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 ~~10-Q~~March 31, 2020



x	~~QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES~~
	~~EXCHANGE ACT OF 1934~~
	~~For the quarterly period ended March 31, 2019~~
OR
o	~~TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES~~
	~~EXCHANGE ACT OF 1934~~
	☐ 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~~

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 ☐x		No o

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 ☐ x		No o

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



Large ~~accelerated filer~~ Accelerated Filer	x	Accelerated ~~filer~~ o Filer	☐

Non-accelerated ~~filer~~ o Filer	☐	Smaller ~~reporting company~~ o Reporting Company	☐

		Emerging ~~growth company~~ oGrowth 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 ☒



	~~Yes~~ o		No x

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 April 30, ~~2019~~2020
Common stock, $1.00 par value	~~60,367,972~~62,749,727	shares

Table of Contents



TABLE OF CONTENTS
			Page
		Glossary of Terms and Abbreviations		34

PART I.				FINANCIAL INFORMATION	5

Item 1.	Financial Statements		5

	~~Condensed Consolidated Statements of Income~~ - unaudited
	~~Three Months Ended March 31, 2019 and 2018~~		5

	~~Condensed Consolidated Statements of Comprehensive Income - unaudited~~
	~~Three Months Ended March 31, 2019 and 2018~~		6

	~~Condensed Consolidated Balance Sheets - unaudited~~
	~~March 31, 2019, December 31, 2018 and March 31, 2018~~		7

	Condensed Consolidated Statements of ~~Cash Flows - unaudited~~Income		7
	~~Three Months Ended March 31, 2019 and 2018~~ 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 ~~- unaudited~~		1013
	Note 1. Management’s Statement		13
	Note 2. Revenue		15
	Note 3. Business Segment Information		16
	Note 4. Selected Balance Sheet Information		17
	Note 5. Regulatory Matters		19
	Note 6. Earnings Per Share		20
	Note 7. Notes Payable, Current Maturities and Debt		21
	Note 8. Equity		22
	Note 9. Risk Management and Derivatives		22
	Note 10. Fair Value Measurements		25
	Note 11. Other Comprehensive Income (Loss)		27
	Note 12. Employee Benefit Plans		28
	Note 13. Commitments and Contingencies		30
	Note 14. Income Taxes		30
	Note 15. Investments		31
	Note 16. Subsequent Events		31

Table of Contents



TABLE OF CONTENTS
		Page
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3532
	Results of Operations	33
	Non-GAAP Financial Measure	36
	Electric Utilities Segment	37
	Gas Utilities Segment	40
	Regulatory Matters	42
	Power Generation Segment	42
	Mining Segment	43
	Corporate and Other	43
	Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax Benefit (Expense)	43
	Critical Accounting Policies Involving Significant Accounting Estimates	43
	Liquidity and Capital Resources	43
	Cash Flow Activities	43
	Dividends	44
	Financing Transactions and Short-Term Liquidity	44
	Capital Requirements	45
	Contractual Obligations	45
	Off-Balance Sheet Commitments	45
	New Accounting Pronouncements	45
	Forward-Looking Information	45
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4.	Controls and Procedures	46

PART II. OTHER INFORMATION
Item 3.1.	~~Quantitative and Qualitative Disclosures about Market Risk~~ Legal Proceedings	5346
Item 1A.	Risk Factors	46
Item 4.	Mine Safety Disclosures	47
Item 6.	Exhibits	47

~~Item 4.~~	~~Controls and Procedures~~	54Signatures

~~PART II.~~	~~OTHER INFORMATION~~	54

~~Item 1.~~	~~Legal Proceedings~~	54

~~Item 1A.~~	~~Risk Factors~~	54

~~Item 2.~~	~~Unregistered Sales of Equity Securities and Use of Proceeds~~	54

~~Item 4.~~	~~Mine Safety Disclosures~~	54

~~Item 5.~~	~~Other Information~~	54

~~Item 6.~~	~~Exhibits~~	55

	~~Signatures~~	5749

Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS

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



AFUDC	Allowance for Funds Used During Construction
ALJ	Administrative Law Judge
AOCI	Accumulated Other Comprehensive Income (Loss)
Arkansas Gas	Black Hills Energy Arkansas, Inc., a direct, wholly-owned subsidiary of Black Hills ~~Gas Inc.~~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
Busch Ranch I	~~Busch Ranch Wind Farm is a~~ 29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and Black Hills Electric ~~Generation. Colorado Electric and Black~~ ~~Hills Electric~~ Generation, each ~~have~~having a 50% ownership interest in the wind farm.
Busch Ranch II	~~Busch Ranch II wind project will be a~~ 60 MW wind farm near Pueblo, Colorado, built by Black Hills Electric Generation to provide wind energy to Colorado Electric through a ~~25-year~~ power purchase ~~agreement.~~agreement expiring in November 2044.
CAPP	Customer Appliance Protection Plan, which provides appliance repair services to residential natural gas customers through on-going monthly service agreements. The consolidation of the existing Service Guard and CAPP plans into the revamped Service Guard Comfort Plan is currently underway across our service territories.
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	~~The~~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 ~~natural gas~~commodity service from the distribution component, which opens up the gas supply for competition allowing customers to choose from different natural gas suppliers. Black Hills Gas Distribution distributes the gas and Black Hills Energy Services is one of the Choice Gas suppliers.
~~CIAC~~	~~Contribution In Aid of Construction~~delivery service.
City of Gillette	Gillette, Wyoming
Colorado Electric	Black Hills Colorado Electric, LLC, ~~an indirect,~~a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing electric service to customers in Colorado (doing business as Black Hills Energy).
Colorado ~~IPP~~Gas	Black Hills Colorado ~~IPP, LLC a 50.1% owned~~Gas, Inc., an indirect, wholly-owned subsidiary of Black Hills ~~Electric Generation~~Utility Holdings, providing natural gas services to customers in Colorado (doing business as Black Hills Energy).

Table of Contents



Consolidated Indebtedness to Capitalization Ratio	Any ~~Indebtedness~~indebtedness outstanding at such time, divided by ~~Capital~~capital at such time. Capital being ~~Consolidated Net-Worth~~consolidated net worth (excluding noncontrolling interest) plus ~~Consolidated Indebtedness~~consolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit ~~Agreement.~~Facility.
Cooling Degree Day (CDD)	A cooling degree day is equivalent to each degree that the average of the high and low ~~temperature~~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 ~~of weather~~ and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
~~CPCN~~Corriedale	~~Certificate of Public Convenience~~Wind project near Cheyenne, Wyoming, that will be a 52.5 MW wind farm jointly owned by South Dakota Electric and ~~Necessity~~Wyoming Electric and will serve as the dedicated wind energy supply to the Renewable Ready program.
COVID-19	The official name for the 2019 novel coronavirus disease, which was 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
Dth	Dekatherm. A unit of energy equal to 10 therms or approximately one million British thermal units (MMBtu)



~~Equity Unit~~	Each Equity Unit had a stated amount of $50, consisting of a purchase contract issued by BHC to purchase shares of BHC common stock and a 1/20, or 5% undivided beneficial ownership interest in $1,000 principal amount of BHC RSNs that were formerly due 2028. On November 1, 2018, we completed settlement of the stock purchase contracts that are components of the Equity Units issued in November 2015.
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 ~~of weather~~ and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
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, ~~Utility Company,~~ LLC, ~~a direct,~~an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Nebraska (doing business as Black Hills Energy)
NPSC	Nebraska Public Service Commission
OCI	Other Comprehensive Income
PPA	Power Purchase 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 Ready	Voluntary renewable energy subscription program for large commercial, industrial and governmental agency customers. The Corriedale wind project will provide 52.5 MW of energy for Renewable Ready subscribers in Wyoming and western South Dakota.

Table of Contents



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.
~~RSNs~~RMNG	~~Remarketable junior subordinated notes, issued on November 23, 2015~~Rocky Mountain Natural Gas LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas transmission and wholesale services in western Colorado (doing business as Black Hills Energy).
SDPUC	South Dakota Public Utilities Commission
SEC	~~U. S.~~United States Securities and Exchange Commission
~~SourceGas~~Service Guard	~~SourceGas Holdings LLC~~Home appliance repair product offering for both natural gas and ~~its subsidiaries, a gas utility owned by funds managed by Alinda Capital Partners~~electric residential customers through on-going monthly service agreements. The consolidation of the existing Service Guard and ~~GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) that was acquired on February 12, 2016, and~~CAPP plans into the revamped Service Guard Comfort Plan is ~~now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy)~~currently underway across our service territories.
~~SourceGas Acquisition~~Service Guard Comfort Plan	~~The acquisition of SourceGas Holdings, LLC by Black Hills Utility Holdings~~New plan that will consolidate Service Guard and CAPP and provide similar services.
S&P	Standard and Poor’s, a division of The McGraw-Hill Companies, Inc.
South Dakota Electric	~~Includes~~ Black Hills Power, ~~operations~~Inc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and Wyoming ~~and Montana~~
~~SSIR~~	~~System Safety and Integrity Rider~~
~~TCJA~~	~~Tax Cuts and Jobs Act enacted on December 22, 2017~~(doing business as Black Hills Energy).
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.
TCJA	Tax Cuts and Jobs Act
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)
Wyodak Plant	Wyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, owned 80% by ~~Pacificorp~~PacifiCorp and 20% by Black Hills Energy South Dakota. Our WRDC mine supplies all of the fuel for the plant.
Wyoming Electric	~~Includes~~ Cheyenne ~~Light’s~~Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric ~~utility operations~~service to customers in the Cheyenne, Wyoming area (doing business as Black Hills Energy).
Wyoming Gas	Black Hills Wyoming Gas, LLC, an indirect and wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Wyoming (doing business as Black Hills Energy).

