Utilities	$	52,083	$	50,653	$	121,726	$	125,219
Gas Utilities	18,147		4,736		139,253		116,607
Power Generation	8,738		11,822		31,489		33,945
Mining	3,505		3,374		9,992		9,351
Corporate and Other	( 239 )		( 34 )		( 108 )		( 439 )
Operating income	82,234		70,551		302,352		284,683

Interest expense, net	( 36,041 )		( 33,487 )		( 107,039 )		( 102,469 )
Impairment of investment	—		( 19,741 )		( 6,859 )		( 19,741 )
Other income (expense), net	( 1,193 )		580		( 703 )		55
Income tax (expense)	( 4,651 )		( 2,508 )		( 25,484 )		( 22,078 )
Net income	40,349		15,395		162,267		140,450
Net income attributable to noncontrolling interest	( 4,066 )		( 3,655 )		( 11,844 )		( 10,319 )
Net income available for common stock	$	36,283	$	11,740	$	150,423	$	130,131

__________

(a) Adjusted operating income recognizes inter-segment revenues and costs for Colorado Electric’s PPA with Black Hills Colorado IPP on an accrual basis rather than as a finance lease. This presentation of segment information does not impact consolidated financial results.

Segment and Corporate and Other balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):


Total assets (net of inter-company eliminations) as of:	September 30, 2020		December 31, 2019
Segment:
Electric Utilities	$	3,040,064	$	2,900,983
Gas Utilities	4,201,325		4,032,339
Power Generation	403,491		417,715
Mining	75,752		77,175
Corporate and Other	108,418		130,245
Total assets	$	7,829,050	$	7,558,457

(4) Selected Balance Sheet Information

Accounts Receivable and Allowance for Credit Losses

Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:


	September 30, 2020		December 31, 2019
Accounts receivable, trade	$	108,351	$	144,747
Unbilled revenue	60,736		113,502
Less: Allowance for credit losses	( 8,609 )		( 2,444 )
Accounts receivable, net	$	160,478	$	255,805

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Changes to allowance for credit losses for the nine months ended September 30, 2020 and 2019, respectively, were as follows (in thousands):


	Balance at Beginning of Year		Additions Charged to Costs and Expenses			Recoveries and Other Additions		Write-offs and Other Deductions		Balance at September 30,
2020	$	2,444	$	8,471	(a)	$	3,720	$	( 6,026 )	$	8,609
2019	$	3,209	$	5,637		$	2,742	$	( 8,429 )	$	3,159

__________

(a) Due to the COVID-19 pandemic, all of our jurisdictions temporarily suspended disconnections for a period of time, which increased our accounts receivable arrears balances. As a result, we increased our allowance for credit losses and bad debt expense for the nine months ended September 30, 2020 by an incremental $ 3.7 million.

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

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:


	September 30, 2020		December 31, 2019
Materials and supplies	$	93,069	$	82,809
Fuel - Electric Utilities	1,745		2,425
Natural gas in storage	31,544		31,938
Total materials, supplies and fuel	$	126,358	$	117,172

Accrued Liabilities

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


	September 30, 2020		December 31, 2019
Accrued employee compensation, benefits and withholdings	$	65,309	$	62,837
Accrued property taxes	40,624		44,547
Customer deposits and prepayments	59,510		54,728
Accrued interest	46,044		31,868
Other (none of which is individually significant)	32,523		32,787
Total accrued liabilities	$	244,010	$	226,767

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(5) Regulatory Matters

We had the following regulatory assets and liabilities (in thousands) as of:



	September 30, 2020		December 31, 2019

Regulatory assets
Deferred energy and fuel cost adjustments (a)	$	35,878	$	34,088
Deferred gas cost adjustments (a)	3,670		1,540
Gas price derivatives (a)	499		3,328
Deferred taxes on AFUDC (b)	7,683		7,790
Employee benefit plan costs and related deferred taxes (c)	114,971		115,900
Environmental (a)	1,417		1,454

Loss on reacquired debt (a)	23,342		24,777
Renewable energy standard adjustment (a)	—		1,622
Deferred taxes on flow through accounting (c)	44,528		41,220
Decommissioning costs (b)	9,421		10,670
Gas supply contract termination (a)	4,027		8,485
Other regulatory assets (a)	25,800		20,470
Total regulatory assets	271,236		271,344
Less current regulatory assets	( 49,493 )		( 43,282 )
Regulatory assets, non-current	$	221,743	$	228,062

Regulatory liabilities
Deferred energy and gas costs (a)	$	14,443	$	17,278
Employee benefit plan costs and related deferred taxes (c)	40,719		43,349
Cost of removal (a)	169,426		166,727

Excess deferred income taxes (c)	286,055		285,438

Other regulatory liabilities (c)	16,956		23,860
Total regulatory liabilities	527,599		536,652
Less current regulatory liabilities	( 22,282 )		( 33,507 )
Regulatory liabilities, non-current	$	505,317	$	503,145

__________

(a) Recovery of costs, but we are not allowed a rate of return.

(b) In addition to recovery of costs, we are allowed a rate of return.

(c) In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base.

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Regulatory Activity

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

Colorado Gas

Rate Reviews and Jurisdictional Consolidation

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

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

TCJA

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. As such, the Company remeasured our deferred income taxes at the 21% federal tax rate as of December 31, 2017. In 2018, the Company successfully delivered the benefits from the TCJA to most of its utility customers.

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

Nebraska Gas

Jurisdictional Consolidation and Rate Review

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

Black Hills Wyoming and Wyoming Electric

Wygen I FERC Filing

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

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(6) Earnings Per Share

A reconciliation of share amounts used to compute earnings per share in the accompanying Condensed Consolidated Statements of Income was as follows (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019

Net income available for common stock	$	36,283	$	11,740	$	150,423	$	130,131

Weighted average shares - basic	62,575		60,976		62,310		60,458
Dilutive effect of:
Equity compensation	55		128		52		120
Weighted average shares - diluted	62,630		61,104		62,362		60,578

Earnings per share of common stock:
Earnings per share, Basic	$	0.58	$	0.19	$	2.41	$	2.15
Earnings per share, Diluted	$	0.58	$	0.19	$	2.41	$	2.15

The following securities were excluded from the diluted earnings per share computation because of their anti-dilutive nature (in thousands):


	Three Months Ended September 30,		Nine Months Ended September 30,
	2020	2019	2020	2019

Equity compensation	22	2	22	4
Restricted stock	49	—	40	1

Anti-dilutive shares	71	2	62	5

(7) Notes Payable, Current Maturities and Debt

We had the following short-term debt outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:


	September 30, 2020				December 31, 2019
	Balance Outstanding		Letters of Credit (a)		Balance Outstanding		Letters of Credit (a)
Revolving Credit Facility	$	—	$	24,588	$	—	$	30,274
CP Program	84,320		—		349,500		—
Total	$	84,320	$	24,588	$	349,500	$	30,274

_______________

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

Facility.

For the nine months ended September 30, 2020, we utilized a combination of our $ 750 million Revolving Credit Facility and CP Program to meet our business needs and support our capital investment plan. Our net short-term borrowings (payments) during the nine months ended September 30, 2020 were $( 265 ) million.

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Debt Covenants

Under our Revolving Credit Facility and term loan agreement, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Our Consolidated Indebtedness to Capitalization Ratio was calculated by dividing (i) consolidated indebtedness, which includes letters of credit and certain guarantees issued, by (ii) capital, which includes consolidated indebtedness plus consolidated net worth, which excludes noncontrolling interest in subsidiaries. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding.

Our Revolving Credit Facility and term loans require compliance with the following financial covenant, which we were in compliance with at September 30, 2020:

As of September 30, 2020

Covenant Requirement

Consolidated Indebtedness to Capitalization Ratio

59.3 %

Less than

65 %

Debt Offering

On June 17, 2020, we completed a public debt offering which consisted of $ 400 million of 2.50 % 10 -year senior unsecured notes due June 15, 2030. The proceeds were used to repay short-term debt and for working capital and general corporate purposes.

South Dakota Electric Series 94A Debt

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

(8) Equity

February 2020 Equity Issuance

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

Shelf Registration, DRSPP and ATM Activity

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

We did not issue any common shares under the ATM during the three and nine months ended September 30, 2020. During the three months ended September 30, 2019, we issued a total of 0.4 million shares of common stock under the ATM for proceeds of $ 30 million, net of $ 0.3 million in issuance costs. During the nine months ended September 30, 2019, we issued a total of 1.3 million shares of common stock under the ATM for proceeds of $ 99 million, net of $ 1.0 million in issuance costs.

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(9) Risk Management and Derivatives

Market and Credit Risk Disclosures

Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk.

