Black Hills - 10-Q quarterly report FY2020 Q2

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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 June 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 July 31, 2020

Common stock, $1.00 par value

62,745,335

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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	13
	Note 1. Management’s Statement	13
	Note 2. Revenue	15
	Note 3. Business Segment Information	17
	Note 4. Selected Balance Sheet Information	19
	Note 5. Regulatory Matters	21
	Note 6. Earnings Per Share	23
	Note 7. Notes Payable, Current Maturities and Debt	23
	Note 8. Equity	24
	Note 9. Risk Management and Derivatives	25
	Note 10. Fair Value Measurements	28
	Note 11. Other Comprehensive Income (Loss)	31
	Note 12. Employee Benefit Plans	32
	Note 13. Commitments and Contingencies	34
	Note 14. Income Taxes	34
	Note 15. Investments	35
	Note 16. Subsequent Events	35

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TABLE OF CONTENTS
		Page
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
	Executive Summary	36
	Results of Operations - Consolidated Summary and Overview	40
	Non-GAAP Financial Measure	41
	Electric Utilities Segment	42
	Gas Utilities Segment	46
	Regulatory Matters	49
	Power Generation Segment	50
	Mining Segment	52
	Corporate and Other	52
	Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax (Expense)	52
	Critical Accounting Policies Involving Significant Accounting Estimates	54
	Liquidity and Capital Resources	55
	Cash Flow Activities	55
	Dividends	56
	Financing Transactions and Short-Term Liquidity	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

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GLOSSARY OF TERMS AND ABBREVIATIONS

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


AFUDC			Allowance for Funds Used During Construction

AOCI			Accumulated Other Comprehensive Income (Loss)

Arkansas Gas			Black Hills Energy Arkansas, Inc., a direct, 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			Megawatts
MWh			Megawatt-hours
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


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. If approved by the CPUC, the project would 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 would 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.
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.

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

Service Guard Comfort Plan			New plan that will consolidate Service Guard and Customer Appliance Protection Plan (CAPP) and provide 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).

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


(unaudited)	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
	(in thousands, except per share amounts)

Revenue	$	326,914	$	333,888	$	863,964	$	931,698

Operating expenses:
Fuel, purchased power and cost of natural gas sold	71,629		90,200		259,508		339,942
Operations and maintenance	117,308		124,950		242,774		248,534
Depreciation, depletion and amortization	56,663		51,595		113,065		102,623
Taxes - property and production	14,381		13,142		28,499		26,467

Total operating expenses	259,981		279,887		643,846		717,566

Operating income	66,933		54,001		220,118		214,132

Other income (expense):

Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	(35,765)		(34,660)		(71,546)		(69,676)
Interest income	220		396		548		695
Impairment of investment	—		—		(6,859)		—
Other income (expense), net	(1,863)		263		490		(526)
Total other income (expense)	(37,408)		(34,001)		(77,367)		(69,507)

Income before income taxes	29,525		20,000		142,751		144,625
Income tax (expense)	(4,831)		(2,307)		(20,833)		(19,570)
Net income	24,694		17,693		121,918		125,055
Net income attributable to noncontrolling interest	(3,728)		(3,110)		(7,778)		(6,664)
Net income available for common stock	$	20,966	$	14,583	$	114,140	$	118,391


Earnings per share of common stock:
Earnings per share, Basic	$	0.34	$	0.24	$	1.84	$	1.97
Earnings per share, Diluted	$	0.33	$	0.24	$	1.83	$	1.96

Weighted average common shares outstanding:
Basic	62,573		60,467		62,175		60,195
Diluted	62,617		60,606		62,230		60,333

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 June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
	(in thousands)

Net income	$	24,694	$	17,693	$	121,918	$	125,055

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, $5, $13 and $10, respectively)	(19)		(15)		(42)		(29)
Reclassification adjustments of benefit plan liability - net gain (net of tax of $(182), $(52), $(277) and $(105), respectively)	415		169		917		336
Derivative instruments designated as cash flow hedges:
Reclassification of net realized losses on settled/amortized interest rate swaps (net of tax of $(170), $(172), $(340) and $(335), respectively)	543		541		1,086		1,091
Net unrealized gains (losses) on commodity derivatives (net of tax of $14, $119, $68 and $65, respectively)	(45)		(399)		(220)		(219)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $(16), $19, $(131), and $147, respectively)	54		(64)		425		(490)
Other comprehensive income, net of tax	948		232		2,221		689

Comprehensive income	25,642		17,925		124,139		125,744
Less: comprehensive income attributable to noncontrolling interest	(3,728)		(3,110)		(7,778)		(6,664)
Comprehensive income available for common stock	$	21,914	$	14,815	$	116,361	$	119,080

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
	June 30, 2020		December 31, 2019
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	31,608	$	9,777
Restricted cash and equivalents	4,105		3,881
Accounts receivable, net	170,980		255,805
Materials, supplies and fuel	105,987		117,172
Derivative assets, current	1,581		342
Income tax receivable, net	20,118		16,446
Regulatory assets, current	51,745		43,282
Other current assets	27,981		26,479
Total current assets	414,105		473,184

Investments	15,438		21,929

Property, plant and equipment	6,954,274		6,784,679
Less: accumulated depreciation and depletion	(1,251,075)		(1,281,493)
Total property, plant and equipment, net	5,703,199		5,503,186

Other assets:
Goodwill	1,299,454		1,299,454
Intangible assets, net	12,536		13,266
Regulatory assets, non-current	220,567		228,062
Other assets, non-current	24,633		19,376
Total other assets, non-current	1,557,190		1,560,158

TOTAL ASSETS	$	7,689,932	$	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
	June 30, 2020		December 31, 2019
	(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	118,942	$	193,523
Accrued liabilities	201,667		226,767
Derivative liabilities, current	621		2,254
Regulatory liabilities, current	59,428		33,507
Notes payable	—		349,500
Current maturities of long-term debt	4,307		5,743
Total current liabilities	384,965		811,294

Long-term debt, net of current maturities	3,532,887		3,140,096

Deferred credits and other liabilities:
Deferred income tax liabilities, net	388,962		360,719
Regulatory liabilities, non-current	506,393		503,145
Benefit plan liabilities	142,580		154,472
Other deferred credits and other liabilities	119,649		124,662
Total deferred credits and other liabilities	1,157,584		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 62,772,996 and 61,480,658 shares, respectively	62,773		61,481
Additional paid-in capital	1,654,563		1,552,788
Retained earnings	826,269		778,776
Treasury stock, at cost – 26,399 and 3,956 shares, respectively	(1,879)		(267)
Accumulated other comprehensive income (loss)	(28,434)		(30,655)
Total stockholders’ equity	2,513,292		2,362,123
Noncontrolling interest	101,204		101,946
Total equity	2,614,496		2,464,069

TOTAL LIABILITIES AND TOTAL EQUITY	$	7,689,932	$	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)	Six Months Ended June 30,
	2020		2019
Operating activities:	(in thousands)
Net income	$	121,918	$	125,055
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	113,065		102,623
Deferred financing cost amortization	4,246		4,219
Impairment of investment	6,859		—
Stock compensation	1,113		7,093
Deferred income taxes	26,401		21,935
Employee benefit plans	5,656		5,683
Other adjustments, net	3,679		8,991
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	7,503		14,911
Accounts receivable and other current assets	73,302		99,925
Accounts payable and other current liabilities	(63,085)		(107,563)
Regulatory assets - current	21,887		16,116
Regulatory liabilities - current	314		(6,348)
Contributions to defined benefit pension plans	(12,700)		—
Other operating activities, net	(1,152)		(2,861)
Net cash provided by operating activities	309,006		289,779

Investing activities:
Property, plant and equipment additions	(348,313)		(317,686)
Other investing activities	(1,412)		389
Net cash (used in) investing activities	(349,725)		(317,297)

Financing activities:
Dividends paid on common stock	(66,440)		(60,952)
Common stock issued	99,435		71,759
Net (payments) borrowings of short-term debt	(349,500)		(83,120)
Long-term debt - issuances	400,000		400,000
Long-term debt - repayments	(5,727)		(302,871)
Distributions to noncontrolling interest	(8,520)		(9,251)
Other financing activities	(6,474)		(1,948)
Net cash provided by financing activities	62,774		13,617

Net change in cash, restricted cash and cash equivalents	22,055		(13,901)

Cash, restricted cash and cash equivalents at beginning of period	13,658		24,145
Cash, restricted cash and cash equivalents at end of period	$	35,713	$	10,244

Supplemental cash flow information:
Cash (paid) refunded during the period:
Interest (net of amounts capitalized)	$	(67,449)	$	(67,624)
Income taxes	$	1,896	$	1,790
Non-cash investing and financing activities:
Accrued property, plant and equipment purchases at June 30	$	59,916	$	83,486

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


	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

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

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

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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 June 30, 2020, December 31, 2019 and June 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 six months ended June 30, 2020 and June 30, 2019, and our financial condition as of June 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 six months ended June 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 June 30, 2019		Six Months Ended June 30, 2019
	(in millions)
Fuel, purchased power and cost of natural gas sold	$	0.4	$	1.3
Operations and maintenance	—		(0.3)
Taxes - property and production	—		(0.2)
Other operating expenses	(0.4)		(0.8)
	$	—	$	—

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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 its employees and the communities in which it operates while assuring the continuity of its business operations.