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


(unaudited)	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
	(in thousands, except per share amounts)						(in thousands, except per share amounts)

Revenue	$	597,810		$	575,389		$	537,050		$	597,810

Operating expenses:
Fuel, purchased power and cost of natural gas sold	248,779			247,639			187,879			249,742
Operations and maintenance	123,913			116,096			125,466			123,584
Depreciation, depletion and amortization	51,028			48,590			56,402			51,028
Taxes - property and production	13,519			13,300			14,118			13,325
Other operating expenses	440			1,490
Total operating expenses	437,679			427,115			383,865			437,679

Operating income	160,131			148,274			153,185			160,131

Other income (expense):
Interest charges -
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	(35,974		)	(35,438		)	(35,781		)	(35,016		)
Allowance for funds used during construction - borrowed	958			133
Interest income	299			310			328			299
Allowance for funds used during construction - equity	48			68
Impairment of investment							(6,859		)	—
Other income (expense), net	(837		)	(172		)	2,353			(789		)
Total other income (expense)	(35,506		)	(35,099		)	(39,959		)	(35,506		)

Income before income taxes	124,625			113,175			113,226			124,625
Income tax benefit (expense)	(17,263		)	25,802
Income from continuing operations	107,362			138,977
Net (loss) from discontinued operations	—			(2,343		)
Income tax (expense)							(16,002		)	(17,263		)
Net income	107,362			136,634			97,224			107,362
Net income attributable to noncontrolling interest	(3,554		)	(3,630		)	(4,050		)	(3,554		)
Net income available for common stock	$	103,808		$	133,004		$	93,174		$	103,808

Amounts attributable to common shareholders:
Net income from continuing operations	$	103,808		$	135,347
Net (loss) from discontinued operations	—			(2,343		)
Net income available for common stock	$	103,808		$	133,004

Earnings (loss) per share of common stock, Basic -
Earnings from continuing operations	$	1.73		$	2.54
(Loss) from discontinued operations	—			(0.05		)
Total earnings per share of common stock, Basic	$	1.73		$	2.49

Earnings (loss) per share of common stock, Diluted -
Earnings from continuing operations	$	1.73		$	2.50
(Loss) from discontinued operations	—			(0.04		)
Total earnings per share of common stock, Diluted	$	1.73		$	2.46
Earnings per share of common stock:
Earnings per share, Basic							$	1.51		$	1.73
Earnings per share, Diluted							$	1.51		$	1.73

Weighted average common shares outstanding:
Basic	59,920			53,319			61,778			59,920
Diluted	60,060			54,122			61,856			60,060

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

Table of Contents

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


(unaudited)	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
	(in thousands)						(in thousands)

Net income	$	107,362		$	136,634		$	97,224		$	107,362

Other comprehensive income (loss), net of tax:
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $5 and $10, respectively)	(14		)	(35		)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax of $(53) and $(136), respectively)	167			486
Benefit plan liability adjustments - net gain (net of tax of $(17) and $0, respectively							55			—
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $7 and $5, respectively)							(23		)	(14		)
Reclassification adjustments of benefit plan liability - net gain (net of tax of $(95) and $(53), respectively)							502			167
Derivative instruments designated as cash flow hedges:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(163) and $(152), respectively)	550			561
Net unrealized gains (losses) on commodity derivatives (net of tax of $(54) and $69, respectively)	180			(228		)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $128 and $(145), respectively)	(426		)	476
Reclassification of net realized losses on settled/amortized interest rate swaps (net of tax of $(170) and $(163), respectively)							543			550
Net unrealized gains (losses) on commodity derivatives (net of tax of $54 and $(54), respectively)							(175		)	180
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $(115) and $128, respectively)							371			(426		)
Other comprehensive income, net of tax	457			1,260			1,273			457

Comprehensive income	107,819			137,894			98,497			107,819
Less: comprehensive income attributable to noncontrolling interest	(3,554		)	(3,630		)	(4,050		)	(3,554		)
Comprehensive income available for common stock	$	104,265		$	134,264		$	94,447		$	104,265

See Note 1113 for additional disclosures.

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

Table of Contents

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


(unaudited)	As of									As of
	March 31, 2019			December 31, 2018			March 31, 2018			March 31, 2020			December 31, 2019
	(in thousands)									(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	12,225		$	20,776		$	30,947		$	54,137		$	9,777
Restricted cash	3,494			3,369			2,958
Restricted cash and equivalents										4,027			3,881
Accounts receivable, net	282,602			269,153			257,772			238,903			255,805
Materials, supplies and fuel	87,676			117,299			82,045			92,894			117,172
Derivative assets, current	932			1,500			295			1,780			342
Income tax receivable, net	15,309			12,978			13,900			22,319			16,446
Regulatory assets, current	54,303			48,776			54,492			49,415			43,282
Other current assets	28,029			29,982			24,972			26,198			26,479
Current assets held for sale	—			—			24,724
Total current assets	484,570			503,833			492,105			489,673			473,184

Investments	41,247			41,013			40,927			15,250			21,929

Property, plant and equipment	6,127,050			6,000,015			5,608,539			6,808,261			6,784,679
Less: accumulated depreciation and depletion	(1,187,112		)	(1,145,136		)	(1,048,933		)	(1,223,979		)	(1,281,493		)
Total property, plant and equipment, net	4,939,938			4,854,879			4,559,606			5,584,282			5,503,186

Other assets:
Goodwill	1,299,454			1,299,454			1,299,454			1,299,454			1,299,454
Intangible assets, net	14,136			14,337			7,357			13,083			13,266
Regulatory assets, non-current	232,404			235,459			212,740			222,814			228,062
Other assets, non-current	25,823			14,352			14,800			24,258			19,376
Total other assets, non-current	1,571,817			1,563,602			1,534,351			1,559,609			1,560,158

TOTAL ASSETS	$	7,037,572		$	6,963,327		$	6,626,989		$	7,648,814		$	7,558,457

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

Table of Contents

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Continued)


(unaudited)	As of									As of
	March 31, 2019			December 31, 2018			March 31, 2018			March 31, 2020			December 31, 2019
	(in thousands, except share amounts)									(in thousands, except share amounts)
LIABILITIES AND TOTAL EQUITY
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	178,678		$	210,609		$	106,281		$	136,344		$	193,523
Accrued liabilities	196,072			215,501			194,040			203,445			226,767
Derivative liabilities, current	95			947			891			852			2,254
Regulatory liabilities, current	45,777			29,810			42,499			54,345			33,507
Notes payable	164,650			185,620			164,200			319,125			349,500
Current maturities of long-term debt	5,743			5,743			255,743			5,743			5,743
Current liabilities held for sale	—			—			24,910
Total current liabilities	591,015			648,230			788,564			719,854			811,294

Long-term debt	2,950,299			2,950,835			2,858,787
Long-term debt, net of current maturities										3,136,887			3,140,096

Deferred credits and other liabilities:
Deferred income tax liabilities, net	337,184			311,331			290,491			387,939			360,719
Regulatory liabilities, non-current	511,482			510,984			495,362			504,149			503,145
Benefit plan liabilities	145,883			145,147			160,580			152,693			154,472
Other deferred credits and other liabilities	118,007			109,377			105,221			122,869			124,662
Total deferred credits and other liabilities	1,112,556			1,076,839			1,051,654			1,167,650			1,142,998

Commitments and contingencies (See Notes 8, 10, 15, 16)
Commitments and contingencies (See Notes 7, 9, 12, 13)

Equity:
Stockholders’ equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 60,378,020; 60,048,567; and 53,648,817 shares, respectively	60,378			60,049			53,649
Common stock $1 par value; 100,000,000 shares authorized; issued 62,772,978 and 61,480,658 shares, respectively										62,773			61,481
Additional paid-in capital	1,469,410			1,450,569			1,151,933			1,652,861			1,552,788
Retained earnings	777,262			700,396			656,161			838,841			778,776
Treasury stock, at cost – 23,756; 44,253; and 53,959 shares, respectively	(1,432		)	(2,510		)	(3,049		)
Treasury stock, at cost – 24,656 and 3,956 shares, respectively										(1,925		)	(267		)
Accumulated other comprehensive income (loss)	(26,459		)	(26,916		)	(39,924		)	(29,382		)	(30,655		)
Total stockholders’ equity	2,279,159			2,181,588			1,818,770			2,523,168			2,362,123
Noncontrolling interest	104,543			105,835			109,214			101,255			101,946
Total equity	2,383,702			2,287,423			1,927,984			2,624,423			2,464,069