Market Risk

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

• Commodity price risk associated with our retail natural gas, wholesale electric power marketing activities and our fuel procurement for several of our gas-fired generation assets which include market fluctuations due to unpredictable factors such as the COVID-19 pandemic, weather, market speculation, pipeline constraints, and other factors that may impact natural gas and electric energy supply and demand; and

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

Credit Risk

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

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

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

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

Derivatives and Hedging Activity

Our derivative and hedging activities included 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 10 .

Utilities

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

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

We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risk using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/or sales from October 2020 through May 2022. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price forward contracts to deliver gas to our Choice Gas Program customers. The gain or loss on these designated derivatives is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and reclassified into earnings in the same period that the underlying hedged item is recognized in earnings. Effectiveness of our hedging position is evaluated at 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 had the following net long positions as of:


		September 30, 2020		December 31, 2019
	Units	Notional Amounts	Maximum Term (months) (a)	Notional Amounts	Maximum Term (months) (a)
Natural gas futures purchased	MMBtus	1,930,000	6	1,450,000	12
Natural gas options purchased, net	MMBtus	8,320,000	6	3,240,000	3
Natural gas basis swaps purchased	MMBtus	1,780,000	6	1,290,000	12
Natural gas over-the-counter swaps, net (b)	MMBtus	4,525,100	20	4,600,000	24
Natural gas physical contracts, net (c)	MMBtus	23,350,287	13	13,548,235	12
Electric wholesale contracts (c)	MWh	55,225	3	—	0

__________

(a) Term reflects the maximum forward period hedged.

(b) As of September 30, 2020, 1,274,900 MMBtus of natural gas over-the-counter swaps purchases were designated as cash flow hedges.

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

Derivatives by Balance Sheet Classification

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

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The following table presents the fair value and balance sheet classification of our derivative instruments (in thousands) as of:


	Balance Sheet Location	September 30, 2020		December 31, 2019
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets, current	$	435	$	1
Noncurrent commodity derivatives	Other assets, non-current	94		3
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current	( 9 )		( 490 )
Noncurrent commodity derivatives	Other deferred credits and other liabilities	—		( 29 )
Total derivatives designated as hedges		$	520	$	( 515 )

Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets, current	$	1,566	$	341
Noncurrent commodity derivatives	Other assets, non-current	434		2
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current	( 1,430 )		( 1,764 )
Noncurrent commodity derivatives	Other deferred credits and other liabilities	—		( 63 )
Total derivatives not designated as hedges		$	570	$	( 1,484 )

Derivatives Designated as Hedges

The impacts of cash flow hedges on our Condensed Consolidated Statements of Comprehensive Income and Condensed Consolidated Statements of Income are presented below for the three and nine months ended September 30, 2020 and 2019. Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.


	Three Months Ended September 30,					Three Months Ended September 30,
	2020		2019			2020		2019
Derivatives in Cash Flow Hedging Relationships	Amount of (Gain)/Loss Recognized in OCI				Income Statement Location	Amount of Gain/(Loss) Reclassified from AOCI into Income
	(in thousands)					(in thousands)
Interest rate swaps	$	712	$	713	Interest expense	$	( 712 )	$	( 713 )
Commodity derivatives	691		( 21 )		Fuel, purchased power and cost of natural gas sold	( 178 )		( 129 )
Total	$	1,403	$	692		$	( 890 )	$	( 842 )


	Nine Months Ended September 30,					Nine Months Ended September 30,
	2020		2019			2020		2019
Derivatives in Cash Flow Hedging Relationships	Amount of (Gain)/Loss Recognized in OCI				Income Statement Location	Amount of Gain/(Loss) Reclassified from AOCI into Income
	(in thousands)					(in thousands)
Interest rate swaps	$	2,138	$	2,139	Interest expense	$	( 2,138 )	$	( 2,139 )
Commodity derivatives	959		( 942 )		Fuel, purchased power and cost of natural gas sold	( 734 )		508
Total	$	3,097	$	1,197		$	( 2,872 )	$	( 1,631 )

Based on September 30, 2020 prices, a $ 0.1 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

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Derivatives Not Designated as Hedges

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, 2020 and 2019. Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.



		Three Months Ended September 30,
		2020		2019
Derivatives Not Designated as Hedging Instruments	Income Statement Location	Amount of Gain/(Loss) on Derivatives Recognized in Income

Commodity derivatives - Electric	Fuel, purchased power and cost of natural gas sold	$	( 1,386 )	$	—
Commodity derivatives - Electric	Other income (expense), net	—		142
Commodity derivatives - Natural Gas	Fuel, purchased power and cost of natural gas sold	1,777		( 20 )
		$	391	$	122


		Nine Months Ended September 30,
		2020		2019
Derivatives Not Designated as Hedging Instruments	Income Statement Location	Amount of Gain/(Loss) on Derivatives Recognized in Income
		(in thousands)
Commodity derivatives - Electric	Fuel, purchased power and cost of natural gas sold	$	( 228 )	$	—
Commodity derivatives - Electric	Other income (expense), net	—		142
Commodity derivatives - Natural Gas	Fuel, purchased power and cost of natural gas sold	2,992		( 1,180 )
		$	2,764	$	( 1,038 )

As discussed above, financial instruments used in our regulated utilities are not designated as cash flow hedges. There is no earnings impact for our Gas Utilities because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory asset or Regulatory liability accounts related to these derivatives in our Gas Utilities were $ 0.5 million and $ 3.3 million as of September 30, 2020 and December 31, 2019, respectively. For our Electric Utilities, the unrealized gains and losses arising from these derivatives are recognized in the Condensed Consolidated Statements of Income.

(10) Fair Value Measurements

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

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

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

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

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

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

Recurring Fair Value Measurements

Derivatives

The commodity contracts for our Utilities segments are valued using the market approach and include forward strip pricing at liquid delivery points, exchange-traded futures, options, basis swaps and over-the-counter swaps and options (Level 2) for 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 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. For additional information, see Note 1 to the Consolidated Financial Statements included in our 2019 Annual Report on Form 10-K filed with the SEC.


	As of September 30, 2020
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting		Total
	(in thousands)
Assets:
Commodity derivatives — Gas Utilities	$	—	$	6,544	$	—	$	( 4,015 )	$	2,529
Commodity derivatives — Electric Utilities	—		—		—		—		—
Total	$	—	$	6,544	$	—	$	( 4,015 )	$	2,529

Liabilities:
Commodity derivatives — Gas Utilities	$	—	$	1,537	$	—	$	( 326 )	$	1,211
Commodity derivatives — Electric Utilities	—		228		—		—		$	228
Total	$	—	$	1,765	$	—	$	( 326 )	$	1,439


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

Liabilities:
Commodity derivatives — Gas Utilities	$	—	$	5,254	$	—	$	( 2,909 )	$	2,345
Total	$	—	$	5,254	$	—	$	( 2,909 )	$	2,345

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Pension and Postretirement Plan Assets

Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about the fair value measurements of their assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 18 to the Consolidated Financial Statements included in our 2019 Annual Report on Form 10-K. The Company has concluded that the market volatility associated with COVID-19 does not require interim re-measurement of our pension plan assets or defined benefit obligations. See Note 12 for additional information.

Nonrecurring Fair Value Measurement

A discussion of the fair value of our investment in equity securities of a privately held oil and gas company, a Level 3 asset, is included in Note 15 .

Other Fair Value Measures

The following table presents the carrying amounts and fair values of financial instruments not recorded at fair value on the Condensed Consolidated Balance Sheets (in thousands) as of:


	September 30, 2020				December 31, 2019
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current maturities (a)	$	3,536,765	$	4,177,801	$	3,145,839	$	3,479,367

__________

(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.