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 six months ended June 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, in conjunction with the annual goodwill impairment test as of October 1, 2020, is not expected to 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 reporting segments for the three and six months ended June 30, 2020 and 2019. Sales tax and other similar taxes are excluded from revenues.


Three Months Ended June 30, 2020	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues		Total
Customer types:	(in thousands)
Retail	$	141,804	$	120,594	$	—	$	14,846	$	(7,916)	$	269,328
Transportation	—		30,792		—		—		(138)		30,654
Wholesale	3,470		—		25,718		—		(24,476)		4,712
Market - off-system sales	3,538		23		—		—		(1,580)		1,981
Transmission/Other	12,761		9,189		—		—		(4,432)		17,518
Revenue from contracts with customers	$	161,573	$	160,598	$	25,718	$	14,846	$	(38,542)	$	324,193
Other revenues	1,627		512		404		570		(392)		2,721
Total revenues	$	163,200	$	161,110	$	26,122	$	15,416	$	(38,934)	$	326,914

Timing of revenue recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	14,846	$	(7,916)	$	6,930
Services transferred over time	161,573		160,598		25,718		—		(30,626)		317,263
Revenue from contracts with customers	$	161,573	$	160,598	$	25,718	$	14,846	$	(38,542)	$	324,193

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Three Months Ended June 30, 2019	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues		Total
Customer Types:
Retail	$	139,732	$	123,630	$	—	$	12,428	$	(7,041)	$	268,749
Transportation	—		28,623		—		—		(276)		28,347
Wholesale	6,781		—		15,062		—		(13,296)		8,547
Market - off-system sales	3,448		161		—		—		(1,335)		2,274
Transmission/Other	14,416		11,612		—		—		(4,199)		21,829
Revenue from contracts with customers	$	164,377	$	164,026	$	15,062	$	12,428	$	(26,147)	$	329,746
Other revenues	1,977		1,443		9,646		617		(9,541)		4,142
Total Revenues	$	166,354	$	165,469	$	24,708	$	13,045	$	(35,688)	$	333,888

Timing of Revenue Recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	12,428	$	(7,041)	$	5,387
Services transferred over time	164,377		164,026		15,062		—		(19,106)		324,359
Revenue from contracts with customers	$	164,377	$	164,026	$	15,062	$	12,428	$	(26,147)	$	329,746


Six Months Ended June 30, 2020	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues		Total
Customer types:	(in thousands)
Retail	$	290,444	$	418,841	$	—	$	29,249	$	(15,755)	$	722,779
Transportation	—		74,900		—		—		(277)		74,623
Wholesale	9,022		—		51,185		—		(48,088)		12,119
Market - off-system sales	8,405		161		—		—		(4,219)		4,347
Transmission/Other	27,618		21,761		—		—		(8,845)		40,534
Revenue from contracts with customers	$	335,489	$	515,663	$	51,185	$	29,249	$	(77,184)	$	854,402
Other revenues	1,850		6,220		903		1,372		(783)		9,562
Total revenues	$	337,339	$	521,883	$	52,088	$	30,621	$	(77,967)	$	863,964

Timing of revenue recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	29,249	$	(15,755)	$	13,494
Services transferred over time	335,489		515,663		51,185		—		(61,429)		840,908
Revenue from contracts with customers	$	335,489	$	515,663	$	51,185	$	29,249	$	(77,184)	$	854,402

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Six Months Ended June 30, 2019	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues		Total
Customer Types:
Retail	$	293,195	$	477,905	$	—	$	28,257	$	(15,169)	$	784,188
Transportation	—		73,140		—		—		(708)		72,432
Wholesale	15,124		—		30,531		—		(26,509)		19,146
Market - off-system sales	10,140		378		—		—		(3,559)		6,959
Transmission/Other	28,591		24,802		—		—		(8,402)		44,991
Revenue from contracts with customers	$	347,050	$	576,225	$	30,531	$	28,257	$	(54,347)	$	927,716
Other revenues	2,231		324		19,422		1,217		(19,212)		3,982
Total Revenues	$	349,281	$	576,549	$	49,953	$	29,474	$	(73,559)	$	931,698

Timing of Revenue Recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	28,257	$	(15,169)	$	13,088
Services transferred over time	347,050		576,225		30,531		—		(39,178)		914,628
Revenue from contracts with customers	$	347,050	$	576,225	$	30,531	$	28,257	$	(54,347)	$	927,716

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 June 30, 2020	External Operating Revenue							Inter-company Operating Revenue					Total Revenues
			Contract Customers		Other Revenues					Contract Customers	Other Revenues
Segment:
Electric Utilities	$	156,197	$	1,627		$	5,376	$	—		$	163,200
Gas Utilities	159,824		512			774		—			161,110
Power Generation	1,242		349			24,476		55			26,122
Mining	6,930		233			7,916		337			15,416
Inter-company eliminations	—		—			(38,542)		(392)			(38,934)
Total	$	324,193	$	2,721		$	—	$	—		$	326,914

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Three Months Ended June 30, 2019	External Operating Revenue							Inter-company Operating Revenue					Total Revenues
			Contract Customers		Other Revenues					Contract Customers	Other Revenues
Segment:
Electric Utilities	$	159,140	$	1,977		$	5,237	$	—		$	166,354
Gas Utilities	163,303		1,443			723		—			165,469
Power Generation	1,765		434			13,297		9,212			24,708
Mining	5,538		288			6,890		329			13,045
Inter-company eliminations	—		—			(26,147)		(9,541)			(35,688)
Total	$	329,746	$	4,142		$	—	$	—		$	333,888



Six Months Ended June 30, 2020	External Operating Revenue							Inter-company Operating Revenue					Total Revenues
			Contract Customers		Other Revenues					Contract Customers	Other Revenues
Segment:
Electric Utilities	$	323,700	$	1,850		$	11,789	$	—		$	337,339
Gas Utilities	514,111		6,220			1,552		—			521,883
Power Generation	3,097		792			48,088		111			52,088
Mining	13,494		700			15,755		672			30,621
Inter-company eliminations	—		—			(77,184)		(783)			(77,967)
Total	$	854,402	$	9,562		$	—	$	—		$	863,964



Six Months Ended June 30, 2019	External Operating Revenue							Inter-company Operating Revenue					Total Revenues
			Contract Customers		Other Revenues					Contract Customers	Other Revenues
Segment:
Electric Utilities	$	335,803	$	2,231		$	11,247	$	—		$	349,281
Gas Utilities	574,803		324			1,422		—			576,549
Power Generation	4,022		870			26,509		18,552			49,953
Mining	13,088		557			15,169		660			29,474
Inter-company eliminations	—		—			(54,347)		(19,212)			(73,559)
Total	$	927,716	$	3,982		$	—	$	—		$	931,698

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	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Adjusted operating income ^(a):
Electric Utilities	$	33,993	$	33,546	$	69,643	$	74,566
Gas Utilities	18,209		8,557		121,106		111,871
Power Generation	11,402		10,156		22,751		22,123
Mining	3,358		1,640		6,487		5,977
Corporate and Other	(29)		102		131		(405)
Operating income	66,933		54,001		220,118		214,132