TOTAL LIABILITIES AND TOTAL EQUITY	$	7,037,572		$	6,963,327		$	6,626,989		$	7,648,814		$	7,558,457

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

Table of Contents

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) Three Months Ended March 31,
2019 2018
Operating activities: (in thousands)
Net income $ 107,362
$ 136,634
Loss from discontinued operations, net of tax —
2,343
Income from continuing operations 107,362
138,977
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization 51,028
48,590
Deferred financing cost amortization 2,007
1,900
Stock compensation 3,296
2,209
Deferred income taxes 19,602
(25,430 )
Employee benefit plans 3,137
3,378
Other adjustments, net 4,428
3,053
Changes in certain operating assets and liabilities:
Materials, supplies and fuel 29,387
31,196
Accounts receivable, unbilled revenues and other operating assets (15,857 ) (25,113 )
Accounts payable and other operating liabilities (41,689 ) (71,149 )
Regulatory assets - current 13,031
47,903
Regulatory liabilities - current (1,635 ) 16,098
Other operating activities, net 1,796
(278 )
Net cash provided by operating activities of continuing operations 175,893
171,334
Net cash provided by (used in) operating activities of discontinued operations —
(1,459 )
Net cash provided by operating activities 175,893
169,875

Investing activities:
Property, plant and equipment additions (144,126 ) (69,972 )
Purchase of investment —
(23,500 )
Other investing activities (901 ) (261 )
Net cash provided by (used in) investing activities of continuing operations (145,027 ) (93,733 )
Net cash provided by (used in) investing activities of discontinued operations —
20,179
Net cash provided by (used in) investing activities (145,027 ) (73,554 )

Financing activities:
Dividends paid on common stock (30,332 ) (25,444 )
Common stock issued 19,949
372
Net (payments) borrowings of short-term debt (20,970 ) (47,100 )
Long-term debt - repayments (1,436 ) (1,436 )
Distributions to noncontrolling interest (4,846 ) (5,648 )
Other financing activities (1,657 ) (1,400 )
Net cash provided by (used in) financing activities (39,292 ) (80,656 )
Net change in cash, cash equivalents and restricted cash (8,426 ) 15,665
Cash, cash equivalents and restricted cash at beginning of period 24,145
18,240
Cash, cash equivalents and restricted cash at end of period $ 15,719
$ 33,905



(unaudited)	Three Months Ended March 31,
	2020			2019
Operating activities:	(in thousands)
Net income	$	97,224		$	107,362
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	56,402			51,028
Deferred financing cost amortization	2,237			2,007
Impairment of investment	6,859			—
Stock compensation	291			3,296
Deferred income taxes	21,876			19,602
Employee benefit plans	1,235			3,137
Other adjustments, net	892			4,428
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	19,222			29,387
Accounts receivable and other current assets	8,171			(15,857		)
Accounts payable and other current liabilities	(43,297		)	(41,689		)
Regulatory assets - current	20,679			13,031
Regulatory liabilities - current	1,316			(1,635		)
Other operating activities, net	(1,138		)	1,796
Net cash provided by operating activities	191,969			175,893

Investing activities:
Property, plant and equipment additions	(171,882		)	(144,126		)
Other investing activities	(1,202		)	(901		)
Net cash (used in) investing activities	(173,084		)	(145,027		)

Financing activities:
Dividends paid on common stock	(32,902		)	(30,332		)
Common stock issued	99,321			19,949
Net (payments) borrowings of short-term debt	(30,375		)	(20,970		)
Long-term debt - repayments	(4,291		)	(1,436		)
Distributions to noncontrolling interest	(4,741		)	(4,846		)
Other financing activities	(1,391		)	(1,657		)
Net cash provided by (used in) financing activities	25,621			(39,292		)

Net change in cash, restricted cash and cash equivalents	44,506			(8,426		)

Cash, restricted cash and cash equivalents at beginning of period	13,658			24,145
Cash, restricted cash and cash equivalents at end of period	$	58,164		$	15,719

Supplemental cash flow information:
Cash (paid) refunded during the period:
Interest (net of amounts capitalized)	$	(21,776	)	$	(30,672	)
Income taxes	—			8
Non-cash investing and financing activities:
Accrued property, plant and equipment purchases at March 31	53,011			56,571

~~See Note~~ 14 ~~for supplemental disclosure of cash flow information.~~

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

Table of Contents

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, 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



	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 (loss) available for common stock	—	—		—		—			—			103,808			—			3,554			107,362
Other comprehensive income, 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

Table of Contents

BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s ~~2018~~2019 Annual Report on Form 10-K)

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

The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company”, “us”, “we” or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Condensed Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes ~~thereto~~ included in our ~~2018~~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.

Accounting standards for presentation of segments requires an approach based on the way we organize the segments for making operating decisions and how the chief operating decision maker (CODM) assesses performance. We have changed our segment performance metrics and concluded that adjusted operating income, instead of net income available for common stock which was used previously, is the most relevant metric for measuring segment performance.

The CODM assesses the performance of our segments by using adjusted operating income, which considers the power sales arrangement between Colorado IPP and Colorado Electric be treated as an executory contract. Adjusted operating income adjusts this power sales arrangement from being accounted for as a capital lease to being accounted for as an executory contract on an accrual basis. This adjustment impacts Electric Utilities and Power Generation segments and Corporate and Other. There were no adjustments to Gas Utilities and Mining segments and this adjustment had no effect on our consolidated operating income.

The change to our segment performance measure resulted in a revision of the Company’s segment disclosures for all periods to report adjusted operating income as the measure of segment profit and adjust revenues, operating income, and total assets for the power sales agreement to an executory contract and not a capital lease. See Notes 2 and 3 for more information.

On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture of our Oil and Gas segment in 2018. The Oil and Gas segment assets and liabilities have been classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, except for certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. At the time the assets were classified as held for sale, depreciation, depletion and amortization expenses were no longer recorded. Unless otherwise noted, the amounts presented in the accompanying notes to the Condensed Consolidated Financial Statements relate to the Company’s continuing operations. See Note 17 for more information on discontinued operations.

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 March 31, 2020, December 31, 2019 and March 31, 2019~~, December 31, 2018, and~~ ~~March 31, 2018~~ financial ~~information and are of a normal recurring nature.~~information. Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements. 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 months ended March 31, 2020 and March 31, 2019, ~~and~~ ~~March 31, 2018~~, and our financial condition as of March 31, ~~2019~~,2020 and December 31, ~~2018, and~~ ~~March 31, 2018~~,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 Consolidated Statements of Income for the three months ended March 31, 2019. Amounts previously reported as Operations and maintenance, Taxes - property and production, and Other operating expenses of ($0.3) million, ($0.3) million, and ($0.4) million, respectively, have been reclassified to Fuel, purchased power and cost of natural gas sold to conform with current year presentation. The prior year reclassifications did not impact previously reported operating income or net income.

COVID-19 Pandemic

In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the outbreak a national emergency. The U.S. government has deemed the electric and natural gas utilities as “critical” in providing essential services during this emergency. As a provider of critical 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 months ended March 31, 2020, there were no material adverse impacts on the Company’s results of operations.

Table of Contents

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 continue to 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 ASU 2018-19, ASU 2019-04, 2019-05, 2019-10, and 2019-11. The standard introduces new accounting guidance for credit losses on financial instruments within its scope, including trade receivables. This 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. ~~The new~~We adopted this standard ~~is effective for interim and annual reporting periods beginning after December~~prospectively on January 1, ~~2019, applied on a prospective basis with early adoption permitted. We do not anticipate the adoption~~2020. Adoption of this guidance is not expected to have ~~any~~an impact on our financial position, results of operations or cash flows.

~~Recently Adopted~~Internal-Use Software: Customer’s Accounting ~~Standards~~

~~Leases,~~for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, ASU ~~2016-02~~2018-15

In ~~February 2016,~~August 2018, the FASB issued ASU ~~2016-02,~~2018-15, ~~Leases (Topic 842)~~ 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 ~~increase transparency~~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 ~~comparability among organizations by requiring~~amortized over the ~~recognition~~term of ~~right-of-use assets and lease liabilities on~~ the balance sheet for most leases, whereas previously only financing-type lease liabilities (capital leases) were recognized on the balance sheet. Under the new standard, disclosures are required to meet the objective of enabling users of financial statements to assess the amount, timing and uncertainty of cash flows arising from leases.

arrangement. We adopted ~~the~~this standard ~~effective~~prospectively on January 1, 2019. We elected not to recast comparative periods coinciding with the new lease standard transition and will report these comparative periods as presented under previous lease guidance. In addition, we elected the package of practical expedients permitted under the transition guidance with the new standard, which among other things, allowed us to carry forward the historical lease classification. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for existing land easement agreements.