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(11) Other Comprehensive Income (Loss)

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

The following table details reclassifications out of AOCI and into net income. The amounts in parentheses below indicate decreases to net income in the Condensed Consolidated Statements of Income for the period (in thousands):


	Location on the Condensed Consolidated Statements of Income	Amount Reclassified from AOCI
		Three Months Ended September 30,				Nine Months Ended September 30,
		2020		2019		2020		2019
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	( 712 )	$	( 713 )	$	( 2,138 )	$	( 2,139 )
Commodity contracts	Fuel, purchased power and cost of natural gas sold	( 178 )		( 129 )		( 734 )		508
		( 890 )		( 842 )		( 2,872 )		( 1,631 )
Income tax	Income tax benefit (expense)	209		170		680		358
Total reclassification adjustments related to cash flow hedges, net of tax		$	( 681 )	$	( 672 )	$	( 2,192 )	$	( 1,273 )

Amortization of components of defined benefit plans:
Prior service cost	Operations and maintenance	$	24	$	19	$	79	$	58

Actuarial gain (loss)	Operations and maintenance	( 597 )		( 83 )		( 1,791 )		( 524 )
		( 573 )		( 64 )		( 1,712 )		( 466 )
Income tax	Income tax benefit (expense)	143		89		407		184
Total reclassification adjustments related to defined benefit plans, net of tax		$	( 430 )	$	25	$	( 1,305 )	$	( 282 )
Total reclassifications		$	( 1,111 )	$	( 647 )	$	( 3,497 )	$	( 1,555 )

Balances by classification included within AOCI, net of tax on the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):


	Interest Rate Swaps		Commodity Derivatives		Employee Benefit Plans		Total
As of December 31, 2019	$	( 15,122 )	$	( 456 )	$	( 15,077 )	$	( 30,655 )
Other comprehensive income (loss)
before reclassifications	—		181		55		236
Amounts reclassified from AOCI	1,630		562		1,305		3,497
As of September 30, 2020	$	( 13,492 )	$	287	$	( 13,717 )	$	( 26,922 )


	Interest Rate Swaps		Commodity Derivatives		Employee Benefit Plans		Total
As of December 31, 2018	$	( 17,307 )	$	328	$	( 9,937 )	$	( 26,916 )
Other comprehensive income (loss)
before reclassifications	—		( 334 )		—		( 334 )
Amounts reclassified from AOCI	1,639		( 366 )		282		1,555
As of September 30, 2019	$	( 15,668 )	$	( 372 )	$	( 9,655 )	$	( 25,695 )

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(12) Employee Benefit Plans

Change in Accounting Principle - Pension Accounting Asset Method

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

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

Funding Status of Employee Benefit Plans

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

Defined Benefit Pension Plan

The components of net periodic benefit cost for the Defined Benefit Pension Plan were as follows (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Service cost	$	1,352	$	1,346	$	4,058	$	4,037
Interest cost	3,356		4,344		10,069		13,031
Expected return on plan assets	( 5,647 )		( 6,100 )		( 16,943 )		( 18,300 )
Prior service cost (benefit)	—		6		—		19
Net loss (gain)	2,093		941		6,279		2,822
Net periodic benefit cost	$	1,154	$	537	$	3,463	$	1,609

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Defined Benefit Postretirement Healthcare Plan

The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plan were as follows (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Service cost	$	514	$	454	$	1,542	$	1,362
Interest cost	412		560		1,237		1,683
Expected return on plan assets	( 46 )		( 57 )		( 137 )		( 172 )
Prior service cost (benefit)	( 136 )		( 99 )		( 410 )		( 298 )
Net loss (gain)	5		—		15		—
Net periodic benefit cost	$	749	$	858	$	2,247	$	2,575

Supplemental Non-qualified Defined Benefit and Defined Contribution Plans

The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Service cost	$	1,035	$	429	$	1,482	$	2,406
Interest cost	274		324		824		972
Prior service cost (benefit)	1		—		1		1
Net loss (gain)	425		134		1,277		402
Net periodic benefit cost	$	1,735	$	887	$	3,584	$	3,781

Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made in the first nine months of 2020 and anticipated contributions for 2020 and 2021 are as follows (in thousands):


	Contributions Made		Additional Contributions		Contributions
	Nine Months Ended September 30, 2020		Anticipated for 2020		Anticipated for 2021
Defined Benefit Pension Plan	$	12,700	$	—	$	12,700
Non-pension Defined Benefit Postretirement Healthcare Plans	$	4,006	$	1,335	$	5,227
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans	$	1,065	$	355	$	1,964

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(13) Commitments and Contingencies

There have been no significant changes to commitments and contingencies from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2019 Annual Report on Form 10-K except for those described below and in Note 5 .

Power Sales Agreement - Colorado Electric

On July 1, 2020, Colorado Electric entered into a PSA with the City of Colorado Springs to sell up to 60 MW of wind energy purchased from PRPA under a separate 60 MW PPA transacted on June 26, 2019. This PSA with the City of Colorado Springs expires June 30, 2025.

Power Purchase Agreement - South Dakota Electric

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

(14) Income Taxes

CARES Act

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

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

Eligible wages or employer-paid health benefits must be paid for the period of time during which an employee did not provide services. However, employees do not need to stop providing all services to the employer for the credit to potentially apply.

Additionally, the CARES Act accelerates the amount of alternative minimum tax (“AMT”) credits that can be refunded for the 2018 and 2019 annual tax returns. In 2020, we filed for, and received, a refund of approximately $ 2.4 million of AMT credit carryforwards under this provision.

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

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

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

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

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

(15) Investments

In February 2018, we contributed $ 28 million of assets in exchange for equity securities in a privately held oil and gas company as we divested our Oil and Gas segment. The carrying value of our investment in the equity securities was recorded at cost. We review this investment on a periodic basis to determine whether a significant event or change in circumstances has occurred that may have an adverse effect on the value of the investment.

During the third quarter of 2019, we assessed our investment for impairment as a result of a deterioration in earnings performance of the privately held oil and gas company and an adverse change in future natural gas prices. We engaged a third-party valuation consultant to estimate the fair value of our investment. The valuation was primarily based on an income approach but also considered a market valuation approach. The significant inputs used to estimate the fair value were the oil and gas reserve quantities and values utilizing forward market price curves, industry standard reserve adjustment factors and a discount rate of 10 %. Based on the results of the valuation, we concluded that the carrying value of the investment exceeded fair value. As a result, we recorded a pre-tax impairment loss of $ 20 million for the three months ended September 30, 2019, which was the difference between the carrying value and the fair value of the investment at that time.

During the first quarter of 2020, we assessed our investment for impairment as a result of continued adverse changes in future natural gas prices and liquidity concerns at the privately held oil and gas company. We performed an internal analysis to compute the fair value of our investment, utilizing a consistent methodology as applied during the third quarter of 2019. Based on the results of the valuation, we concluded that the carrying value of the investment exceeded fair value. As a result, we recorded a pre-tax impairment loss of $ 6.9 million for the three months ended March 31, 2020, which was the difference between the carrying value and the fair value of the investment at that time.

The following table presents the carrying value of our investments (in thousands) as of:


	September 30, 2020		December 31, 2019
Investment in privately held oil and gas company	$	1,500	$	8,359
Cash surrender value of life insurance contracts	13,467		13,056
Other investments	692		514
Total investments	$	15,659	$	21,929

(16) Subsequent Events

We evaluated all subsequent event activity and concluded that no subsequent events have occurred that would require recognition in the condensed consolidated financial statements or disclosures, with the exception of those items disclosed in Note 5 .

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

Executive Summary

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

Electric Utilities : Our Electric Utilities segment generates, transmits and distributes electricity to approximately 214,000 customers in Colorado, Montana, South Dakota and Wyoming. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our distribution systems. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates. We also provide non-regulated services through our Tech Services product lines.

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

Black Hills Energy Services provides natural gas supply to approximately 49,000 retail distribution customers under the Choice Gas Program in Nebraska and Wyoming. Additionally, we provide services under the Service Guard Comfort Plan and Tech Services and also offer HomeServe products.

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

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

Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. All of our non-utility business segments support our utilities. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other.

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

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

COVID-19 Pandemic

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

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For the three and nine months ended September 30, 2020, we have experienced limited impacts to our financial results and operational activities due to COVID-19. Year-to-date decreases to gross margins are driven primarily by lower volumes and waived customer late payment fees. Increased operations and maintenance expenses due to sequestration of mission critical and essential employees and increased bad debt expense were partially offset by decreased training, travel, outside services and employee related expenses.

During the three and nine months ended September 30, 2020, COVID-19 had a limited impact on revenues and customer loads. Increases in revenues and customer loads for the three months ended September 30, 2020, when compared to the same period in the prior year, were driven primarily by warmer and drier weather across our service territories. Declines in revenues and customer loads for the nine months ended September 30, 2020, when compared to the same period in the prior year, were driven primarily by milder first quarter winter temperatures in our Gas Utilities’ service territories. We continue to closely monitor loads in our states as updated executive orders and recommendations associated with COVID-19 are provided. We have continued to proactively communicate with various commercial and industrial customers in our service territories to understand their needs and forecast the potential financial implications. We have increased our allowance for credit losses and bad debt expense by $1.7 million and $3.7 million for the three and nine months ended September 30, 2020, respectively, after considering the potential economic impact of the COVID-19 pandemic in forward looking projections related to write-off and recovery rates. All of our jurisdictions temporarily suspended disconnections for a period of time. State orders lifting those restrictions have been issued in nearly all of our jurisdictions; however, we expect the status of restrictions will continue to fluctuate for the next several months. We continue to monitor customer loads, accounts receivable arrears balances, disconnects, cash flows and bad debt expense. We are proactively working with customers to establish payment plans and find available payment assistance resources.