Interest expense, net	(35,545)		(34,264)		(70,998)		(68,981)
Impairment of investment	—		—		(6,859)		—
Other income (expense), net	(1,863)		263		490		(526)
Income tax (expense)	(4,831)		(2,307)		(20,833)		(19,570)
Net income	24,694		17,693		121,918		125,055
Net income attributable to noncontrolling interest	(3,728)		(3,110)		(7,778)		(6,664)
Net income available for common stock	$	20,966	$	14,583	$	114,140	$	118,391

__________

(a) Adjusted operating income recognizes intersegment revenues and costs for Colorado Electric’s PPA with Black Hills Colorado IPP on an accrual basis rather than as a finance lease. This presentation of 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:	June 30, 2020		December 31, 2019
Segment:
Electric Utilities	$	2,982,841	$	2,900,983
Gas Utilities	4,052,860		4,032,339
Power Generation	407,107		417,715
Mining	79,774		77,175
Corporate and Other	167,350		130,245
Total assets	$	7,689,932	$	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:


	June 30, 2020		December 31, 2019
Accounts receivable, trade	$	122,650	$	144,747
Unbilled revenue	55,915		113,502
Less: Allowance for credit losses	(7,585)		(2,444)
Accounts receivable, net	$	170,980	$	255,805

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Changes to allowance for credit losses for the six months ended June 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 June 30,
2020	$	2,444	$	6,715	$	2,203	$	(3,777)	$	7,585
2019	$	3,209	$	4,913	$	1,870	$	(4,906)	$	5,086

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 six months ended June 30, 2020 by $2.0 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:


	June 30, 2020		December 31, 2019
Materials and supplies	$	92,284	$	82,809
Fuel - Electric Utilities	3,574		2,425
Natural gas in storage	10,129		31,938
Total materials, supplies and fuel	$	105,987	$	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:


	June 30, 2020		December 31, 2019
Accrued employee compensation, benefits and withholdings	$	59,701	$	62,837
Accrued property taxes	36,832		44,547
Customer deposits and prepayments	45,143		54,728
Accrued interest	31,757		31,868
Other (none of which is individually significant)	28,234		32,787
Total accrued liabilities	$	201,667	$	226,767

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(5) Regulatory Matters

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



	June 30, 2020		December 31, 2019

Regulatory assets
Deferred energy and fuel cost adjustments ^(a)	$	36,900	$	34,088
Deferred gas cost adjustments ^(a)	226		1,540
Gas price derivatives ^(a)	662		3,328
Deferred taxes on AFUDC^(b)	7,715		7,790
Employee benefit plans ^(c)	115,416		115,900
Environmental^(a)	1,426		1,454

Loss on reacquired debt^(a)	23,820		24,777
Renewable energy standard adjustment ^(a)	1		1,622
Deferred taxes on flow through accounting^(c)	44,940		41,220
Decommissioning costs ^(b)	9,854		10,670
Gas supply contract termination ^(a)	5,521		8,485
Other regulatory assets^(a)	25,831		20,470
Total regulatory assets	272,312		271,344
Less current regulatory assets	(51,745)		(43,282)
Regulatory assets, non-current	$	220,567	$	228,062

Regulatory liabilities
Deferred energy and gas costs^(a)	$	28,279	$	17,278
Employee benefit plan costs and related deferred taxes^(c)	41,025		43,349
Cost of removal^(a)	168,137		166,727

Excess deferred income taxes ^(c)	288,796		285,438
TCJA revenue reserve	3,027		3,418
Other regulatory liabilities^(c)	36,557		20,442
Total regulatory liabilities	565,821		536,652
Less current regulatory liabilities	(59,428)		(33,507)
Regulatory liabilities, non-current	$	506,393	$	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.

Nebraska Gas

Jurisdictional Consolidation and Rate Review

On June 1, 2020, Nebraska Gas filed a rate review with the NPSC to consolidate rates, tariffs, and services of its two existing gas distribution territories. The rate review requests $17 million in new revenue, as well as renewal and expansion of the SSIR, to recover investments in safety, reliability and system integrity. The rate review requests a capital structure of 50% equity and 50% debt and a return on equity of 10% for investments Nebraska Gas made in its natural gas pipeline system. Nebraska statute allows for implementation of interim rates 90 days after filing a rate review. New rates are expected to be effective in early 2021.

Black Hills Wyoming and Wyoming Electric

Wygen I FERC Filing

On June 1, 2020, Black Hills Wyoming and Wyoming Electric filed a settlement agreement with the FERC. The agreement represents a resolution of all issues in the joint application filed with the FERC on August 2, 2019 for approval of a new 60 MW PPA. On July 10, 2020, a judge certified the settlement to the FERC and a decision is expected by the end of 2020. If approved, Wyoming Electric will continue to receive 60 MW of capacity and energy from the Wygen I power plant. The new agreement would commence on January 1, 2022, replacing the existing PPA, and would continue for 11 years.

Colorado Gas

Jurisdictional Consolidation and Rate Review

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 April 14, 2020 the CPUC deliberated on the application and on May 19, 2020 issued a final order. The order 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. In accordance with the final order, Colorado Gas will file a new system integrity rider proposal prior to the end of 2020. Colorado Gas also plans to file a new rate review by the end of 2020.

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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 June 30,						Six Months Ended June 30,
	2020		2019		2020		2019

Net income available for common stock	$	20,966	$	14,583	$	114,140	$	118,391

Weighted average shares - basic	62,573		60,467		62,175		60,195
Dilutive effect of:
Equity compensation	44		139		55		138
Weighted average shares - diluted	62,617		60,606		62,230		60,333

Earnings per share of common stock:
Earnings per share, Basic	$	0.34	$	0.24	$	1.84	$	1.97
Earnings per share, Diluted	$	0.33	$	0.24	$	1.83	$	1.96

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


	Three Months Ended June 30,			Six Months Ended June 30,
	2020	2019	2020	2019

Equity compensation	29	—	26	—
Restricted stock	76	—	36	—

Anti-dilutive shares	105	—	62	—

(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:


	June 30, 2020						December 31, 2019
	Balance Outstanding		Letters of Credit ^(a)		Balance Outstanding		Letters of Credit ^(a)
Revolving Credit Facility	$	—	$	11,999	$	—	$	30,274
CP Program	—		—		349,500		—
Total	$	—	$	11,999	$	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 six months ended June 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 six months ended June 30, 2020 were $(350) 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 June 30, 2020:

As of June 30, 2020

Covenant Requirement

Consolidated Indebtedness to Capitalization Ratio

58.7%

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 six months ended June 30, 2020. During the three months ended June 30, 2019, we issued a total of 0.7 million shares of common stock under the ATM for proceeds of $49 million, net of $0.5 million in issuance costs. During the six months ended June 30, 2019, we issued a total of 0.9 million shares of common stock under the ATM for proceeds of $69 million, net of $0.7 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;

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

Credit Risk

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

For production and generation activities, 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 six months ended June 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 $1.5 million and $2.0 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 July 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 effective portion of the gain or loss on these designated derivatives is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Fuel, purchased power and cost of natural gas sold. 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:


		June 30, 2020			December 31, 2019
	Units	Notional Amounts	Maximum Term (months)^(a)	Notional Amounts	Maximum Term (months)^(a)
Natural gas futures purchased	MMBtus	660,000	9	1,450,000	12
Natural gas options purchased, net	MMBtus	950,000	9	3,240,000	3
Natural gas basis swaps purchased	MMBtus	520,000	6	1,290,000	12
Natural gas over-the-counter swaps, net ^(b)	MMBtus	6,480,000	23	4,600,000	24
Natural gas physical contracts, net ^(c)	MMBtus	8,085,376	9	13,548,235	12
Electric wholesale contracts ^(c)	MWh	141,225	6	—	0

__________

(a) Term reflects the maximum forward period hedged.