2020. Adoption of the new standard resulted in the recording of an operating lease right-of-use asset of $3.1 million, an operating lease obligation liability of $3.2 million, and an accrued rent receivable of $4.5 million, as of January 1, 2019. The cumulative effect of the adoption, net of tax impact, was $3.4 million, which was recorded as an adjustment to retained earnings.

~~Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities, ASU 2017-12~~

~~Effective January 1, 2019, we adopted ASU 2017-12,~~ ~~Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.~~ This standard better aligns risk management activities and financial reporting for hedging relationships, simplifies hedge accounting requirements and improves disclosures of hedging arrangements. The adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

Table of Contents

(2) ~~REVENUE~~Revenue

~~Revenue Recognition~~

AsOur revenue contracts generally provide for performance obligations that are: fulfilled and transfer control to customers over time; represent a series of ~~January 1, 2018, we adopted ASU 2014-09,~~ ~~Revenue~~distinct services that are substantially the same; involve the same pattern of transfer to the customer; and provide a right to consideration from ~~Contracts with Customers (Topic 606), and its related amendments (collectively known as ASC 606). Revenue is recognized~~our customers in an amount that ~~reflects~~corresponds directly with the ~~consideration~~value to the customer for the performance completed to date. Therefore, we ~~expect~~recognize revenue in the amount to ~~receive in exchange for goods or services, when control of the promised goods or services is transferred~~which we have a right to ~~our customers.~~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 months ended March 31, ~~2019~~2020 and ~~2018.~~2019. Sales tax and other similar taxes are excluded from revenues.


Three Months Ended March 31, 2019	Electric Utilities		Gas Utilities				Power Generation ^(a)		Mining		Inter-company Revenues ^(a)			Total
Three Months Ended March 31, 2020																	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues			Total
Customer types:	(in thousands)																(in thousands)
Retail	$	153,463	$	354,275			$	—	$	15,829	$	(8,128	)	$	515,439		$	148,640	$	298,247	$	—	$	14,403	$	(7,839	)	$	453,451
Transportation	—		44,517				—		—		(432		)	44,085			—		44,108		—		—		(139		)	43,969
Wholesale	8,343		—				15,469		—		(13,213		)	10,599			5,552		—		25,467		—		(23,612		)	7,407
Market - off-system sales	6,692		217				—		—		(2,224		)	4,685			4,867		138		—		—		(2,639		)	2,366
Transmission/Other	14,175		13,190				—		—		(4,203		)	23,162			14,857		12,572		—		—		(4,413		)	23,016
Revenue from contracts with customers	182,673		412,199				15,469		15,829		(28,200		)	597,970			$	173,916	$	355,065	$	25,467	$	14,403	$	(38,642	)	$	530,209
Other revenues	254		(1,119		)	^(b)	9,776		600		(9,671		)	(160		)	223		5,708		499		802		(391		)	6,841
Total revenues	$	182,927	$	411,080			$	25,245	$	16,429	$	(37,871	)	$	597,810		$	174,139	$	360,773	$	25,966	$	15,205	$	(39,033	)	$	537,050

Timing of revenue recognition:
Services transferred at a point in time	$	—	$	—			$	—	$	15,829	$	(8,128	)	$	7,701		$	—	$	—	$	—	$	14,403	$	(7,839	)	$	6,564
Services transferred over time	182,673		412,199				15,469		—		(20,072		)	590,269			173,916		355,065		25,467		—		(30,803		)	523,645
Revenue from contracts with customers	$	182,673	$	412,199			$	15,469	$	15,829	$	(28,200	)	$	597,970		$	173,916	$	355,065	$	25,467	$	14,403	$	(38,642	)	$	530,209



Three Months Ended March 31, 2019	Electric Utilities		Gas Utilities			Power Generation		Mining		Inter-company Revenues			Total
Customer Types:
Retail	$	153,463	$	354,275		$	—	$	15,829	$	(8,128	)	$	515,439
Transportation	—		44,517			—		—		(432		)	44,085
Wholesale	8,343		—			24,147		—		(21,891		)	10,599
Market - off-system sales	6,692		217			—		—		(2,224		)	4,685
Transmission/Other	14,175		13,190			—		—		(4,203		)	23,162
Revenue from contracts with customers	$	182,673	$	412,199		$	24,147	$	15,829	$	(36,878	)	$	597,970
Other revenues	254		(1,119		)	1,098		600		(993		)	(160		)
Total Revenues	$	182,927	$	411,080		$	25,245	$	16,429	$	(37,871	)	$	597,810

Timing of Revenue Recognition:
Services transferred at a point in time	$	—	$	—		$	—	$	15,829	$	(8,128	)	$	7,701
Services transferred over time	182,673		412,199			24,147		—		(28,750		)	590,269
Revenue from contracts with customers	$	182,673	$	412,199		$	24,147	$	15,829	$	(36,878	)	$	597,970

Three Months Ended March 31, 2018 Electric Utilities Gas Utilities
Power Generation ^(a)
Mining
Inter-company Revenues ^(a)
Total
Customer Types:
Retail $ 147,057
$ 341,394
$ —
$ 16,557
$ (7,842 ) $ 497,166
Transportation —
41,669
—
—
(409 ) 41,260
Wholesale 9,050
—
14,769
—
(13,049 ) 10,770
Market - Off-System Sales 4,144
427
—
—
(2,522 ) 2,049
Transmission/Other 13,071
12,670
—
—
(3,631 ) 22,110
Revenue from contracts with customers $ 173,322
$ 396,160
$ 14,769
$ 16,557
$ (27,453 ) $ 573,355
Other Revenues 233
1,184
^(b)
9,170
571
(9,124 ) 2,034
Total Revenues $ 173,555
$ 397,344
$ 23,939
$ 17,128
$ (36,577 ) $ 575,389

Timing of Revenue Recognition:
Services transferred at a point in time $ —
$ —
$ —
$ 16,557
$ (7,842 ) $ 8,715
Services transferred over time 173,322
396,160
14,769
—
(19,611 ) 564,640
Revenue from contracts with customers $ 173,322
$ 396,160
$ 14,769
$ 16,557
$ (27,453 ) $ 573,355

Table of Contents

~~(a)~~

Due to changes to our segment performance measure as disclosed in Note 1, Power Generation Wholesale revenue was recast for the three months ended March 31, 2018 which resulted in a change of $0.8 million. For the three months ended March 31, 2019, the impact to Power Generation Wholesale revenue was $3.4 million. The changes to Power Generation were offset by changes to eliminations in Inter-company Revenues and there was no impact to our consolidated Total Revenues.


~~(b)~~	Other revenues in the Gas Utilities segment include alternative revenue programs related to weather normalization mechanisms for Arkansas Gas and Kansas Gas that are considered out of scope for ASC 606.

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 ~~exists.~~exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable further discussed in Note 4.4. We do not typically incur costs that would be capitalized to obtain or fulfill a revenue contract.

(3~~) BUSINESS SEGMENT INFORMATION~~(3) Business Segment Information

Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation.

~~As disclosed in Note 1, changes to~~ All of our ~~segment performance measure resulted in a revision of the Company’s segment disclosures for all periods to adjust revenues, operating income,~~operations and assets ~~related to~~are located within the power sales arrangement between Colorado IPP and Colorado Electric from being accounted for as a capital lease to being accounted for as an executory contract on an accrual basis. This change had no effect on our consolidated revenues, operating income, or total assets. See below for more information.United States.

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



Three Months Ended March 31, 2020	External Operating Revenue				Inter-company Operating Revenue						Total Revenues
Three Months Ended March 31, 2020	Contract Customers		Other Revenues		Contract Customers			Other Revenues			Total Revenues
Segment:
Electric Utilities	$	167,503	$	223	$	6,413		$	—		$	174,139
Gas Utilities	354,287		5,708		778			—			360,773
Power Generation	1,855		443		23,612			56			25,966
Mining	6,564		467		7,839			335			15,205
Inter-company eliminations	—		—		(38,642		)	(391		)	(39,033		)
Total	$	530,209	$	6,841	$	—		$	—		$	537,050




Three Months Ended March 31, 2019	External Operating Revenue					Inter-company Operating Revenue						Total Revenues
	Contract Customers		Other Revenues			Contract Customers			Other Revenues
Segment:
Electric Utilities	$	176,663	$	254		$	6,010		$	—		$	182,927
Gas Utilities	411,500		(1,119		)	699			—			411,080
Power Generation	2,257		436			21,890			662			25,245
Mining	7,550		269			8,279			331			16,429
Inter-company eliminations	—		—			(36,878		)	(993		)	(37,871		)
Total	$	597,970	$	(160	)	$	—		$	—		$	597,810