We continue to maintain adequate liquidity to operate our businesses and fund our capital investment program. In February 2020, the Company issued $100 million in equity to support its 2020 capital investment program. In June 2020, the Company issued $400 million of long-term debt which was used to repay short-term debt and for working capital and general corporate purposes. For the nine months ended September 30, 2020, the Company also utilized a combination of its $750 million Revolving Credit Facility and CP Program to meet its funding requirements. The Company has no material debt maturities until late 2023 and as of September 30, 2020, had $648 million of liquidity which included $7.0 million of cash and $641 million of available capacity on its Revolving Credit Facility. We continue to meet our debt covenant requirements. We also continue to monitor the funding status of our employee benefit plan obligations, which did not materially change during the nine months ended September 30, 2020.

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

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

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

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

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

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

2020 Business Segment Highlights and Corporate Activity

Electric Utilities

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

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

• On September 23, 2020, Colorado Electric received approval from the CPUC for its request for approval of its preferred solar bid in support of its Renewable Advantage program. The program plans to add up to 200 MW of renewable energy in Colorado by the end of 2023.

• On July 10, 2020, Wyoming Electric set a new all-time peak load of 271 MW, surpassing the previous peak of 265 MW set in July 2019.

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

Gas Utilities

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

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

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

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

Power Generation

• On October 15, 2020, the FERC approved a settlement agreement that represents a resolution of all issues in the joint application filed by Black Hills Wyoming and Wyoming Electric on August 2, 2019 for approval of a new 60 MW PPA. See additional information in the Electric Utilities Segment highlights above.

Corporate and Other

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

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

• On August 3, 2020, we filed a shelf registration and DRSPP with the SEC. In conjunction with these shelf filings, we renewed the ATM. The renewed ATM program, which allows us to sell shares of our common stock, is the same as the prior program other than the aggregate value increased from $300 million to $400 million and a forward sales option was incorporated.

• On June 17, 2020, we completed a public debt offering of $400 million principal amount in senior unsecured notes. The debt offering consisted of $400 million of 2.50%, 10-year senior notes due June 15, 2030. The proceeds were used to repay short-term debt and for working capital and general corporate purposes.

• On April 16, 2020, S&P affirmed South Dakota Electric’s credit rating at A.

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

• On February 27, 2020, we issued 1.2 million shares of common stock at a price of $81.77 per share for net proceeds of $99 million.

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Results of Operations

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

Consolidated Summary and Overview


(in thousands, except per share amounts)	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019			2020		2019
Revenue
Revenue	$	386,525	$	363,491		$	1,328,456	$	1,368,748
Inter-company eliminations	(39,935)		(37,943)			(117,902)		(111,502)
	$	346,590	$	325,548		$	1,210,554	$	1,257,246
Adjusted operating income (a)
Electric Utilities	$	52,083	$	50,653		$	121,726	$	125,219
Gas Utilities	18,147		4,736			139,253		116,607
Power Generation	8,738		11,822			31,489		33,945
Mining	3,505		3,374			9,992		9,351
Corporate and Other	(239)		(34)			(108)		(439)
Operating income	82,234		70,551			302,352		284,683

Interest expense, net	(36,041)		(33,487)			(107,039)		(102,469)
Impairment of investment	—		(19,741)			(6,859)		(19,741)
Other income (expense), net	(1,193)		580			(703)		55
Income tax (expense)	(4,651)		(2,508)			(25,484)		(22,078)
Net income	40,349		15,395			162,267		140,450
Net income attributable to noncontrolling interest	(4,066)		(3,655)			(11,844)		(10,319)
Net income available for common stock	$	36,283	$	11,740		$	150,423	$	130,131

Earnings per share, Basic	$	0.58	$	0.19		$	2.41	$	2.15
Earnings per share, Diluted	$	0.58	$	0.19		$	2.41	$	2.15

__________

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

The variance to the prior year included the following:

• COVID-19 related impacts to consolidated results included $1.0 million of lower gross margin driven primarily by waived customer late payment fees, $1.7 million of additional bad debt expense and $0.5 million of costs due to sequestration of mission-critical and essential employees which were partially offset by $1.1 million of lower travel, training, and employee related expenses;

• Electric Utilities’ adjusted operating income increased $1.4 million primarily due to rider revenues and benefits from the release of TCJA revenue reserves partially offset by higher operating expenses and mark-to-market losses on wholesale energy contracts;

• Gas Utilities’ adjusted operating income increased $13 million primarily due to drier summer weather favorably impacting our Nebraska service territory irrigation loads, new customer rates in Wyoming and Nebraska and mark-to-market gains on non-utility natural gas commodity contracts partially offset by higher operating expenses;

• Power Generation adjusted operating income decreased $3.1 million primarily due to higher operating expenses driven by the early retirement of certain assets;

• Interest expense increased $2.6 million primarily due to higher debt balances partially offset by lower rates;

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• A prior year $20 million pre-tax non-cash impairment of our investment in equity securities of a privately held oil and gas company;

• Other expense increased $1.8 million primarily due to increased costs for our non-qualified benefit plan driven by market performance on plan assets and increased non-service pension costs resulting from a change in accounting principle for our defined benefit pension plan effective January 1, 2020; and

• Income tax expense increased $2.1 million primarily due to higher pre-tax earnings partially offset by a lower effective tax rate.

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

The variance to the prior year included the following:

• COVID-19 related impacts to consolidated results included $3.4 million of lower gross margin driven primarily by lower volumes and waived customer late payment fees, $2.6 million of costs due to sequestration of mission-critical and essential employees and $3.7 million of additional bad debt expense which were partially offset by $4.6 million of lower travel, training, outside services and employee related expenses;

• Electric Utilities’ adjusted operating income decreased $3.5 million primarily due to higher operating expenses and COVID-19 impacts partially offset by benefits from the release of TCJA revenue reserves, rider revenues and favorable weather;

• Gas Utilities’ adjusted operating income increased $23 million primarily due to new customer rates in Wyoming, mark-to-market gains on non-utility natural gas commodity contracts, prior year amortization of excess deferred income taxes and customer growth partially offset by higher operating expenses and COVID-19 impacts;

• Power Generation adjusted operating income decreased $2.5 million primarily due to higher operating expenses driven by the early retirement of certain assets;

• Interest expense increased $4.6 million primarily due to higher debt balances partially offset by lower rates;

• A prior year $20 million pre-tax non-cash impairment of our investment in equity securities of a privately held oil and gas company compared to a current year $6.9 million impairment on the same investment; and

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

Operating Results by Segment

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

Non-GAAP Financial Measure

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

Gross margin for our Electric Utilities is calculated as operating revenue less cost of fuel and purchased power. Gross margin for our Gas Utilities is calculated as operating revenue less cost of natural gas sold. Our gross margin is impacted by the fluctuations in power 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 measures. Furthermore, this measure is not intended to replace operating income, as determined in accordance with GAAP, as an indicator of operating performance.

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Electric Utilities


	Three Months Ended September 30,						Nine Months Ended September 30,
	2020		2019		Variance		2020		2019		Variance
	(in thousands)
Revenue	$	200,842	$	191,384	$	9,458	$	538,181	$	540,665	$	(2,484)

Total fuel and purchased power	77,885		71,593		6,292		201,398		207,004		(5,606)

Gross margin (non-GAAP)	122,957		119,791		3,166		336,783		333,661		3,122

Operations and maintenance	47,426		47,172		254		144,956		143,049		1,907
Depreciation and amortization	23,448		21,966		1,482		70,101		65,393		4,708
Total operating expenses	70,874		69,138		1,736		215,057		208,442		6,615

Adjusted operating income	$	52,083	$	50,653	$	1,430	$	121,726	$	125,219	$	(3,493)

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

Gross margin for the three months ended September 30, 2020 increased as a result of the following:


	(in millions)
Release of TCJA revenue reserves	$	1.5
Rider recovery	1.3
Off-system power marketing	0.9
Weather	0.2
Mark-to-market on wholesale energy contracts	(1.4)
COVID-19 impacts	(0.2)
Other	0.9
Total increase in Gross margin (non-GAAP)	$	3.2

Operations and maintenance expense increased primarily due to COVID-19 related expenses of $0.5 million for the sequestration of essential employees and $0.3 million of additional bad debt expense which were partially offset by $0.4 million of lower travel, training and employee related expenses.