(b) As of June 30, 2020, 1,776,900 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 June 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	June 30, 2020		December 31, 2019
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets, current	$	66	$	1
Noncurrent commodity derivatives	Other assets, non-current	83		3
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current	(324)		(490)
Noncurrent commodity derivatives	Other deferred credits and other liabilities	—		(29)
Total derivatives designated as hedges		$	(175)	$	(515)

Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets, current	$	1,515	$	341
Noncurrent commodity derivatives	Other assets, non-current	191		2
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current	(297)		(1,764)
Noncurrent commodity derivatives	Other deferred credits and other liabilities	(15)		(63)
Total derivatives not designated as hedges		$	1,394	$	(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 six months ended June 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 June 30,							Three Months Ended June 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	$	713	$	713	Interest expense	$	(713)	$	(713)
Commodity derivatives	11		(601)		Fuel, purchased power and cost of natural gas sold	(70)		83
Total	$	724	$	112		$	(783)	$	(630)


	Six Months Ended June 30,							Six Months Ended June 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	$	1,426	$	1,426	Interest expense	$	(1,426)	$	(1,426)
Commodity derivatives	268		(921)		Fuel, purchased power and cost of natural gas sold	(556)		637
Total	$	1,694	$	505		$	(1,982)	$	(789)

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Based on June 30, 2020 prices, a $0.2 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.

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 six months ended June 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 June 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	$	(204)	$	—
Commodity derivatives - Natural Gas	Fuel, purchased power and cost of natural gas sold	449		(1,185)
		$	245	$	(1,185)


		Six Months Ended June 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	$	1,158	$	—
Commodity derivatives - Natural Gas	Fuel, purchased power and cost of natural gas sold	1,215		(1,160)
		$	2,373	$	(1,160)

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 the hedges in our Gas Utilities were $0.7 million and $3.3 million as of June 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 June 30, 2020
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting		Total
	(in thousands)
Assets:
Commodity derivatives — Gas Utilities	$	—	$	1,114	$	—	$	(417)	$	697
Commodity derivatives — Electric Utilities	—		1,158		—		—		1,158
Total	$	—	$	2,272	$	—	$	(417)	$	1,855

Liabilities:
Commodity derivatives — Gas Utilities	$	—	$	1,553	$	—	$	(917)	$	636
Total	$	—	$	1,553	$	—	$	(917)	$	636


	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:


	June 30, 2020						December 31, 2019
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current maturities ^(a)	$	3,537,194	$	4,051,912	$	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 June 30,						Six Months Ended June 30,
						2020	2019				2020	2019
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	(713)	$	(713)		$	(1,426)	$	(1,426)
Commodity contracts	Fuel, purchased power and cost of natural gas sold	(70)		83			(556)		637
		(783)		(630)			(1,982)		(789)
Income tax	Income tax benefit (expense)	186		153			471		188
Total reclassification adjustments related to cash flow hedges, net of tax		$	(597)	$	(477)		$	(1,511)	$	(601)

Amortization of components of defined benefit plans:
Prior service cost	Operations and maintenance	$	25	$	20		$	55	$	39

Actuarial gain (loss)	Operations and maintenance	(597)		(221)			(1,194)		(441)
		(572)		(201)			(1,139)		(402)
Income tax	Income tax benefit (expense)	176		47			264		95
Total reclassification adjustments related to defined benefit plans, net of tax		$	(396)	$	(154)		$	(875)	$	(307)
Total reclassifications		$	(993)	$	(631)		$	(2,386)	$	(908)

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	—		(220)		55		(165)
Amounts reclassified from AOCI	1,087		424		875		2,386
As of June 30, 2020	$	(14,035)	$	(252)	$	(14,147)	$	(28,434)


	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	—		(219)		—		(219)
Amounts reclassified from AOCI	1,091		(490)		307		908
As of June 30, 2019	$	(16,216)	$	(381)	$	(9,630)	$	(26,227)

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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 six months ended June 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 June 30, 2020, we estimate the unfunded status of our employee benefit plans to be approximately $50 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 June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Service cost	$	1,353	$	1,345	$	2,706	$	2,691
Interest cost	3,356		4,344		6,713		8,687
Expected return on plan assets	(5,648)		(6,100)		(11,296)		(12,200)
Prior service cost	—		7		—		13
Net loss (gain)	2,093		940		4,186		1,881
Net periodic benefit cost	$	1,154	$	536	$	2,309	$	1,072

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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 June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Service cost	$	514	$	454	$	1,028	$	908
Interest cost	413		563		825		1,123
Expected return on plan assets	(46)		(58)		(91)		(115)
Prior service (benefit)	(137)		(100)		(274)		(199)
Net loss (gain)	5		—		10		—
Net periodic benefit cost	$	749	$	859	$	1,498	$	1,717

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 June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Service cost	$	1,817	$	692	$	447	$	1,977
Interest cost	275		324		550		648
Prior service cost	—		1		—		1
Net loss (gain)	426		134		852		268
Net periodic benefit cost	$	2,518	$	1,151	$	1,849	$	2,894

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 six months of 2020 and anticipated contributions for 2020 and 2021 are as follows (in thousands):


	Contributions Made		Additional Contributions		Contributions
	Six Months Ended June 30, 2020		Anticipated for 2020		Anticipated for 2021
Defined Benefit Pension Plan	$	12,700	$	—	$	12,700
Non-pension Defined Benefit Postretirement Healthcare Plans	$	2,670	$	2,671	$	5,364
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans	$	710	$	710	$	1,614

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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 PPA. This agreement expires June 30, 2025.

(14) Income Taxes

CARES Act

On March 27, 2020, the President signed the Coronavirus Aid, Relief, and Economic Security Act (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.

During the second quarter 2020, we utilized the payroll tax deferral provision which allowed us to defer payment of approximately $2.9 million 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 June 30, 2020 Compared to the Three Months Ended June 30, 2019.

Income tax (expense) for the three months ended June 30, 2020 was $(4.8) million compared to $(2.3) million reported for the same period in 2019. For the three months ended June 30, 2020, the effective tax rate was 16.4% compared to 11.5% for the same period in 2019. The higher effective tax rate is primarily due to a prior year discrete tax benefit related to repairs and certain indirect costs.

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

Income tax (expense) for the six months ended June 30, 2020 was $(21) million compared to $(20) million reported for the same period in 2019. For the six months ended June 30, 2020, the effective tax rate was 14.6% compared to 13.5% for the same period in 2019. The higher effective tax rate is primarily due to a prior year discrete tax benefit related to repairs and certain indirect costs and a current year discrete tax adjustment related to the impairment of our investment in equity securities of a privately held oil and gas company partially offset by increased tax benefits from forecasted federal production tax credits associated with new wind assets.

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(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:


	June 30, 2020		December 31, 2019
Investment in privately held oil and gas company	$	1,500	$	8,359
Cash surrender value of life insurance contracts	13,423		13,056
Other investments	515		514
Total investments	$	15,438	$	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 Notes 8 and 13.

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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 six months ended June 30, 2020 and 2019, and our financial condition as of June 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 six months ended June 30, 2020, we have experienced limited impacts to our financial results and operational activities due to COVID-19. Estimated decreases to gross margins driven primarily by lower volumes, increased costs due to sequestration of mission critical and essential employees and increased bad debt expense were partially offset by decreased training, travel and outside services related expenses.

During the three months ended June 30, 2020, COVID-19 had a limited impact on revenues and customer loads, as the decline in volumes from commercial and certain industrial and transport customers was partially offset by higher residential usage. Decline in revenues and customer loads for the six months ended June 30, 2020, when compared to the same period in the prior year, were driven primarily by weather. 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 $1.5 million and $2.0 million for the three and six months ended June 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 some 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 six months ended June 30, 2020, the Company also utilized a combination of its $750 million Revolving Credit Facility and CP Program to meet its funding requirements. Disruptions in the commercial paper markets at the outset of the COVID-19 pandemic in the U.S. have since improved. The Company has no material debt maturities until late 2023 and as of June 30, 2020, had $770 million of liquidity which included $32 million of cash and $738 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 six months ended June 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. Some of the actions the Company has taken include implementing protocols for our field operations personnel to continue to safely and effectively interact with our customers, asking employees to work from home to the extent possible, quarantining employees if they have traveled to an at-risk area, limiting travel to only mission-critical purposes and sequestering essential employees.

As we look forward to the second half of 2020, we anticipate that our operating results could potentially be further affected by COVID-19, as discussed in detail in our Risk Fact ors.

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.

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.

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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 on schedule and on budget and expected to be in service by year-end 2020.