Table of Contents

Three Months Ended March 31, 2019
External Operating
Revenue
Inter-company Operating Revenue Total Revenues
Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities $ 176,663
$ 254
$ 6,010
$ —
$ 182,927
Gas Utilities ^(a)
411,500
(1,119 ) 699
—
411,080
Power Generation ^(b)
2,257
436
13,212
9,340
25,245
Mining 7,550
269
8,279
331
16,429
Corporate and Other —
—
—
—
—
Inter-company eliminations ^(b)
—
—
(28,200 ) (9,671 ) (37,871 )
Total $ 597,970
$ (160 ) $ —
$ —
$ 597,810




	Three Months Ended March 31,
	2020			2019
Adjusted operating income ^(a):
Electric Utilities	$	35,650		$	41,020
Gas Utilities	102,897			103,314
Power Generation	11,349			11,967
Mining	3,129			4,337
Corporate and Other	160			(507		)
Operating income	153,185			160,131

Interest expense, net	(35,453		)	(34,717		)
Impairment of investment	(6,859		)	—
Other income (expense), net	2,353			(789		)
Income tax (expense)	(16,002		)	(17,263		)
Net income	97,224			107,362
Net income attributable to noncontrolling interest	(4,050		)	(3,554		)
Net income available for common stock	$	93,174		$	103,808

Three Months Ended March 31, 2018 External Operating Revenue Inter-company Operating Revenue Total Revenues
Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities $ 167,178
$ 233
$ 6,144
$ —
$ 173,555
Gas Utilities^(a)
395,742
1,184
418
—
397,344
Power Generation ^(b)
1,720
371
13,049
8,799
23,939
Mining 8,715
246
7,842
325
17,128
Corporate and Other —
—
—
—
—
Inter-company eliminations ^(b)
—
—
(27,453 ) (9,124 ) (36,577 )
Total $ 573,355
$ 2,034
$ —
$ —
$ 575,389

__________


(a)	Other revenues in the Gas Utilities segment include alternative revenue programs related to weather normalization mechanisms for Arkansas Gas and Kansas Gas that are considered out of scope for ASC 606.

~~(b)~~

Due to changes to our segment performance measure, Power Generation Inter-company Operating Revenue for Contract Customers was recast for the three months ended March 31, 2018 which resulted in a change of $0.8 million. For the three months ended March 31, 2019, the impact to Power Generation Inter-company Operating Revenue for Contract Customers was $3.4 million. The changes to Power Generation were offset by changes to Inter-company eliminations and there was no impact on our consolidated Total revenues.

Three Months Ended March 31,
2019 2018
Adjusted operating income:
Electric Utilities ^(a)
$ 41,020
$ 38,480
Gas Utilities 103,314
95,443
Power Generation ^(a)
11,967
11,776
Mining 4,337
4,271
Corporate and Other ^(a)
(507 ) (1,696 )
Operating income 160,131
148,274

Interest expense, net (34,717 ) (34,995 )
Other income (expense), net (789 ) (104 )
Income tax benefit (expense) ^(b)
(17,263 ) 25,802
Income from continuing operations 107,362
138,977
Net (loss) from discontinued operations —
(2,343 )
Net income 107,362
136,634
Net income attributable to noncontrolling interest (3,554 ) (3,630 )
Net income available for common stock $ 103,808
$ 133,004

~~___________~~

~~(a)~~

~~Due to changes to our segment performance measure,~~ Adjusted operating income ~~was recast~~recognizes intersegment revenues and costs for ~~the three months ended March 31, 2018, for Electric Utilities, Power Generation, and Corporate and Other which resulted in changes~~Colorado Electric’s PPA with Black Hills Colorado IPP on an accrual basis rather than as a finance lease. This presentation of ~~$1.7 million, ($1.6) million, and ($0.1) million, respectively. The~~segment information does not impact to Adjusted operating income for the three months ended March 31, 2019, for Electric Utilities, Power Generation, and Corporate and Other was ($5.4) million, $0.7 million, and $4.7 million, respectively. There was no impact on our consolidated ~~Operating income.~~


~~(b)~~	~~Income tax benefit (expense) for the three months ended March 31, 2018 included a $49 million tax benefit resulting fromlegal entity restructuring. See Note 18 for more information.~~ financial results.

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


Total Assets (net of inter-company eliminations) as of:	March 31, 2019		December 31, 2018		March 31, 2018
Total assets (net of inter-company eliminations) as of:							March 31, 2020		December 31, 2019
Segment:
Electric Utilities ^(a)	$	2,755,056	$	2,707,695	$	2,629,267	$	2,931,902	$	2,900,983
Gas Utilities	3,639,430		3,623,475		3,398,473		4,043,539		4,032,339
Power Generation ^(a)	372,503		342,085		314,764		412,572		417,715
Mining	63,088		80,594		65,568		80,289		77,175
Corporate and Other	207,495		209,478		194,193		180,512		130,245
Discontinued operations	—		—		24,724
Total assets	$	7,037,572	$	6,963,327	$	6,626,989	$	7,648,814	$	7,558,457

~~___________~~

~~(a)~~

Due to changes to our segment performance measure, Electric Utilities Total assets were recast as of December 31, 2018 and March 31, 2018 which resulted in changes of ($188) million and ($261) million, respectively. Power Generation Total Assets were recast as of December 31, 2018, and March 31, 2018 which resulted in changes of $188 million and $261 million, respectively. The impact to Electric Utilities and Power Generation Total Assets as of March 31, 2019, was ($186) million and $186 million, respectively. There was no impact on our consolidated Total assets.

(4) Selected Balance Sheet Information

(4~~) ACCOUNTS RECEIVABLE~~Accounts Receivable

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

Accounts Unbilled Less Allowance for Accounts
March 31, 2019 Receivable, Trade Revenue Doubtful Accounts Receivable, net
Electric Utilities $ 45,764
$ 31,075
$ (535 ) $ 76,304
Gas Utilities 138,005
62,566
(4,008 ) 196,563
Power Generation 3,167
—
—
3,167
Mining 2,791
—
—
2,791
Corporate 3,946
—
(169 ) 3,777
Total $ 193,673
$ 93,641
$ (4,712 ) $ 282,602

Accounts Unbilled Less Allowance for Accounts
December 31, 2018 Receivable, Trade Revenue Doubtful Accounts Receivable, net
Electric Utilities $ 39,721
$ 35,125
$ (448 ) $ 74,398
Gas Utilities 96,123
90,521
(2,592 ) 184,052
Power Generation 1,876
—
—
1,876
Mining 3,988
—
—
3,988
Corporate 5,008
—
(169 ) 4,839
Total $ 146,716
$ 125,646
$ (3,209 ) $ 269,153

Accounts Unbilled Less Allowance for Accounts
March 31, 2018 Receivable, Trade Revenue Doubtful Accounts Receivable, net
Electric Utilities $ 40,492
$ 33,907
$ (624 ) $ 73,775
Gas Utilities 120,910
60,142
(3,684 ) 177,368
Power Generation 1,580
—
—
1,580
Mining 3,133
—
—
3,133
Corporate 1,916
—
—
1,916
Total $ 168,031
$ 94,049
$ (4,308 ) $ 257,772



	March 31, 2020			December 31, 2019
Accounts receivable, trade	$	162,138		$	144,747
Unbilled revenue	81,927			113,502
Less: Allowance for credit losses	(5,162		)	(2,444		)
Accounts receivable, net	$	238,903		$	255,805

The ongoing credit evaluation of our customers during the COVID-19 pandemic is further discussed in the Credit Risk section of Note 9. The Company did not experience material credit losses or customer defaults during the three months ended March 31, 2020.

Table of Contents

Materials, Supplies and Fuel

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



	March 31, 2020		December 31, 2019
Materials and supplies	$	88,346	$	82,809
Fuel - Electric Utilities	3,049		2,425
Natural gas in storage	1,499		31,938
Total materials, supplies and fuel	$	92,894	$	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:



	March 31, 2020		December 31, 2019
Accrued employee compensation, benefits and withholdings	$	45,070	$	62,837
Accrued property taxes	45,666		44,547
Customer deposits and prepayments	43,524		54,728
Accrued interest	43,776		31,868
Other (none of which is individually significant)	25,409		32,787
Total accrued liabilities	$	203,445	$	226,767

Table of Contents

(5) ~~REGULATORY ACCOUNTING~~Regulatory Matters

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


	March 31, 2019			December 31, 2018			March 31, 2018			March 31, 2020			December 31, 2019
Regulatory assets
Deferred energy and fuel cost adjustments ^(a)	$	35,512		$	29,661		$	25,056		$	35,687		$	34,088
Deferred gas cost adjustments ^(a)	5,124			3,362			2,118			—			1,540
Gas price derivatives ^(a)	3,939			6,201			11,045			1,302			3,328
Deferred taxes on AFUDC^(b)	7,771			7,841			7,808			7,739			7,790
Employee benefit plans ^(c)	111,724			110,524			109,999			117,150			115,900
Environmental^(a)	945			959			1,012			1,439			1,454
Loss on reacquired debt^(a)	20,570			21,001			20,267			24,299			24,777
Renewable energy standard adjustment ^(a)	1,533			1,722			1,600			340			1,622
Deferred taxes on flow through accounting^(c)	33,226			31,044			28,014			44,589			41,220
Decommissioning costs ^(b)	11,694			11,700			12,552			10,248			10,670
Gas supply contract termination ^(a)	12,866			14,310			18,590			7,007			8,485
Other regulatory assets^(a)	41,803			45,910			29,171			22,429			20,470
Total regulatory assets	286,707			284,235			267,232			272,229			271,344
Less current regulatory assets	(54,303		)	(48,776		)	(54,492		)	(49,415		)	(43,282		)
Regulatory assets, non-current	$	232,404		$	235,459		$	212,740		$	222,814		$	228,062