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

Table of Contents

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

Gross margin for the nine months ended September 30, 2020 increased as a result of the following:


	(in millions)
Release of TCJA revenue reserves	$	2.7
Rider recovery and true-up (a)	1.0
Weather	0.9
COVID-19 impacts (b)	(1.7)
Other	0.2
Total increase in Gross margin (non-GAAP)	$	3.1

____________________

(a) Gross margin increased due to $2.6 million of rider revenues, which was partially offset by a $1.6 million rider true-up.

(b) The impacts to Electric Utilities’ gross margin from COVID-19 were primarily driven by reduced commercial volumes and waived customer late payment fees partially offset by higher residential usage.

Operations and maintenance expense increased primarily due to $1.4 million of expenses related to the efforts to retain our franchise privileges in Pueblo, Colorado. COVID-19 impacts to operations and maintenance expense included $2.2 million of expenses related to the sequestration of essential employees and $0.9 million of additional bad debt expense which were partially offset by $2.4 million of lower travel, training, outside services and employee related expenses.

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

Operating Statistics


	Electric Revenue								Quantities Sold
	(in thousands)								(MWh)
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,		Nine Months Ended September 30,
	2020		2019		2020		2019		2020	2019	2020	2019

Residential	$	62,395	$	58,919	$	167,048	$	162,257	405,989	384,735	1,113,821	1,075,394
Commercial	64,756		65,732		178,979		186,434		538,299	560,547	1,492,239	1,556,449
Industrial	35,660		33,937		99,725		98,074		462,545	462,809	1,382,710	1,335,260
Municipal	4,834		4,792		12,732		13,184		46,256	46,106	121,027	121,025
Subtotal Retail Revenue - Electric	167,645		163,380		458,484		459,949		1,453,089	1,454,197	4,109,797	4,088,128
Contract Wholesale (a)	5,924		8,211		14,947		23,335		129,960	229,369	348,991	646,611
Off-system/Power Marketing Wholesale	9,535		6,452		17,939		16,592		167,494	160,357	469,590	436,298
Other	17,738		13,341		46,811		40,789		—	—	—	—
Total Revenue and Energy Sold	200,842		191,384		538,181		540,665		1,750,543	1,843,923	4,928,378	5,171,037
Other Uses, Losses or Generation, net (b)	—		—		—		—		118,410	112,172	294,466	299,038
Total Revenue and Energy	200,842		191,384		538,181		540,665		1,868,953	1,956,095	5,222,844	5,470,075
Less cost of fuel and purchased power	77,885		71,593		201,398		207,004
Gross Margin (non-GAAP)	$	122,957	$	119,791	$	336,783	$	333,661

Table of Contents


	Electric Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)				Quantities Sold (MWh) (b)
Three Months Ended September 30,	2020		2019		2020		2019		2020	2019
Colorado Electric	$	74,742	$	70,771	$	42,236	$	41,916	666,916	634,098
South Dakota Electric (a)	78,861		77,022		58,062		55,217		699,150	835,725
Wyoming Electric	47,239		43,591		22,659		22,658		502,887	486,272
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold	$	200,842	$	191,384	$	122,957	$	119,791	1,868,953	1,956,095



	Electric Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)				Quantities Sold (MWh) (b)
Nine Months Ended September 30,	2020		2019		2020		2019		2020	2019
Colorado Electric	$	191,197	$	186,030	$	106,961	$	104,411	1,765,501	1,611,126
South Dakota Electric (a)	213,059		225,309		163,659		162,390		1,954,902	2,438,366
Wyoming Electric	133,925		129,326		66,163		66,860		1,502,441	1,420,583
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold	$	538,181	$	540,665	$	336,783	$	333,661	5,222,844	5,470,075

________________

(a) Revenue and purchased power for the three and nine months ended September 30, 2020 as well as associated quantities, for certain wholesale contracts have been presented on a net basis. Amounts for the three and nine months ended September 30, 2019, were presented on a gross basis and, due to their immaterial nature, were not revised. This presentation change has no impact on Gross margin.

(b) Includes company uses, line losses, and excess exchange production.


	Three Months Ended September 30,		Nine Months Ended September 30,
Quantities Generated and Purchased (MWh)	2020	2019	2020	2019

Coal-fired	592,681	564,220	1,712,540	1,621,355
Natural Gas and Oil	199,408	234,366	453,950	445,498
Wind	54,518	55,407	191,696	167,331
Total Generated	846,607	853,993	2,358,186	2,234,184

Purchased (a)	1,022,346	1,102,102	2,864,658	3,235,891
Total Generated and Purchased	1,868,953	1,956,095	5,222,844	5,470,075


	Three Months Ended September 30,		Nine Months Ended September 30,
Quantities Generated and Purchased (MWh)	2020	2019	2020	2019
Generated:
Colorado Electric	97,450	149,509	271,957	341,925
South Dakota Electric	518,821	489,042	1,434,353	1,262,336
Wyoming Electric	230,336	215,442	651,876	629,923
Total Generated	846,607	853,993	2,358,186	2,234,184
Purchased:
Colorado Electric	569,466	484,589	1,493,544	1,269,201
South Dakota Electric (a)	180,329	346,683	520,549	1,176,030
Wyoming Electric	272,551	270,830	850,565	790,660
Total Purchased	1,022,346	1,102,102	2,864,658	3,235,891

Total Generated and Purchased	1,868,953	1,956,095	5,222,844	5,470,075

________________

(a) Purchased power quantities for the three and nine months ended September 30, 2020, for certain wholesale contracts have been presented on a net basis. Amounts for the three and nine months ended September 30, 2019, were presented on a gross basis and, due to their immaterial nature, were not revised. This presentation change has no impact on Gross margin.

Table of Contents



	Three Months Ended September 30,
Degree days	2020			2019
	Actual	Variance from Normal			Actual	Variance from Normal
Heating Degree Days:
Colorado Electric	99	1	%		4	(96)	%
South Dakota Electric	202	(10)	%		175	(22)	%
Wyoming Electric	208	(29)	%		120	(77)	%
Combined (a)	156	(14)	%		86	(36)	%

Cooling Degree Days:
Colorado Electric	987	44	%		1,079	58	%
South Dakota Electric	561	5	%		366	(31)	%
Wyoming Electric	492	65	%		433	45	%
Combined (a)	742	34	%		705	27	%


	Nine Months Ended September 30,
Degree days	2020			2019
	Actual	Variance from Normal		Actual	Variance from Normal
Heating Degree Days:
Colorado Electric	3,073	(9)	%	3,156	(6)	%
South Dakota Electric	4,440	—	%	5,370	20	%
Wyoming Electric	4,356	(3)	%	4,677	5	%
Combined (a)	3,799	(4)	%	4,198	6	%

Cooling Degree Days:
Colorado Electric	1,369	53	%	1,226	37	%
South Dakota Electric	681	8	%	404	(36)	%
Wyoming Electric	593	70	%	462	33	%
Combined (a)	977	41	%	791	14	%

____________________

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


	Three Months Ended September 30,				Nine Months Ended September 30,
Contracted Power Plant Fleet Availability (a)	2020		2019		2020		2019
Coal-fired plants (b)	97.4	%	94.6	%	94.1	%	90.0	%
Natural gas-fired plants and Other plants (c)(d)	79.7	%	89.6	%	80.5	%	89.8	%
Wind	97.7	%	93.7	%	98.3	%	95.0	%
Total Availability	86.8	%	91.5	%	86.3	%	90.3	%

Wind Capacity Factor	33.2	%	33.8	%	39.3	%	37.1	%

____________________

(a) Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.

(b) 2019 included planned outages at Neil Simpson II and Wygen III and unplanned outages at Wyodak Plant and Wygen III.

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

Table of Contents

Gas Utilities


	Three Months Ended September 30,						Nine Months Ended September 30,
	2020		2019		Variance		2020		2019		Variance
	(in thousands)
Revenue:
Natural gas - regulated	$	128,468	$	117,549	$	10,919	$	612,797	$	651,366	$	(38,569)
Other - non-regulated services	15,461		13,195		2,266		53,015		55,927		(2,912)
Total revenue	143,929		130,744		13,185		665,812		707,293		(41,481)

Cost of sales:
Natural gas - regulated	25,235		28,154		(2,919)		222,144		280,312		(58,168)
Other - non-regulated services	1,800		4,870		(3,070)		4,874		16,975		(12,101)
Total cost of sales	27,035		33,024		(5,989)		227,018		297,287		(70,269)

Gross margin (non-GAAP)	116,894		97,720		19,174		438,794		410,006		28,788

Operations and maintenance	73,642		70,170		3,472		223,351		225,239		(1,888)
Depreciation and amortization	25,105		22,814		2,291		76,190		68,160		8,030
Total operating expenses	98,747		92,984		5,763		299,541		293,399		6,142

Adjusted operating income	$	18,147	$	4,736	$	13,411	$	139,253	$	116,607	$	22,646

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

Gross margin for the three months ended September 30, 2020 increased as a result of:



	(in millions)
Weather (a)	$	8.4
New rates	4.9
Mark-to-market on non-utility natural gas commodity contracts	1.8
Customer growth - distribution	1.5
Non-Utility - Tech Services	0.6
COVID-19 impacts (b)	(0.8)
Other	2.8
Total increase in Gross margin (non-GAAP)	$	19.2

____________________

(a) Weather impacts for the three months ended September 30, 2020 compared to the same period in the prior year include increased irrigation loads to agriculture customers in 2020 in our Nebraska Gas service territory as 2019 was a record precipitation year and increased heating demand due to cooler temperatures.