•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 June 19, 2020, Colorado Electric submitted its 120-day report to the CPUC, which provided a detailed analysis of the proposals received during its competitive solicitation and outlined its preferred bid, a 200 MW solar project, along with several back-up options, in the Renewable Advantage plan. The bidding process for new renewable energy projects concluded in February 2020, attracting interest from developers in southern Colorado and across the U.S. In total, Colorado Electric received 54 bids from 25 bidders for renewable energy projects at varying sizes, prices, technology types and locations, with the majority of projects to be sited in the city of Pueblo and Pueblo County. A hearing to review the 120-day report with the CPUC is scheduled for August 18, 2020. The project is scheduled to be in service in 2023.

•On June 1, 2020, Black Hills Wyoming and Wyoming Electric filed a settlement agreement with the FERC. The agreement represents a resolution of all issues in the joint application filed with the FERC on August 2, 2019 for approval of a new 60 MW PPA. On July 10, 2020, a judge certified the settlement to the FERC and a decision is expected by the end of 2020. If approved, Wyoming Electric will continue to receive 60 MW of capacity and energy from the Wygen I power plant. The new agreement would commence on January 1, 2022, replacing the existing PPA and would continue for 11 years.

•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 January 1, 2020, Nebraska Gas completed the legal consolidation of its two natural gas utilities, having received approval from the NPSC on October 29, 2019. On June 1, 2020, Nebraska Gas filed a rate review with the NPSC to consolidate rates, tariffs, and services of its two existing gas distribution territories. The rate review requests $17 million in new revenue, as well as an extension of the SSIR, to recover investments in safety, reliability and system integrity. The rate review requests a capital structure of 50% equity and 50% debt and a return on equity of 10% for investments Nebraska Gas made in its natural gas pipeline system. Nebraska statute allows for implementation of interim rates 90 day after filing a rate review. New rates are expected to be effective in early 2021.

•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 April 14, 2020 the CPUC deliberated on the application and on May 19, 2020 issued a final order. The order 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. In accordance with the final order, Colorado Gas will file a new system integrity rider proposal prior to the end of 2020. Colorado Gas also plans to file a new rate review by the end of 2020.

•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.

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Power Generation

•On June 1, 2020, Black Hills Wyoming and Wyoming Electric filed a settlement agreement with the FERC. The agreement represents a resolution of all issues in the joint application filed with the FERC 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 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 June 30,							Six Months Ended June 30,
			2020		2019			2020		2019
Revenue
Revenue	$	365,848	$	369,576		$	941,931	$	1,005,257
Inter-company eliminations	(38,934)		(35,688)			(77,967)		(73,559)
	$	326,914	$	333,888		$	863,964	$	931,698
Adjusted operating income^(a)
Electric Utilities	$	33,993	$	33,546		$	69,643	$	74,566
Gas Utilities	18,209		8,557			121,106		111,871
Power Generation	11,402		10,156			22,751		22,123
Mining	3,358		1,640			6,487		5,977
Corporate and Other	(29)		102			131		(405)
Operating income	66,933		54,001			220,118		214,132

Interest expense, net	(35,545)		(34,264)			(70,998)		(68,981)
Impairment of investment	—		—			(6,859)		—
Other income (expense), net	(1,863)		263			490		(526)
Income tax (expense)	(4,831)		(2,307)			(20,833)		(19,570)
Net income	24,694		17,693			121,918		125,055
Net income attributable to noncontrolling interest	(3,728)		(3,110)			(7,778)		(6,664)
Net income available for common stock	$	20,966	$	14,583		$	114,140	$	118,391

Earnings per share, Basic	$	0.34	$	0.24		$	1.84	$	1.97
Earnings per share, Diluted	$	0.33	$	0.24		$	1.83	$	1.96

__________

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

The variance to the prior year included the following:

•COVID-19 related impacts to consolidated results included $2.4 million of lower gross margin driven primarily by lower volumes, $2.0 million of costs due to sequestration of mission-critical and essential employees and $1.5 million of additional bad debt expense which were partially offset by $3.4 million of lower travel, training, and outside services expenses;

•Electric Utilities’ adjusted operating income increased $0.4 million primarily due to favorable spring weather and lower operating expenses mostly offset by a rider true-up and COVID-19 impacts to margin from lower commercial volumes;

•Gas Utilities’ adjusted operating income increased $9.7 million primarily due to new customer rates in Wyoming, prior year direct and indirect impacts from significant rainfall and flooding in our service territories, mark-to-market gains on non-utility natural gas commodity contracts and lower operating expenses partially offset by COVID-19 impacts to margin from lower volumes from certain industrial and transport customers;

•Power Generation’s adjusted operating income increased $1.2 million primarily due to increased MWh sold driven by new wind assets and strong availability;

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•Mining’s adjusted operating income increased $1.7 million primarily due to higher tons sold driven by prior year planned and unplanned facility outages;

•Interest expense increased $1.3 million primarily due to higher debt balances partially offset by lower rates;

•Other expense increased $2.1 million primarily due to increased costs for our non-qualified benefit plan driven by market performance on plan assets; and

•Income tax expense increased $2.5 million primarily due to a prior year discrete tax benefit related to repairs and certain indirect costs.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019:

The variance to the prior year included the following:

•COVID-19 related impacts to consolidated results included $2.4 million of lower gross margin driven primarily by lower volumes, $2.0 million of costs due to sequestration of mission-critical and essential employees and $2.0 million of additional bad debt expense which were partially offset by $3.4 million of lower travel, training, and outside services expenses;

•Electric Utilities’ adjusted operating income decreased $4.9 million primarily due to COVID-19 impacts to margin from lower commercial volumes, lower power marketing margins and higher operating expenses partially offset by increased mark-to-market on wholesale energy contracts;

•Gas Utilities’ adjusted operating income increased $9.2 million primarily due to new customer rates in Wyoming, prior year amortization of excess deferred income taxes, customer growth, mark-to-market gains on non-utility natural gas commodity contracts and lower operating expenses partially offset by lower heating demand from warmer winter weather and COVID-19 impacts to margin from lower volumes from certain industrial and transport customers;

•Interest expense increased $2.0 million primarily due to higher debt balances partially offset by lower rates; and

•A $6.9 million pre-tax non-cash impairment of our investment in equity securities of a privately held oil and gas company.

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 measure. 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 June 30,										Six Months Ended June 30,
	2020		2019		Variance		2020		2019		Variance
	(in thousands)
Revenue	$	163,200	$	166,354	$	(3,154)	$	337,339	$	349,281	$	(11,942)

Total fuel and purchased power	59,053		62,128		(3,075)		123,513		135,411		(11,898)

Gross margin (non-GAAP)	104,147		104,226		(79)		213,826		213,870		(44)

Operations and maintenance	47,031		48,733		(1,702)		97,530		95,877		1,653
Depreciation and amortization	23,123		21,947		1,176		46,653		43,427		3,226
Total operating expenses	70,154		70,680		(526)		144,183		139,304		4,879

Adjusted operating income	$	33,993	$	33,546	$	447	$	69,643	$	74,566	$	(4,923)

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

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


	(in millions)
COVID-19 impacts ^(a)	$	(1.5)
Rider recovery and true-up ^(b)	(1.3)
Weather	2.4
Other	0.3
Total decrease in Gross margin (non-GAAP)	$	(0.1)

____________________

(a) The impacts to Electric Utilities gross margin from COVID-19 were driven by reduced commercial volumes partially offset by higher residential usage.

(b) Gross margin decreased due to a $2.5 million rider true-up, which was partially offset by $1.2 million of increased rider recovery.

Operations and maintenance expense decreased primarily due to lower generation expenses driven by timing of planned outages and lower employee costs. COVID-19 impacts to operations and maintenance expense included $1.6 million of expenses related to the sequestration of essential employees and $0.5 million of additional bad debt expense which were offset by $2.0 million of lower travel, training and outside services related expenses.