Regulatory liabilities
Deferred energy and gas costs^(a)	$	19,018		$	6,991		$	20,194		$	40,002		$	17,278
Employee benefit plan costs and related deferred taxes^(c)	42,207			42,533			40,332			41,518			43,349
Cost of removal^(a)	154,170			150,123			139,002			170,954			166,727
Excess deferred income taxes ^(c)	307,894			310,562			310,622			283,690			285,438
TCJA revenue reserve	16,549			18,032			15,239			5,147			3,418
Other regulatory liabilities^(c)	17,421			12,553			12,472			17,183			20,442
Total regulatory liabilities	557,259			540,794			537,861			558,494			536,652
Less current regulatory liabilities	(45,777		)	(29,810		)	(42,499		)	(54,345		)	(33,507		)
Regulatory liabilities, non-current	$	511,482		$	510,984		$	495,362		$	504,149		$	503,145

__________


(a)	~~We are allowed recovery~~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.

Table of Contents

Regulatory ~~Matters~~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 ~~2018~~2019 Annual Report on Form 10-K.

~~Regulatory Activity~~Black Hills Wyoming and Wyoming Electric

~~Nebraska~~Wygen 1 FERC Filing

Black Hills Wyoming has a PPA with Wyoming Electric expiring on December 31, 2022, which provides 60 MW of unit-contingent capacity and energy from Black Hills Wyoming’s Wygen I facility. On ~~March 29,~~August 2, 2019, ~~Nebraska Gas~~Black Hills Wyoming and Wyoming Electric jointly filed ~~an application~~a request with ~~the NPSC requesting to merge its two gas distribution utilities into~~FERC for approval of a new ~~public utility entity.~~60 MW PPA. The ~~filing also requests to merge~~agreement would fulfill Wyoming Electric’s capacity need at the ~~terms and conditions~~expiration of the ~~existing tariffs~~current agreement on December 31, 2022. If approved, Black Hills Wyoming will continue to deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and continuing for an additional 20 years to December 31, 2042. On February 21, 2020, the ~~two utilities into~~FERC set this filing for hearing. However, the hearing has been placed in abeyance pending a ~~single tariff.~~

~~Wyoming~~

~~On March 6, 2019,~~FERC monitored settlement process. Settlement negotiations are ongoing among all parties. Any settlement would require FERC approval. To the extent the parties are unable to reach agreement, the next step in FERC’s process would be to set the matter for hearing. We will continue to evaluate our options to fulfill Wyoming Gas filed an application with the WPSC requesting to merge its four gas distribution utilities into a new public utility entity. The filing also requests the new entity adopt the terms and conditions of the existing tariffs.

Electric’s 60 MW capacity need.

Colorado Gas

Jurisdictional Consolidation and Rate Review

On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate ~~the base rate areas,~~rates, tariffs, ~~terms~~ and ~~conditions and adjustment clauses~~services of its ~~two legacy utilities.~~2 existing gas distribution territories. The rate review ~~also requests~~requested $2.5 million in new revenue to recover ~~costs and~~ investments in safety, reliability and system integrity.

(6) ~~MATERIALS, SUPPLIES AND FUEL~~

Colorado Gas also requested a new rider mechanism to recover future safety and integrity investments in its system. On December 27, 2019, the ALJ issued a recommended decision denying the company’s plan to consolidate rate territories and rider mechanism and also recommended a rate decrease. On April 14, 2020, the CPUC deliberated on the ALJ’s recommended decision and filed exceptions to that decision. The ~~following amounts by major classification~~CPUC essentially accepted the ALJ’s recommended decisions, except for return on equity, which they lowered from 9.5% to 9.2%. A final order and new rates are ~~included in Materials, supplies and fuel~~anticipated to be effective in the ~~accompanying Condensed Consolidated Balance Sheets (in thousands) as of:~~

March 31, 2019 December 31, 2018 March 31, 2018
Materials and supplies $ 76,728
$ 75,081
$ 72,045
Fuel - Electric Utilities 2,485
2,850
2,903
Natural gas in storage held for distribution 8,463
39,368
7,097
Total materials, supplies and fuel $ 87,676
$ 117,299
$ 82,045

second quarter of 2020.

((6) 7) ~~EARNINGS PER SHARE~~Earnings Per Share

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

Three Months Ended March 31,
2019 2018

Net income available for common stock $ 103,808
$ 133,004

Weighted average shares - basic 59,920
53,319
Dilutive effect of:
Equity Units ^(a)
—
733
Equity compensation 140
70
Weighted average shares - diluted 60,060
54,122

~~__________~~


~~(a)~~	~~Calculated using the treasury stock method. On November 1, 2018, we completed settlement of the stock purchase contracts that are components of the Equity Units issued in November 2015.~~

~~The following outstanding securities were excluded in the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands):~~


	Three Months Ended March 31,		Three Months Ended March 31,
	2019	2018	2020		2019

Net income available for common stock			$	93,174	$	103,808

Weighted average shares - basic			61,778		59,920
Dilutive effect of:
Equity compensation	6	71	78		140
Anti-dilutive shares	6	71
Weighted average shares - diluted			61,856		60,060

Earnings per share of common stock:
Earnings per share, Basic			$	1.51	$	1.73
Earnings per share, Diluted			$	1.51	$	1.73

Table of Contents

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



	Three Months Ended March 31,
	2020	2019

Equity compensation	12	6
Restricted stock	26	—
Anti-dilutive shares	38	6

((7) 8) ~~NOTES PAYABLE, CURRENT MATURITIES AND DEBT~~Notes Payable, Current Maturities and Debt

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


	March 31, 2019				December 31, 2018				March 31, 2018				March 31, 2020				December 31, 2019
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit ^(a)		Balance Outstanding		Letters of Credit ^(a)
Revolving Credit Facility	$	—	$	14,006	$	—	$	22,310	$	—	$	15,830	$	165,000	$	17,281	$	—	$	30,274
CP Program	164,650		—		185,620		—		164,200		—		154,125		—		349,500		—
Total	$	164,650	$	14,006	$	185,620	$	22,310	$	164,200	$	15,830	$	319,125	$	17,281	$	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 three months ended March 31, 2020, we utilized a combination of our $750 million Revolving Credit Facility and CP Program

~~On July 30, 2018, we amended~~ to meet our business needs and ~~restated~~support our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 30, 2023 with two one year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to ~~$1.0 billion~~. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our Corporate credit rating from S&P, Fitch, and Moody's for our senior unsecured long-term debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were ~~0.125%~~, ~~1.125%, and~~ ~~1.125%, respectively, at March 31, 2019. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at March 31, 2019.~~

We have a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million. The notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration exemption.capital investment plan. Our net ~~payments under the CP Program~~short-term borrowings (payments) during the three months ended March 31, ~~2019~~2020 were ~~$21 million and our notes outstanding as of March 31, 2019 were $165~~$(30) million. ~~As of March 31, 2019, the~~The weighted average interest rate on Revolving Credit Facility and CP Program borrowings ~~was 2.70%. As of~~at March 31, ~~2019, we had outstanding letters of credit of totaling approximately $14 million.~~2020 was 1.92% and 1.74%, respectively.

Debt Covenants

Under our Revolving Credit Facility and term loan agreements, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Our Consolidated Indebtedness to Capitalization Ratio was calculated by dividing (i) ~~Consolidated Indebtedness,~~consolidated indebtedness, which includes letters of credit and certain guarantees issued, by (ii) ~~Capital,~~capital, which includes ~~Consolidated Indebtedness~~consolidated indebtedness plus ~~Net Worth,~~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, ~~at the end of each quarter:~~

As of March 31, 2019 Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio 58.1% Less than 65%

~~As of March 31, 2019,~~which we were in compliance with ~~this covenant.~~at March 31, 2020:



	As of March 31, 2020	Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio	58.2%	Less than	65%

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.

Table of Contents

~~(9) EQUITY~~(8) Equity

~~A summary of the changes in equity is as follows:~~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.