(b) The impacts to Gas Utilities’ gross margin from COVID-19 were primarily driven by waived customer late payment fees.

Operations and maintenance expense increased primarily due to higher employee costs. COVID-19 impacts to operations and maintenance expense included $1.4 million of additional bad debt expense which was partially offset by $0.7 million of lower travel and training expenses.

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

Table of Contents

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

Gross margin for the nine months ended September 30, 2020 increased as a result of:


	(in millions)
New rates	$	14.1
Mark-to-market on non-utility natural gas commodity contracts	4.2
Customer growth - distribution	3.6
Prior year amortization of excess deferred income taxes	3.5
Non-Utility - Tech Services and Gas Supply Services	1.4
Weather (a)	0.8
COVID-19 impacts (b)	(1.7)
Other	2.9
Total increase in Gross margin (non-GAAP)	$	28.8

____________________

(a) Weather impacts for the nine months ended September 30, 2020 compared to the same period in the prior year include increased irrigation loads to agriculture customers in the third quarter of 2020 in our Nebraska Gas service territory as 2019 was a record precipitation year mostly offset by lower heating demand in the first quarter of 2020 due to warmer temperatures.

(b) The impacts to Gas Utilities’ gross margin from COVID-19 were primarily driven by reduced volumes from certain transport customers and waived customer late payment fees.

Operations and maintenance expense decreased primarily due to $2.7 million of lower outside services expenses and $1.2 million of lower employee costs partially offset by $1.0 million of higher property taxes due to a higher asset base. COVID-19 impacts to operations and maintenance expense included $2.8 million of additional bad debt expense which was partially offset by $2.2 million of lower travel, training, outside services and employee related expenses.

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

Operating Statistics


	Gas Revenue (in thousands)					Gross Margin (non-GAAP) (in thousands)					Gas Utilities Quantities Sold & Transported (Dth)
	Three Months Ended September 30,				Three Months Ended September 30,					Three Months Ended September 30,
	2020		2019			2020		2019			2020	2019

Residential	$	61,515	$	57,244		$	48,165	$	43,441		4,058,040	3,599,549
Commercial	19,940		19,629			12,821		11,589			2,354,719	2,298,919
Industrial	7,280		8,770			2,514		2,493			2,674,127	2,960,930
Other	1,271		2,499			1,271		2,499			—	—
Total Distribution	90,006		88,142			64,771		60,022			9,086,886	8,859,398

Transportation and Transmission	38,462		29,407			38,462		29,373			33,668,174	31,538,815

Total Regulated	128,468		117,549			103,233		89,395			42,755,060	40,398,213

Non-regulated Services	15,461		13,195			13,661		8,325

Total Gas Revenue & Gross Margin (non-GAAP)	$	143,929	$	130,744		$	116,894	$	97,720

Table of Contents



	Gas Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)				Gas Utilities Quantities Sold & Transported (Dth)
	Nine Months Ended September 30,				Nine Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019		2020	2019

Residential	$	351,986	$	383,466	$	207,654	$	201,168	40,790,670	44,356,725
Commercial	127,617		146,752		61,676		61,673		19,155,051	21,484,646
Industrial	18,539		18,764		6,697		5,830		5,771,732	5,141,399
Other	856		(968)		856		(968)		—	—
Total Distribution	498,998		548,014		276,883		267,703		65,717,453	70,982,770

Transportation and Transmission	113,799		103,352		113,770		103,351		108,967,182	110,622,285

Total Regulated	612,797		651,366		390,653		371,054		174,684,635	181,605,055

Non-regulated Services	53,015		55,927		48,141		38,952

Total Gas Revenue & Gross Margin (non-GAAP)	$	665,812	$	707,293	$	438,794	$	410,006



	Gas Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)						Gas Utilities Quantities Sold & Transported (Dth)
	Three Months Ended September 30,					Three Months Ended September 30,					Three Months Ended September 30,
	2020		2019				2020		2019			2020	2019

Arkansas Gas	$	21,043	$	21,387			$	17,400	$	16,249		3,925,893	4,094,454
Colorado Gas	22,724		22,632				16,972		15,667			3,702,666	3,806,360
Iowa Gas	18,155		16,381				14,672		13,135			5,628,110	5,686,772
Kansas Gas	18,591		19,013				13,099		12,309			8,564,408	7,602,758
Nebraska Gas	46,315		35,715				39,755		28,046			16,525,547	13,999,302
Wyoming Gas	17,101		15,616				14,996		12,314			4,408,436	5,208,567
Total Gas Revenue & Gross Margin (non-GAAP)	$	143,929	$	130,744			$	116,894	$	97,720		42,755,060	40,398,213



	Gas Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)				Gas Utilities Quantities Sold & Transported (Dth)
	Nine Months Ended September 30,				Nine Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019		2020	2019

Arkansas Gas	$	124,621	$	127,014	$	88,161	$	79,148	19,795,077	21,061,567
Colorado Gas	123,943		135,816		73,785		73,022		21,845,915	23,050,638
Iowa Gas	94,386		105,736		50,355		50,773		25,429,502	28,834,731
Kansas Gas	70,571		77,609		44,162		42,385		25,202,180	24,336,744
Nebraska Gas	170,447		183,827		122,140		111,828		56,857,061	57,815,316
Wyoming Gas	81,844		77,291		60,191		52,850		25,554,900	26,506,059
Total Gas Revenue & Gross Margin (non-GAAP)	$	665,812	$	707,293	$	438,794	$	410,006	174,684,635	181,605,055

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

Table of Contents



	Three Months Ended September 30,
	2020		2019
Heating Degree Days	Actual	Variance from Normal	Actual	Variance from Normal
Arkansas Gas (a)	24	(44)%	—	(100)%
Colorado Gas	159	(26)%	68	(68)%
Iowa Gas	140	1%	43	(69)%
Kansas Gas (a)	70	27%	—	(101)%
Nebraska Gas	109	(1)%	22	(80)%
Wyoming Gas	245	(20)%	183	(37)%
Combined (b)	125	(13)%	53	(62)%



	Nine Months Ended September 30,
	2020		2019
Heating Degree Days	Actual	Variance from Normal	Actual	Variance from Normal
Arkansas Gas (a)	2,036	(18)%	2,347	(5)%
Colorado Gas	3,797	(7)%	4,115	—%
Iowa Gas	4,104	(2)%	4,611	10%
Kansas Gas (a)	2,851	(4)%	3,204	8%
Nebraska Gas	3,636	(4)%	4,169	10%
Wyoming Gas	4,678	(1)%	5,093	9%
Combined (b)	3,731	(4)%	4,297	7%

___________

(a) Arkansas and Kansas have weather normalization mechanisms that mitigate the weather impact on gross margins.

(b) The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas due to its weather normalization mechanism. Arkansas is excluded based on the weather normalization mechanism in effect from November through April.

Regulatory Matters

For more information on recent regulatory activity and enacted regulatory provisions with respect to the states in which our Utilities operate, see Note 5 of the Notes to Condensed Consolidated Financial Statements and Part I, Items 1 and 2 and Part II, Item 8 of our 2019 Annual Report on Form 10-K filed with the SEC.

Power Generation


	Three Months Ended September 30,						Nine Months Ended September 30,
	2020		2019		Variance		2020		2019		Variance
	(in thousands)
Revenue	$	26,518	$	25,811	$	707	$	78,606	$	75,764	$	2,842

Fuel expense	2,320		2,283		37		6,692		6,933		(241)
Operations and maintenance	10,539		6,946		3,593		24,886		20,817		4,069
Depreciation and amortization	4,921		4,760		161		15,539		14,069		1,470
Total operating expense	17,780		13,989		3,791		47,117		41,819		5,298

Adjusted operating income	$	8,738	$	11,822	$	(3,084)	$	31,489	$	33,945	$	(2,456)

Table of Contents

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

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

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

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

Operating Statistics


	Three Months Ended September 30,		Nine Months Ended September 30,
	2020	2019	2020	2019
Quantities Sold, Generated and Purchased (MWh) (a)
Sold
Black Hills Colorado IPP	301,934	275,867	830,860	692,156
Black Hills Wyoming (b)	157,855	162,668	471,073	476,430
Black Hills Electric Generation	65,697	30,912	255,605	112,461
Total Sold	525,486	469,447	1,557,538	1,281,047

Generated
Black Hills Colorado IPP	301,934	275,867	830,860	692,156
Black Hills Wyoming (b)	139,313	142,219	408,545	407,001
Black Hills Electric Generation	65,697	30,912	255,605	112,461
Total Generated	506,944	448,998	1,495,010	1,211,618

Purchased

Black Hills Wyoming (b)	18,004	16,865	62,097	56,205

Total Purchased	18,004	16,865	62,097	56,205

___________

(a) Company uses and losses are not included in the quantities sold, generated, and purchased.