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

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Six Months Ended June 30, 2020 Compared to the Six Months Ended June 30, 2019:

Gross margin for the six months ended June 30, 2020 remained constant as a result of the following:


	(in millions)
COVID-19 impacts ^(a)	$	(1.5)
Off-system power marketing	(1.2)
Rider recovery and true-up ^(b)	(0.3)
Mark-to-market on wholesale energy contracts	1.2
Weather	0.6
Residential customer growth	0.4
Other	0.8
Total change in Gross margin (non-GAAP)	$	—

____________________

(a) The impacts to Electric Utilities gross margin from COVID-19 were driven by reduced commercial volumes partially offset by higher residential usage.

(b) Gross margin decreased due to a $2.5 million rider true-up, which was mostly offset by $2.2 million of increased rider recovery.

Operations and maintenance expense increased primarily due to $1.4 million of expenses related to the municipalization efforts in Pueblo, Colorado. COVID-19 impacts to operations and maintenance expense included $1.6 million of expenses related to the sequestration of essential employees and $0.6 million of additional bad debt expense which were offset by $2.0 million of lower travel, training and outside services 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 June 30,						Six Months Ended June 30,				Three Months Ended June 30,		Six Months Ended June 30,
	2020		2019		2020		2019		2020	2019	2020	2019

Residential	$	50,148	$	45,700	$	104,653	$	103,338	334,682	301,481	707,832	690,659
Commercial	56,400		59,739		114,223		120,702		459,632	490,329	953,940	995,902
Industrial	31,896		31,697		64,065		64,137		459,533	445,837	920,165	872,451
Municipal	4,020		4,253		7,898		8,392		38,372	38,283	74,771	74,919
Subtotal Retail Revenue - Electric	142,464		141,389		290,839		296,569		1,292,219	1,275,930	2,656,708	2,633,931
Contract Wholesale ^(a)	3,470		6,781		9,023		15,124		87,253	194,222	219,031	417,242
Off-system/Power Marketing Wholesale	3,537		3,448		8,404		10,140		136,311	135,091	302,096	275,941
Other	13,729		14,736		29,073		27,448		—	—	—	—
Total Revenue and Energy Sold	163,200		166,354		337,339		349,281		1,515,783	1,605,243	3,177,835	3,327,114
Other Uses, Losses or Generation, net ^(b)	—		—		—		—		85,185	89,866	176,056	186,866
Total Revenue and Energy	163,200		166,354		337,339		349,281		1,600,968	1,695,109	3,353,891	3,513,980
Less cost of fuel and purchased power	59,053		62,128		123,513		135,411
Gross Margin (non-GAAP)	$	104,147	$	104,226	$	213,826	$	213,870

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	Electric Revenue (in thousands)						Gross Margin (non-GAAP) (in thousands)				Quantities Sold (MWh) ^(b)
Three Months Ended June 30,	2020		2019		2020		2019		2020	2019
Colorado Electric	$	57,897	$	55,412	$	32,455	$	31,051	547,814	485,346
South Dakota Electric ^(a)	62,587		69,246		49,973		50,865		570,528	757,640
Wyoming Electric	42,716		41,696		21,719		22,310		482,626	452,123
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold	$	163,200	$	166,354	$	104,147	$	104,226	1,600,968	1,695,109



	Electric Revenue (in thousands)						Gross Margin (non-GAAP) (in thousands)				Quantities Sold (MWh) ^(b)
Six Months Ended June 30,	2020		2019		2020		2019		2020	2019
Colorado Electric	$	116,455	$	115,259	$	64,725	$	62,495	1,098,585	977,028
South Dakota Electric ^(a)	134,198		148,287		105,597		107,173		1,255,752	1,602,641
Wyoming Electric	86,686		85,735		43,504		44,202		999,554	934,311
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold	$	337,339	$	349,281	$	213,826	$	213,870	3,353,891	3,513,980

________________

(a) Revenue and purchased power for the three and six months ended June 30, 2020 as well as associated quantities, for certain wholesale contracts have been presented on a net basis. Amounts for the three and six months ended June 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 June 30,			Six Months Ended June 30,
Quantities Generated and Purchased (MWh)	2020	2019	2020	2019

Coal-fired	572,030	471,840	1,119,859	1,057,135
Natural Gas and Oil	86,798	86,475	254,542	211,132
Wind	63,628	56,505	137,178	111,924
Total Generated	722,456	614,820	1,511,579	1,380,191

Purchased ^(a)	878,512	1,080,289	1,842,312	2,133,789
Total Generated and Purchased	1,600,968	1,695,109	3,353,891	3,513,980


	Three Months Ended June 30,			Six Months Ended June 30,
Quantities Generated and Purchased (MWh)	2020	2019	2020	2019
Generated:
Colorado Electric	80,456	91,886	174,507	192,416
South Dakota Electric	442,566	315,925	915,532	773,294
Wyoming Electric	199,434	207,009	421,540	414,481
Total Generated	722,456	614,820	1,511,579	1,380,191
Purchased:
Colorado Electric	467,358	393,460	924,078	784,612
South Dakota Electric ^(a)	127,962	441,715	340,220	829,347
Wyoming Electric	283,192	245,114	578,014	519,830
Total Purchased	878,512	1,080,289	1,842,312	2,133,789

Total Generated and Purchased	1,600,968	1,695,109	3,353,891	3,513,980

________________

(a) Purchased power quantities for the three and six months ended June 30, 2020, for certain wholesale contracts have been presented on a net basis. Amounts for the three and six months ended June 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.

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	Three Months Ended June 30,
Degree days	2020				2019
	Actual	Variance from Normal		Actual	Variance from Normal
Heating Degree Days:
Colorado Electric	518	(18)	%	603	(5)	%
South Dakota Electric	1,127	10	%	1,279	25	%
Wyoming Electric	1,149	(4)	%	1,359	12	%
Combined^(a)	853	(3)	%	986	12	%

Cooling Degree Days:
Colorado Electric	382	83	%	147	(30)	%
South Dakota Electric	120	21	%	38	(62)	%
Wyoming Electric	101	102	%	29	(42)	%
Combined^(a)	236	69	%	86	(38)	%


	Six Months Ended June 30,
Degree days	2020				2019
	Actual	Variance from Normal		Actual	Variance from Normal
Heating Degree Days:
Colorado Electric	2,974	(9)	%	3,152	(4)	%
South Dakota Electric	4,238	—	%	5,195	23	%
Wyoming Electric	4,148	(1)	%	4,557	3	%
Combined^(a)	3,642	(4)	%	4,132	8	%

Cooling Degree Days:
Colorado Electric	382	83	%	147	(30)	%
South Dakota Electric	120	21	%	38	(62)	%
Wyoming Electric	101	102	%	29	(42)	%
Combined^(a)	236	69	%	86	(38)	%

____________________

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


	Three Months Ended June 30,						Six Months Ended June 30,
Contracted Power Plant Fleet Availability ^(a)	2020		2019		2020		2019
Coal-fired plants ^(b)	94.1	%	79.2	%	92.5	%	87.7	%
Natural gas-fired plants and Other plants^(c)	78.3	%	89.3	%	80.9	%	90.0	%
Wind	98.1	%	94.5	%	98.6	%	95.6	%
Total Availability	85.0	%	86.4	%	86.0	%	89.7	%

Wind Capacity Factor	39.0	%	34.8	%	42.3	%	38.7	%

____________________

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

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

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Gas Utilities


	Three Months Ended June 30,										Six Months Ended June 30,
	2020		2019		Variance		2020		2019		Variance
	(in thousands)
Revenue:
Natural gas - regulated	$	148,432	$	149,942	$	(1,510)	$	484,329	$	533,817	$	(49,488)
Other - non-regulated services	12,678		15,527		(2,849)		37,554		42,732		(5,178)
Total revenue	161,110		165,469		(4,359)		521,883		576,549		(54,666)

Cost of sales:
Natural gas - regulated	42,910		51,108		(8,198)		196,909		252,158		(55,249)
Other - non-regulated services	1,712		5,876		(4,164)		3,074		12,105		(9,031)
Total cost of sales	44,622		56,984		(12,362)		199,983		264,263		(64,280)

Gross margin (non-GAAP)	116,488		108,485		8,003		321,900		312,286		9,614

Operations and maintenance	72,415		77,131		(4,716)		149,709		155,069		(5,360)
Depreciation and amortization	25,864		22,797		3,067		51,085		45,346		5,739
Total operating expenses	98,279		99,928		(1,649)		200,794		200,415		379

Adjusted operating income	$	18,209	$	8,557	$	9,652	$	121,106	$	111,871	$	9,235

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

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



	(in millions)
New rates	$	3.6
Weather	2.8
Mark-to-market on non-utility natural gas commodity contracts	1.6
Customer growth - distribution	0.6
COVID-19 impacts ^(a)	(0.9)
Decreased transport and transmission	(0.8)
Other	1.1
Total increase in Gross margin (non-GAAP)	$	8.0

____________________

(a) The impacts to Gas Utilities gross margin from COVID-19 were primarily driven by reduced volumes from certain industrial and transport customers.