Three Months Ended March 31, 2019 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 (loss) 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 )
Cumulative effect of ASU 2016-02, Leases implementation
—
—
—
—
—
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

Three Months Ended March 31, 2018 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, 2017 53,579,986
$ 53,580
39,064
$ (2,306 ) $ 1,150,285
$ 548,617
$ (41,202 ) $ 111,232
$ 1,820,206
Net income (loss) available for common stock —
—
—
—
—
133,004
—
3,630
136,634
Other comprehensive income (loss), net of tax —
—
—
—
—
—
1,260
—
1,260
Dividends on common stock ($0.475 per share) —
—
—
—
—
(25,444 ) —
—
(25,444 )
Share-based compensation 64,770
65
14,895
(743 ) 1,433
—
—
—
755
Dividend reinvestment and stock purchase plan 4,061
4
—
—
215
—
—
—
219
Other stock transactions —
—
—
—
—
(16 ) 18
—
2
Distributions to noncontrolling interest —
—
—
—
—
—
—
(5,648 ) (5,648 )
March 31, 2018 53,648,817
$ 53,649
53,959
$ (3,049 ) $ 1,151,933
$ 656,161
$ (39,924 ) $ 109,214
$ 1,927,984

~~At-the-Market Equity Offering Program~~ATM Activity

Our ATM ~~equity offering program~~ allows us to sell shares of our common stock with an aggregate value of up to $300 million. The shares may be offered from time to time pursuant to a sales agreement dated August 4, 2017. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. We did not issue any common shares during the three months ended March 31, 2020 under the ATM. During the three months ended March 31, 2019, we issued a total of ~~280,497~~0.3 million shares of common stock under the ATM ~~equity offering program~~ for proceeds of $20 million, net of $0.2 million in ~~commissions. As of March 31, 2019, there were no shares that were sold, but not settled.~~

issuance costs.

(9) Risk Management and Derivatives

(10~~) RISK MANAGEMENT ACTIVITIES~~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 ~~operation~~operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. ~~To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk and Credit Policies and Procedures as discussed in our~~ ~~2018~~ ~~Annual Report on Form 10-K.~~

Market Risk

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

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

Interest rate risk associated with our variable debt.

Credit Risk

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

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

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

Although we did not experience material credit losses or customer defaults for the three months ended March 31, 2020, we are monitoring 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 future financial impacts to the allowance for credit losses.

Table of Contents

Derivatives and Hedging Activity

Our derivative and hedging activities ~~recorded~~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 1011.

Utilities

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

For our regulated ~~utilities’~~Utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Condensed Consolidated Balance Sheets in accordance with the state 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 ~~risks~~risk using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/or sales ~~during time frames ranging~~ from April ~~2019~~2020 through May ~~2021; a~~2022. A portion of ~~these~~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.~~Sheets and the ineffective portion, if any, is reported in Fuel, purchased power and cost of natural gas sold. Effectiveness of our ~~hedged~~hedging position is evaluated at ~~inception of the hedge, upon occurrence of a triggering event and as of the end of each quarter.~~

least quarterly.

The contract or notional amounts and terms of the electric and natural gas derivative commodity instruments held at our ~~utilities~~Utilities are composed of both long and short positions. We ~~were in a~~had the following net long ~~position~~positions as of:

March 31, 2019 December 31, 2018 March 31, 2018

Notional
(MMBtus)

Maximum
Term
(months)^(a)

Notional
(MMBtus)

Maximum
Term
(months)^(a)

Notional
(MMBtus)

Maximum
Term
(months)^(a)
Natural gas futures purchased 3,120,000
21 4,000,000
24 6,760,000
33
Natural gas options purchased, net 1,150,000
10 4,320,000
13 170,000
11
Natural gas basis swaps purchased 3,020,000
21 3,960,000
24 6,770,000
33
Natural gas over-the-counter swaps, net ^(b)
3,316,000
26 3,660,000
24 2,760,000
26
Natural gas physical contracts, net ^(c)
2,786,980
12 18,325,852
30 386,250
32



		March 31, 2020		December 31, 2019
	Units	Notional Amounts	Maximum Term (months)^(a)	Notional Amounts	Maximum Term (months)^(a)
Natural gas futures purchased	MMBtus	920,000	9	1,450,000	12
Natural gas options purchased, net	MMBtus	—	0	3,240,000	3
Natural gas basis swaps purchased	MMBtus	790,000	9	1,290,000	12
Natural gas over-the-counter swaps, net ^(b)	MMBtus	4,620,000	26	4,600,000	24
Natural gas physical contracts, net ^(c)	MMBtus	1,104,725	12	13,548,235	12
Electric wholesale contracts ^(c)	MWh	195,825	9	—	0

__________


(a)	Term reflects the maximum forward period hedged.


(b)	As of March 31, ~~2019~~, ~~534,000~~2020, 800,000 MMBtus of natural gas over-the-counter swaps purchases were designated as cash flow hedges.


(c)	Volumes exclude contracts that qualify for the normal ~~purchase,~~purchases and normal sales exception.

Based on March 31, 2019 prices, a $0.1 million loss would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

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 March 31, ~~2019,~~2020, the Company posted ~~$0.2~~$0.5 million related to such provisions, which is included in Other current assets on the Condensed Consolidated Balance Sheets.

~~Cash Flow~~

Table of Contents

Derivatives by Balance Sheet Classification

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

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



	Balance Sheet Location	March 31, 2020			December 31, 2019
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets, current	$	8		$	1
Noncurrent commodity derivatives	Other assets, non-current	—			3
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current	(284		)	(490		)
Noncurrent commodity derivatives	Other deferred credits and other liabilities	(10		)	(29		)
Total derivatives designated as hedges		$	(286	)	$	(515	)

Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets, current	$	1,772		$	341
Noncurrent commodity derivatives	Other assets, non-current	156			2
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current	(568		)	(1,764		)
Noncurrent commodity derivatives	Other deferred credits and other liabilities	(28		)	(63		)
Total derivatives not designated as hedges		$	1,332		$	(1,484	)

Derivatives Designated as Hedges

The impacts of cash flow hedges on our Condensed Consolidated Statements of Comprehensive Income isand Condensed Consolidated Statements of Income are presented below for the three months ended March 31, ~~2019~~2020 and ~~2018.~~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 March 31, 2019
(in thousands)
Derivatives in Cash Flow Hedging Relationships
Location of
Reclassifications from AOCI into Income

Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
Interest rate swaps Interest expense $ (713 )
Commodity derivatives Fuel, purchased power and cost of natural gas sold 554
Total $ (159 )

Three Months Ended March 31, 2018
(in thousands)
Derivatives in Cash Flow Hedging Relationships
Location of
Reclassifications from AOCI into Income

Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
Interest rate swaps Interest expense $ (713 )
Commodity derivatives Fuel, purchased power and cost of natural gas sold (621 )
Total $ (1,334 )

The following tables summarize the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the three months ended March 31, 2019 and 2018.

Three Months Ended March 31,
2019 2018
(in thousands)
Increase (decrease) in fair value:
Forward commodity contracts $ 234
$ (297 )
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps 713
713
Forward commodity contracts (554 ) 621
Total other comprehensive income (loss) from hedging $ 393
$ 1,037



	Three Months Ended March 31,						Three Months Ended March 31,
	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	257		(320		)	Fuel, purchased power and cost of natural gas sold	(486		)	554
Total	$	970	$	393			$	(1,199	)	$	(159	)

Based on March 31, 2020 prices, a $0.3 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.

Table of Contents

Derivatives Not Designated as ~~Hedge Instruments~~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 months ended March 31, ~~2019~~2020 and ~~2018 (in thousands).~~2019. Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.



		Three Months Ended March 31,
		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	$	1,362	$	—
Commodity derivatives - Natural Gas	Fuel, purchased power and cost of natural gas sold	766		25
		$	2,128	$	25

Three Months Ended March 31,
2019 2018
Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income

Commodity derivatives Fuel, purchased power and cost of natural gas sold $ 25
$ 254
$ 25
$ 254

As discussed above, financial instruments used in our regulated utilities are not designated as cash flow hedges. ~~However, there~~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 ~~assets~~asset or Regulatory liability accounts related to the hedges in our ~~utilities~~Gas Utilities were ~~$3.9 million, $6.2~~$1.3 million and ~~$11~~$3.3 million atas of March 31, ~~2019,~~2020 and December 31, ~~2018~~2019, respectively. For our Electric Utilities, the unrealized gains and ~~March 31, 2018, respectively.~~losses arising from these derivatives are recognized in the 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 111~~) FAIR VALUE MEASUREMENTS~~ — 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.

~~Derivative Financial Instruments~~

~~The accounting guidance~~Level 2 — Pricing inputs include quoted prices for ~~fair value measurements requires certain disclosures about~~identical or similar assets and liabilities ~~measured at~~in active markets other than quoted prices in Level 1, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3 — Pricing inputs are generally less observable from objective sources. These inputs reflect management’s best estimate of fair ~~value. This guidance establishes~~value using its own assumptions about the assumptions a ~~hierarchical framework for disclosing~~market participant would use in pricing the ~~observability of the inputs utilized in measuring assets and liabilities at fair value.~~ asset or liability.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. ~~For additional information, see Notes 1, 9, 10 and 11 to the Consolidated Financial Statements included in our 2018 Annual Report on Form 10-K filed with the SEC.~~

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

~~Valuation Methodologies for~~

Table of Contents

Recurring Fair Value Measurements

Derivatives

The commodity contracts for our Utilities ~~Segments,~~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 ~~component~~ based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position.