(b) Under the 20-year economy energy PPA with the City of Gillette effective September 2014, Black Hills Wyoming purchases energy on behalf of the City of Gillette and sells that energy to the City of Gillette. MWh sold may not equal MWh generated and purchased due to a dispatch agreement Black Hills Wyoming has with South Dakota Electric to cover energy imbalances.

Table of Contents


	Three Months Ended September 30,				Nine Months Ended September 30,
Contracted Power Plant Fleet Availability (a)	2020		2019		2020		2019

Coal-fired plant	96.1	%	98.0	%	94.5	%	95.2	%
Natural gas-fired plants (b)	99.8	%	97.6	%	99.6	%	98.4	%
Wind	90.6	%	81.9	%	92.8	%	93.4	%
Total Availability	95.8	%	93.6	%	96.3	%	96.5	%

Wind Capacity Factor	19.4	%	15.0	%	25.7	%	22.1	%

___________

(a) Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.

(b) 2019 included a planned outage at Pueblo Airport Generation.

Mining


	Three Months Ended September 30,						Nine Months Ended September 30,
	2020		2019		Variance		2020		2019		Variance
	(in thousands)
Revenue	$	15,236	$	15,552	$	(316)	$	45,857	$	45,026	$	831

Operations and maintenance	8,923		9,900		(977)		28,481		28,988		(507)
Depreciation, depletion and amortization	2,808		2,278		530		7,384		6,687		697
Total operating expenses	11,731		12,178		(447)		35,865		35,675		190

Adjusted operating income	$	3,505	$	3,374	$	131	$	9,992	$	9,351	$	641

Operating Statistics


	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands, except for Revenue per ton)	2020		2019		2020		2019
Tons of coal sold	940		969		2,808		2,720
Cubic yards of overburden moved	1,595		2,341		6,073		6,380

Revenue per ton	$	15.60	$	15.47	$	15.64	$	15.90

Corporate and Other


	Three Months Ended September 30,						Nine Months Ended September 30,
	2020		2019		Variance		2020		2019		Variance
	(in thousands)
Adjusted operating income (loss)	$	(239)	$	(34)	$	(205)	$	(108)	$	(439)	$	331

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2020		2019		Variance		2020		2019		Variance
	(in thousands)						(in thousands)
Interest expense, net	$	(36,041)	$	(33,487)	$	(2,554)	$	(107,039)	$	(102,469)	$	(4,570)
Impairment of investment	—		(19,741)		$	19,741	(6,859)		(19,741)		$	12,882
Other income (expense), net	(1,193)		580		$	(1,773)	(703)		55		$	(758)
Income tax (expense)	(4,651)		(2,508)		$	(2,143)	(25,484)		(22,078)		$	(3,406)

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

Interest expense, net

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

Impairment of Investment

For the three months ended September 30, 2019, we recorded a pre-tax non-cash write-down of $20 million in our investment in equity securities of a privately held oil and gas company. The impairment was triggered by continued adverse changes in future natural gas prices and liquidity concerns at the privately held oil and gas company. The remaining book value of our investment is $1.5 million, and this is our only remaining investment in oil and gas exploration and production activities. See Note 15 of the Notes to Condensed Consolidated Financial Statements for additional details.

Other Income (Expense)

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

Income Tax (Expense)

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

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

Interest expense, net

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

Impairment of Investment

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

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Income Tax (Expense)

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

Critical Accounting Policies Involving Significant Accounting Estimates

There have been no material changes in our critical accounting estimates from those reported in our 2019 Annual Report on Form 10-K filed with the SEC except for Pension and Other Postretirement Benefits provided below. We continue to closely monitor the rapidly evolving and uncertain impact of COVID-19 on our critical accounting estimates including, but not limited to, collectibility of customer receivables, recoverability of regulatory assets, impairment risk of goodwill and long-lived assets, valuation of pension assets and liabilities, and contingent liabilities. For more information on our critical accounting estimates, see Part II, Item 7 of our 2019 Annual Report on Form 10-K.

Pension and Other Postretirement Benefits

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

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

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

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Liquidity and Capital Resources

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

Collateral Requirements

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

Cash Flow Activities

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


Cash provided by (used in):	2020		2019		Variance
Operating activities	$	419.5	$	386.1	$	33.4
Investing activities	$	(529.7)	$	(593.3)	$	63.6
Financing activities	$	107.8	$	199.8	$	(92.0)

Year-to-Date 2020 Compared to Year-to-Date 2019

Operating Activities

Net cash provided by operating activities was $419 million for the nine months ended September 30, 2020, compared to net cash provided by operating activities of $386 million for the same period in 2019, for an increase of $33 million. The variance was primarily attributable to:

• Cash earnings (net income plus non-cash adjustments) were $22 million higher for the nine months ended September 30, 2020 compared to the same period in the prior year primarily driven by higher operating income at the Gas Utilities segment;

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

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

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

◦ Cash outflows increased by $13 million primarily as a result of changes in our regulatory assets and liabilities driven by timing of recovery and returns for fuel costs adjustments partially offset by the TCJA tax rate change that was returned to customers in the prior year.

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Investing Activities

Net cash used in investing activities was $530 million for the nine months ended September 30, 2020, compared to net cash used in investing activities of $593 million for the same period in 2019, a decrease of $64 million primarily due to the following:

• Capital expenditures of $536 million for the nine months ended September 30, 2020 compared to $593 million for the same period in the prior year. Higher prior year expenditures were driven by large prior year projects such as the Natural Bridge pipeline project, the Busch Ranch II wind project and construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota to Stegall, Nebraska. These large prior year expenditures were partially offset by the current year Corriedale wind project at our Electric Utilities segment.

Financing Activities

Net cash provided by financing activities for the nine months ended September 30, 2020 was $108 million, compared to $200 million of net cash provided by financing activities for the same period in 2019, a decrease of $92 million primarily due to the following:

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

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

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

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

• Decrease of $2.0 million in net proceeds from the issuance of common stock;

Dividends

Dividends paid on our common stock totaled $100 million for the nine months ended September 30, 2020, or $0.535 per share per quarter. On October 27, 2020, our board of directors declared a quarterly dividend of $0.565 per share payable December 1, 2020, equivalent to an annual dividend of $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.

Financing Transactions and Short-Term Liquidity

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):


		Current		Revolver Borrowings at		CP Program Borrowings at		Letters of Credit (a) at		Available Capacity at
Credit Facility	Expiration	Capacity		September 30, 2020		September 30, 2020		September 30, 2020		September 30, 2020
Revolving Credit Facility and CP Program	July 30, 2023	$	750	$	—	$	84	$	25	$	641

_______________

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

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Revolving Credit Facility and CP Program borrowing activity for the nine months ended September 30, 2020 was (dollars in millions):


	For the Nine Months Ended September 30, 2020
Maximum amount outstanding - Revolving Credit Facility (based on daily outstanding balances)	$	220
Maximum amount outstanding - CP Program (based on daily outstanding balances)	$	366
Average amount outstanding - Revolving Credit Facility (based on daily outstanding balances)	$	109
Average amount outstanding - CP Program (based on daily outstanding balances)	$	170
Weighted average interest rates - Revolving Credit Facility	1.75		%
Weighted average interest rates - CP Program	1.10		%

Covenant Requirements

The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on certain liens, restrictions on certain transactions, and maintenance of a certain Consolidated Indebtedness to Capitalization Ratio. 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, 2020. See Note 7 of the Notes to Condensed Consolidated Financial Statements for more information.

Covenants within Wyoming Electric’s financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of September 30, 2020, we were in compliance with these covenants.

Financing Activities

See Notes 7 and 8 of the Notes to Condensed Consolidated Financial Statements for information concerning significant financing activities for the nine months ended September 30, 2020.

Future Financing Plans

We will continue to assess debt and equity needs to support our capital expenditure plan.

Credit Ratings

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.