Operations and maintenance expense decreased primarily due to $1.5 million of lower employee costs and $1.5 million of lower outside service expenses. COVID-19 impacts to operations and maintenance expense included $1.4 million of lower travel, training and outside services related expenses which were partially offset by $1.0 million of additional bad debt expense. Various other expenses comprised the remainder of the difference when compared to the same period in the prior year.

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

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Six Months Ended June 30, 2020 Compared to the Six Months Ended June 30, 2019:

Gross margin for the six months ended June 30, 2020 increased as a result of:


	(in millions)
New rates	$	9.2
Prior year amortization of excess deferred income taxes	2.7
Customer growth - distribution	2.1
Mark-to-market on non-utility natural gas commodity contracts	2.4
Weather	(7.6)
COVID-19 impacts ^(a)	(0.9)
Other	1.7
Total increase in Gross margin (non-GAAP)	$	9.6

____________________

(a) The impacts to Gas Utilities gross margin from COVID-19 were primarily driven by reduced volumes from certain industrial and transport customers.

Operations and maintenance expense decreased primarily due to $3.4 million of lower outside services expenses, $1.9 million of lower employee costs partially offset by $0.9 million of higher property taxes due to a higher asset base. COVID-19 impacts to operations and maintenance expense included $1.4 million of lower travel, training and outside services related expenses which were offset by $1.4 million of additional bad debt expense. Various other expenses comprised the remainder of the difference when compared to the same period in the prior year.

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 June 30,						Three Months Ended June 30,				Three Months Ended June 30,
	2020		2019		2020		2019		2020	2019

Residential	$	83,240	$	85,093	$	56,368	$	52,670	8,501,835	7,919,158
Commercial	27,441		30,984		15,336		14,926		3,965,529	4,194,879
Industrial	6,059		3,980		2,140		1,320		2,036,553	997,942
Other	828		887		827		887		—	—
Total Distribution	117,568		120,944		74,671		69,803		14,503,917	13,111,979

Transportation and Transmission	30,864		28,998		30,851		29,031		30,243,501	32,767,310

Total Regulated	148,432		149,942		105,522		98,834		44,747,418	45,879,289

Non-regulated Services	12,678		15,527		10,966		9,651

Total Gas Revenue & Gross Margin (non-GAAP)	$	161,110	$	165,469	$	116,488	$	108,485

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

Residential	$	290,471	$	326,222	$	159,489	$	157,727	36,732,630	40,757,176
Commercial	107,677		127,123		48,855		50,084		16,800,332	19,185,727
Industrial	11,259		9,994		4,183		3,337		3,097,605	2,180,469
Other	(415)		(3,467)		(415)		(3,467)		—	—
Total Distribution	408,992		459,872		212,112		207,681		56,630,567	62,123,372

Transportation and Transmission	75,337		73,945		75,308		73,978		75,299,008	79,083,470

Total Regulated	484,329		533,817		287,420		281,659		131,929,575	141,206,842

Non-regulated Services	37,554		42,732		34,480		30,627

Total Gas Revenue & Gross Margin (non-GAAP)	$	521,883	$	576,549	$	321,900	$	312,286



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

Arkansas Gas	$	28,733	$	26,236	$	21,906	$	18,617	4,906,236	4,542,917
Colorado Gas	28,613		36,713		18,807		19,755		5,046,844	6,067,353
Iowa Gas	21,407		23,714		14,355		14,588		5,521,119	7,484,272
Kansas Gas	18,486		17,379		12,460		11,957		6,722,914	6,290,716
Nebraska Gas	40,466		39,315		30,719		27,709		13,822,478	14,816,996
Wyoming Gas	23,405		22,112		18,241		15,859		8,727,827	6,677,035
Total Gas Revenue & Gross Margin (non-GAAP)	$	161,110	$	165,469	$	116,488	$	108,485	44,747,418	45,879,289



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

Arkansas Gas	$	103,578	$	105,627	$	70,761	$	62,899	15,869,184	16,967,113
Colorado Gas	101,219		113,184		56,813		57,355		18,143,249	19,244,278
Iowa Gas	76,231		89,355		35,683		37,638		19,801,392	23,147,959
Kansas Gas	51,980		58,596		31,063		30,076		16,637,772	16,733,986
Nebraska Gas	124,132		148,112		82,385		83,782		40,331,514	43,816,014
Wyoming Gas	64,743		61,675		45,195		40,536		21,146,464	21,297,492
Total Gas Revenue & Gross Margin (non-GAAP)	$	521,883	$	576,549	$	321,900	$	312,286	131,929,575	141,206,842

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.

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	Three Months Ended June 30,
	2020			2019
Heating Degree Days	Actual	Variance from Normal	Actual	Variance from Normal
Arkansas Gas ^(a)	353	7%	246	(25)%
Colorado Gas	809	(15)%	1,017	6%
Iowa Gas	783	14%	738	8%
Kansas Gas ^(a)	477	7%	425	(5)%
Nebraska Gas	692	9%	664	5%
Wyoming Gas	1,216	—%	1,397	15%
Combined ^(b)	688	2%	795	5%



	Six Months Ended June 30,
	2020			2019
Heating Degree Days:	Actual	Variance from Normal	Actual	Variance from Normal
Arkansas Gas ^(a)	2,012	(17)%	2,347	(4)%
Colorado Gas	3,638	(6)%	4,047	4%
Iowa Gas	3,964	(2)%	4,568	13%
Kansas Gas ^(a)	2,781	(4)%	3,204	10%
Nebraska Gas	3,527	(4)%	4,147	13%
Wyoming Gas	4,433	1%	4,910	11%
Combined Gas ^(b)	3,606	(4)%	4,244	10%

___________

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

(b) The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas due to its weather normalization mechanism. Arkansas 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.

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Power Generation


	Three Months Ended June 30,										Six Months Ended June 30,
	2020		2019		Variance		2020		2019		Variance
	(in thousands)
Revenue	$	26,122	$	24,708	$	1,414	$	52,088	$	49,953	$	2,135

Fuel expense	2,087		2,024		63		4,372		4,650		(278)
Operations and maintenance	7,350		7,809		(459)		14,347		13,871		476
Depreciation and amortization	5,283		4,719		564		10,618		9,309		1,309
Total operating expense	14,720		14,552		168		29,337		27,830		1,507

Adjusted operating income	$	11,402	$	10,156	$	1,246	$	22,751	$	22,123	$	628

Three Months Ended June 30, 2020 Compared to the Three Months Ended June 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 higher depreciation from new wind assets and COVID-19 impacts of $0.4 million of expenses related to the sequestration of essential employees partially offset by lower maintenance costs due to a prior year planned outage at Pueblo Airport Generation.

Six Months Ended June 30, 2020 Compared to the Six Months Ended June 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 higher 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.

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The following table summarizes MWh for our Power Generation segment:


	Three Months Ended June 30,			Six Months Ended June 30,
	2020	2019	2020	2019
Quantities Sold, Generated and Purchased (MWh) ^(a)
Sold
Black Hills Colorado IPP	263,701	210,316	528,926	416,289
Black Hills Wyoming ^(b)	156,866	149,713	313,218	313,762
Black Hills Electric Generation	92,629	47,796	189,908	81,549
Total Sold	513,196	407,825	1,032,052	811,600

Generated
Black Hills Colorado IPP	263,701	210,316	528,926	416,289
Black Hills Wyoming ^(b)	142,747	132,189	269,232	264,782
Black Hills Electric Generation	92,629	47,796	189,908	81,549
Total Generated	499,077	390,301	988,066	762,620

Purchased

Black Hills Wyoming ^(b)	14,160	13,761	44,093	39,340

Total Purchased	14,160	13,761	44,093	39,340

___________

(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.


	Three Months Ended June 30,						Six Months Ended June 30,
Contracted Power Plant Fleet Availability ^(a)	2020		2019		2020		2019

Coal-fired plant	98.2	%	95.8	%	93.7	%	95.3	%
Natural gas-fired plants ^(b)	99.7	%	88.7	%	99.6	%	92.1	%
Wind	93.1	%	94.1	%	94.0	%	92.3	%
Total Availability	97.0	%	91.5	%	96.6	%	92.8	%

Wind Capacity Factor	27.5	%	23.1	%	28.9	%	25.7	%

___________

(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.

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Mining


	Three Months Ended June 30,										Six Months Ended June 30,
	2020		2019		Variance		2020		2019		Variance
	(in thousands)
Revenue	$	15,416	$	13,045	$	2,371	$	30,621	$	29,474	$	1,147

Operations and maintenance	9,732		9,175		557		19,558		19,088		470
Depreciation, depletion and amortization	2,326		2,230		96		4,576		4,409		167
Total operating expenses	12,058		11,405		653		24,134		23,497		637

Adjusted operating income	$	3,358	$	1,640	$	1,718	$	6,487	$	5,977	$	510

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

Current year revenue increased due to 29% higher tons sold driven primarily by prior year planned and unplanned facility outages partially offset by a 7% decrease in price per ton sold driven by contract price adjustments based on actual mining costs.

Six Months Ended June 30, 2020 Compared to the Six Months Ended June 30, 2019:

Current year revenue increased due to 7% higher tons sold driven primarily by prior year planned and unplanned facility outages partially offset by a 3% decrease in price per ton sold driven by contract price adjustments based on actual mining costs.

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Tons of coal sold	972		754		1,868		1,751
Cubic yards of overburden moved	2,211		2,045		4,478		4,039

Revenue per ton	$	15.27	$	16.48	$	15.66	$	16.14

Corporate and Other


	Three Months Ended June 30,										Six Months Ended June 30,
	2020		2019		Variance		2020		2019		Variance
	(in thousands)
Adjusted operating income (loss)	$	(29)	$	102	$	(131)	$	131	$	(405)	$	536

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


	Three Months Ended June 30,										Six Months Ended June 30,
	2020		2019		Variance		2020		2019		Variance
	(in thousands)										(in thousands)
Interest expense, net	$	(35,545)	$	(34,264)	$	(1,281)	$	(70,998)	$	(68,981)	$	(2,017)
Impairment of investment	—		—		$	—	(6,859)		—		$	(6,859)
Other income (expense), net	(1,863)		263		$	(2,126)	490		(526)		$	1,016
Income tax (expense)	(4,831)		(2,307)		$	(2,524)	(20,833)		(19,570)		$	(1,263)

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

Interest expense, net

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

Other Income (Expense)

The variance in Other income (expense), net for the three months ended June 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 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 June 30, 2020, the effective tax rate was 16.4% compared to 11.5% for the same period in 2019. The higher effective tax rate is primarily due to a prior year discrete tax benefit related to repair costs and certain indirect costs.

Six Months Ended June 30, 2020 Compared to the Six Months Ended June 30, 2019.

Interest expense, net

The increase in Interest expense, net for the six months ended June 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 six months ended June 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. 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 six months ended June 30, 2020, compared to the same period in the prior year, was primarily due to reduced costs for our non-qualified benefit plans which are driven by market performance partially offset by 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 six months ended June 30, 2020, the effective tax rate was 14.6% compared to 13.5% for the same period in 2019. The higher effective tax rate is primarily due to a prior year discrete tax benefit related to repair costs and certain indirect costs and a current year discrete tax adjustment related to the impairment of our investment in equity securities of a privately held oil and gas company partially offset by increased tax benefits from forecasted federal production tax credits associated with new wind assets.

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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.

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 Ex ecutive 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 June 30, 2020, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts. For the six months ended June 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.

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Cash Flow Activities

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


Cash provided by (used in):	2020		2019		Variance
Operating activities	$	309.0	$	289.8	$	19.2
Investing activities	$	(349.7)	$	(317.3)	$	(32.4)
Financing activities	$	62.8	$	13.6	$	49.2

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

Operating Activities

Net cash provided by operating activities was $309 million for the six months ended June 30, 2020, compared to net cash provided by operating activities of $290 million for the same period in 2019, for an increase of $19 million. The variance was primarily attributable to:

•Cash earnings (net income plus non-cash adjustments) were $7.3 million higher for the six months ended June 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 $26 million for the six months ended June 30, 2020, compared to net cash inflows of $14 million in the same period in the prior year. This $12 million increase was primarily due to:

◦Cash inflows decreased by $34 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 $44 million as a result of changes in accounts payable and accrued liabilities driven by the impact of lower commodity prices, lower employee costs, lower outside services expenses and other working capital requirements;

◦Cash inflows increased by $12 million primarily as a result of changes in our regulatory assets and liabilities driven by timing of recovery from fuel costs adjustments and the TCJA tax rate change that was returned to customers in the prior year; and

◦Cash outflows increased by $13 million due to the timing of pension contributions made in the current year.

Investing Activities

Net cash used in investing activities was $350 million for the six months ended June 30, 2020, compared to net cash used in investing activities of $317 million for the same period in 2019, for a variance of $32 million. The variance was primarily attributable to:

•Capital expenditures of $348 million for the six months ended June 30, 2020 compared to $318 million for the same period in the prior year. Higher current year expenditures were driven by higher programmatic safety, reliability and integrity spending at our Gas Utilities and Electric Utilities segments and the Corriedale wind project at our Electric Utilities segment.

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Financing Activities

Net cash provided by financing activities for the six months ended June 30, 2020 was $63 million, compared to $14 million of net cash provided by financing activities for the same period in 2019, an increase of $49 million primarily due to the following:

•Cash dividends on common stock of $66 million were paid in the current year compared to $61 million paid in the prior year;

•Increase of $28 million in common stock issued due primarily to current year net proceeds of $99 million through an underwritten registered transaction partially offset by prior year net proceeds of $69 million through our ATM;

•$266 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; and

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

Dividends

Dividends paid on our common stock totaled $66 million for the six months ended June 30, 2020, or $0.535 per share per quarter. On July 27, 2020, our board of directors declared a quarterly dividend of $0.535 per share payable September 1, 2020, equivalent to an annual dividend of $2.14 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		June 30, 2020		June 30, 2020		June 30, 2020		June 30, 2020
Revolving Credit Facility and CP Program	July 30, 2023	$	750	$	—	$	—	$	12	$	738

_______________

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

Facility.

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


	For the Six Months Ended June 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)	$	243
Weighted average interest rates - Revolving Credit Facility	1.75		%
Weighted average interest rates - CP Program	1.48		%

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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 June 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 June 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 six months ended June 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 June 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.

The following table represents the credit ratings of South Dakota Electric at June 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.

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Capital Requirements

Capital Expenditures


	Actual		Planned		Planned		Planned		Planned		Planned
Capital Expenditures by Segment	Six Months Ended June 30, 2020 ^(a)		2020 ^(b)		2021		2022		2023		2024
(in millions)
Electric Utilities	$	117	$	246	$	203	$	170	$	137	$	152
Gas Utilities	209		391		309		285		316		293
Power Generation	6		7		9		11		6		6
Mining	6		8		12		9		9		9
Corporate and Other	10		17		22		11		12		10
	$	348	$	669	$	555	$	486	$	480	$	470

__________

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

(b) Includes actual capital expenditures for the six months ended June 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 six months ended June 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 June 30, 2020. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at June 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 June 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 six months ended June 30, 2020, the COVID-19 pandemic had a limited financial impact on our business, operations, financial condition and cash flows. In particular, we experienced:

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

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

•Minimal 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;

•Reduced availability and productivity of our employees;

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

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

•Increased costs for personal protection equipment and cleaning supplies;

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

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

•Reduced training, travel and outside services 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 and productivity of our employees and third-party resources;

•Increased costs as a result of our emergency measures;

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

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

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

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

•Impairment of goodwill or long-lived assets;

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

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

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

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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:	August 4, 2020

Black Hills - 10-Q quarterly report FY2020 Q2

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