The following table represents the credit ratings and outlook and risk profile of BHC at September 30, 2020:


Rating Agency	Senior Unsecured Rating	Outlook
S&P (a)	BBB+	Stable
Moody’s (b)	Baa2	Stable
Fitch (c)	BBB+	Stable

__________

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

(b) On December 20, 2019, Moody’s affirmed our Baa2 rating and maintained a Stable outlook.

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The following table represents the credit ratings of South Dakota Electric at September 30, 2020:


Rating Agency			Senior Secured Rating
S&P (a)			A
Moody’s (b)			A1
Fitch (c)			A

__________

(a) On April 16, 2020, S&P affirmed A rating.

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

Capital Requirements

Capital Expenditures


	Actual		Planned		Planned		Planned		Planned		Planned
Capital Expenditures by Segment	Nine Months Ended September 30, 2020 (a)		2020 (b)		2021		2022		2023		2024
(in millions)
Electric Utilities	$	179	$	262	$	240	$	180	$	143	$	156
Gas Utilities	329		434		363		334		327		317
Power Generation	12		10		10		9		6		4
Mining	6		8		9		9		9		9
Corporate and Other	10		19		11		5		12		13
	$	536	$	733	$	633	$	537	$	497	$	499

__________

(a) Expenditures for the nine months ended September 30, 2020 include the impact of accruals for property, plant and equipment.

(b) Includes actual capital expenditures for the nine months ended September 30, 2020.

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

Contractual Obligations

There have been no significant changes in contractual obligations from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2019 Annual Report on Form 10-K except for the items described in Note 13 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Off-Balance Sheet Commitments

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

New Accounting Pronouncements

Other than the pronouncements reported in our 2019 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.

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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 and Analysis of Financial Condition and Results of Operations.

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

Any forward-looking statement contained in this document speaks only as of the date 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, 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 2019 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our 2019 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. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information regarding our quantitative and qualitative disclosures about market risk is disclosed in Item 7A of our Annual Report on Form 10-K. See Note 9 of the Notes to Condensed Consolidated Financial Statements for updates to market risks during the nine months ended September 30, 2020.

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, as amended (the “Exchange Act”)) as of September 30, 2020. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at September 30, 2020.

Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’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, 2020, there have been no changes in our internal controls over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. Although we have altered some work routines due to the COVID-19 pandemic, the changes in our work environment (i.e. remote work arrangements) have not materially impacted our internal controls over financial reporting and have not adversely affected the Company’s ability to maintain operations, including financial reporting systems, ICFR, and disclosure controls and procedures.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see Note 19 in Item 8 of our 2019 Annual Report on Form 10-K and Note 13 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 13 is incorporated by reference into this item.

ITEM 1A. RISK FACTORS

There are no material changes to the risk factors previously disclosed in Item 1A of Part I in our 2019 Annual Report on Form 10-K filed with the SEC except as shown below:

Our business, results of operations, financial condition and cash flows could be adversely affected by the recent coronavirus (COVID-19) pandemic.

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

For the nine months ended September 30, 2020, the COVID-19 pandemic had a limited financial impact on our business, operations, financial condition and cash flows. In particular, we experienced:

• Increased allowance for credit losses and bad debt expense due to anticipated customer non-payment as a result of suspended disconnections;

• Increased costs due to sequestration of mission-critical and essential employees;

• Lower commercial and certain transport volumes partially offset by higher electric and natural gas residential usage;

• Reduced availability of our employees;

• Increased costs for personal protection equipment and cleaning supplies;

• Limited cash flow impacts from delayed payments from residential, commercial and industrial customers;

• Minimal disruptions receiving the materials and supplies necessary to maintain operations and continue executing our capital investment plan;

• Minimal impacts to the availability of our third-party resources;

• Minimal decline in the funded status of our pension plan;

• Minimal interest expense increase due to disruptions in the Commercial Paper markets; and

• Reduced training, travel, employee, outside services and employee related expenses.

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

• Adverse impacts on our strategic business plans, growth strategy and capital investment plans;

• Increased adverse impacts to electricity and natural gas demand from our customers, particularly from commercial and industrial customers;

• Further reduction in the availability of our employees and third-party resources;

• Increased costs as a result of our emergency measures;

• I ncreased allowance for credit losses and bad debt expense as a result of delayed or non-payment from our customers, both of which could be magnified by Federal or state government legislation that requires us to extend suspensions of disconnections for non-payment;

• Delays and disruptions in the availability, timely delivery and cost of materials and components used in our operations;

• Disruptions in the commercial operation dates of certain projects impacting qualification criteria for certain tax credits and triggering potential damages under our power purchase agreements;

• Deterioration of the credit quality of our counterparties, including gas commodity contract counterparties, power purchase agreement counterparties, contractors or retail customers, that could result in credit losses;

• Impairment of goodwill or long-lived assets;

• Adverse impacts on our ability to develop, construct and operate facilities;

• Inability to meet the requirements of the covenants in our existing credit facilities, including covenants regarding Consolidated Indebtedness to Capitalization Ratio;

• Deterioration in our financial metrics or the business environment that adversely impacts our credit ratings;

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

• Adverse impact on our liquidity position and cost of and ability to access funds from financial institutions and capital markets;

• Delays in our ability to change rates through regulatory proceedings; and

• Other risks that impact us, such as the risks described in the “Risk Factors” section of our 2019 Annual Report on Form 10-K and our ability to meet our financial obligations.

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

ITEM 4. MINE SAFETY DISCLOSURES

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

ITEM 6. EXHIBITS


Exhibit Number			Description










Exhibit 3.1*			Restated Articles of Incorporation of the Registrant dated January 30, 2018 (filed as Exhibit 3 to the Registrant’s Form 8-K filed on February 5, 2018).

Exhibit 3.2*			Amended and Restated Bylaws of the Registrant dated April 24, 2017 (filed as Exhibit 3 to the Registrant’s Form 8-K filed on April 28, 2017).

Exhibit 4.1*			Indenture dated as of May 21, 2003 between the Registrant and Wells Fargo Bank, National Association (as successor to LaSalle Bank National Association), as Trustee (filed as Exhibit 4.1 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003).
			First Supplemental Indenture dated as of May 21, 2003 (filed as Exhibit 4.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003).
			Second Supplemental Indenture dated as of May 14, 2009 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on May 14, 2009).
			Third Supplemental Indenture dated as of July 16, 2010 (filed as Exhibit 4 to Registrant’s Form 8-K filed on July 15, 2010).
			Fourth Supplemental Indenture dated as of November 19, 2013 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on November 18, 2013).
			Fifth Supplemental Indenture dated as of January 13, 2016 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on January 13, 2016).
			Sixth Supplemental Indenture dated as of August 19, 2016 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on August 19, 2016).
			Seventh Supplemental Indenture dated as of August 17, 2018 (filed as Exhibit 4.2 to the Registrant’s Form 8-K filed on August 17, 2018).
			Eighth Supplemental Indenture dated as of October 3, 2019 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on October 4, 2019).
			Ninth Supplemental Indenture dated as of June 17, 2020 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on June 17, 2020).

Exhibit 4.2*			Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)).
			First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S‑3 (No. 333‑150669)).
			Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registrant’s Post-Effective Amendment No. 2 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)).


			Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014).

Exhibit 4.3*			Restated Indenture of Mortgage, Deed of Trust, Security Agreement and Financing Statement, amended and restated as of November 20, 2007, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on October 2, 2014).
			First Supplemental Indenture, dated as of September 3, 2009, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.3 to the Registrant’s Form 8-K filed on October 2, 2014).
			Second Supplemental Indenture, dated as of October 1, 2014, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.4 to the Registrant’s Form 8-K filed on October 2, 2014).

Exhibit 4.4*			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).

Exhibit 10.1			Equity Distribution Sales Agreement dated August 4, 2020 among Black Hills Corporation and the several Agents named therein (filed as Exhibit 1.1 to the Registrant’s Form 8-K filed on August 4, 2020).

Exhibit 31.1			Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.

Exhibit 31.2			Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuance to Section 302 of the Sarbanes - Oxley Act of 2002.

Exhibit 32.1			Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.

Exhibit 32.2			Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.

Exhibit 95			Mine Safety and Health Administration Safety Data.

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 101)

__________

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

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

BLACK HILLS CORPORATION


		/s/ Linden R. Evans
		Linden R. Evans, President and
		Chief Executive Officer

		/s/ Richard W. Kinzley
		Richard W. Kinzley, Senior Vice President and
		Chief Financial Officer

Dated:	November 3, 2020

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Part I. Financial Information Item 1. Financial Statements Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II. Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 4. Mine Safety Disclosures Item 6. Exhibits

Exhibits

BKH 10-Q Quarter ended Sept. 30, 2020

Exhibits