~~Recurring Fair Value Measurements~~ 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 March 31, 2019											As of March 31, 2020
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total		Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)											(in thousands)
Assets:
Commodity derivatives — Utilities	$	—	$	1,375	$	—	$	(388	)	$	987
Commodity derivatives — Gas Utilities												$	—	$	1,949	$	—	$	(13	)	$	1,936
Commodity derivatives — Electric Utilities												—		1,362		—		—			1,362
Total	$	—	$	1,375	$	—	$	(388	)	$	987	$	—	$	3,311	$	—	$	(13	)	$	3,298

Liabilities:
Commodity derivatives — Utilities	$	—	$	4,122	$	—	$	(4,009	)	$	113
Commodity derivatives — Gas Utilities												$	—	$	2,464	$	—	$	(1,573	)	$	891
Total	$	—	$	4,122	$	—	$	(4,009	)	$	113	$	—	$	2,464	$	—	$	(1,573	)	$	891


	As of December 31, 2018											As of December 31, 2019
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total		Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)											(in thousands)
Assets:
Commodity derivatives — Utilities	$	—	$	2,927	$	—	$	(1,408	)	$	1,519
Commodity derivatives — Gas Utilities												$	—	$	1,433	$	—	$	(1,085	)	$	348
Total	$	—	$	2,927	$	—	$	(1,408	)	$	1,519	$	—	$	1,433	$	—	$	(1,085	)	$	348

Liabilities:
Commodity derivatives — Utilities	$	—	$	6,801	$	—	$	(5,794	)	$	1,007
Commodity derivatives — Gas Utilities												$	—	$	5,254	$	—	$	(2,909	)	$	2,345
Total	$	—	$	6,801	$	—	$	(5,794	)	$	1,007	$	—	$	5,254	$	—	$	(2,909	)	$	2,345

Pension and Postretirement Plan Assets

As of March 31, 2018
Level 1 Level 2 Level 3
Cash Collateral and Counterparty
Netting
Total
(in thousands)
Assets:
Commodity derivatives — Utilities $ —
$ 414
$ —
$ (119 ) $ 295
Total $ —
$ 414
$ —
$ (119 ) $ 295

Liabilities:
Commodity derivatives — Utilities $ —
$ 12,259
$ —
$ (11,175 ) $ 1,084
Total $ —
$ 12,259
$ —
$ (11,175 ) $ 1,084

~~Fair Value Measures by Balance Sheet Classification~~

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

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

Balance Sheet Location March 31, 2019 December 31, 2018 March 31, 2018
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivatives Derivative assets — current $ 131
$ 415
$ —
Noncurrent commodity derivatives Other assets, non-current 9
18
—
Liability derivative instruments:
Current commodity derivatives Derivative liabilities — current (11 ) (114 ) (394 )
Noncurrent commodity derivatives Other deferred credits and other liabilities —
(4 ) (29 )
Total derivatives designated as hedges $ 129
$ 315
$ (423 )

Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivatives Derivative assets — current $ 801
$ 1,085
$ 295
Noncurrent commodity derivatives Other assets, non-current 46
1
—
Liability derivative instruments:
Current commodity derivatives Derivative liabilities — current (84 ) (833 ) (497 )
Noncurrent commodity derivatives Other deferred credits and other liabilities (18 ) (56 ) (164 )
Total derivatives not designated as hedges $ 745
$ 197
$ (366 )

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 ~~2018~~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.

Table of Contents

(12~~) FAIR VALUE OF FINANCIAL INSTRUMENTS~~

Other fair value measures

The ~~estimated~~following table presents the carrying amounts and fair values of ~~our~~ financial instruments ~~excluding derivatives which are presented in Note 11, were as follows~~not recorded at fair value on the Condensed Consolidated Balance Sheets (in thousands) as of:

March 31, 2019 December 31, 2018 March 31, 2018

Carrying
Amount
Fair Value
Carrying
Amount
Fair Value
Carrying
Amount
Fair Value
Cash and cash equivalents ^(a)
$ 12,225
$ 12,225
$ 20,776
$ 20,776
$ 30,947
$ 30,947
Restricted cash ^(a)
$ 3,494
$ 3,494
$ 3,369
$ 3,369
$ 2,958
$ 2,958
Notes payable ^(b)
$ 164,650
$ 164,650
$ 185,620
$ 185,620
$ 164,200
$ 164,200
Long-term debt, including current maturities ^{(c) (d)}
$ 2,956,042
$ 3,137,538
$ 2,956,578
$ 3,039,108
$ 3,114,530
$ 3,265,965



	March 31, 2020				December 31, 2019
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current maturities ^(a)	$	3,142,630	$	3,320,562	$	3,145,839	$	3,479,367

__________


(a)	Carrying value approximates fair value due to either the short-term length of maturity or variable interest rates that approximate prevailing market rates, and therefore is classified in Level 1 in the fair value hierarchy.


~~(b)~~	Notes payable consist of commercial paper borrowings and borrowings on our Revolving Credit Facility. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy.


~~(c)~~	Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified inas Level 2 in the fair value hierarchy.


~~(d)~~	Carrying amount of long-term debt is net of deferred financing costs.


(13) (11)	~~OTHER COMPREHENSIVE INCOME (LOSS)~~Other Comprehensive Income (Loss)

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

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


	Location on the Condensed Consolidated Statements of Income	Amount Reclassified from AOCI						Location on the Condensed Consolidated Statements of Income	Amount Reclassified from AOCI
		Three Months Ended							Three Months Ended March 31,
		March 31, 2019			March 31, 2018				2020			2019
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	(713	)	$	(713	)	Interest expense	$	(713	)	$	(713	)
Commodity contracts	Fuel, purchased power and cost of natural gas sold	554			(621		)	Fuel, purchased power and cost of natural gas sold	(486		)	554
		(159		)	(1,334		)		(1,199		)	(159		)
Income tax	Income tax benefit (expense)	35			297			Income tax benefit (expense)	285			35
Total reclassification adjustments related to cash flow hedges, net of tax		$	(124	)	$	(1,037	)		$	(914	)	$	(124	)

Amortization of components of defined benefit plans:
Prior service cost	Operations and maintenance	$	19		$	45		Operations and maintenance	$	30		$	19

Actuarial gain (loss)	Operations and maintenance	(220		)	(622		)	Operations and maintenance	(597		)	(220		)
		(201		)	(577		)		(567		)	(201		)
Income tax	Income tax benefit (expense)	48			126			Income tax benefit (expense)	88			48
Total reclassification adjustments related to defined benefit plans, net of tax		$	(153	)	$	(451	)		$	(479	)	$	(153	)
Total reclassifications		$	(277	)	$	(1,488	)		$	(1,393	)	$	(277	)

Table of Contents

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													—			(175		)	55			(120		)
Amounts reclassified from AOCI													543			371			479			1,393
As of March 31, 2020													$	(14,579	)	$	(260	)	$	(14,543	)	$	(29,382	)


	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total			Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
As of December 31, 2018	$	(17,307	)	$	328		$	(9,937	)	$	(26,916	)	$	(17,307	)	$	328		$	(9,937	)	$	(26,916	)
Other comprehensive income (loss)
before reclassifications	—			180			—			180			—			180			—			180
Amounts reclassified from AOCI	550			(426		)	153			277			550			(426		)	153			277
As of March 31, 2019	$	(16,757	)	$	82		$	(9,784	)	$	(26,459	)	$	(16,757	)	$	82		$	(9,784	)	$	(26,459	)


	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
Balance as of December 31, 2017	$	(19,581	)	$	(518	)	$	(21,103	)	$	(41,202	)
Other comprehensive income (loss)
before reclassifications	—			(228		)	—			(228		)
Amounts reclassified from AOCI	561			476			451			1,488
Reclassifications of certain tax effects from AOCI	15			—			3			18
As of March 31, 2018	$	(19,005	)	$	(270	)	$	(20,649	)	$	(39,924	)

(14~~) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION~~(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 continue to 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 three months ended March 31, 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 March 31, 2020, we estimate the unfunded status of our employee benefit plans to be approximately $46 million compared to $51 million at December 31, 2019. 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.

Three Months Ended March 31, 2019 March 31, 2018
(in thousands)
Non-cash investing and financing activities —
Property, plant and equipment acquired with accrued liabilities $ 56,571
$ 21,708

Cash (paid) refunded during the period —
Interest (net of amounts capitalized) $ (30,672 ) $ (36,928 )
Income taxes $ 8
$ (14,336 )

Table of Contents

(15~~) EMPLOYEE BENEFIT PLANS~~

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 March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
Service cost	$	1,346		$	1,708		$	1,353		$	1,346
Interest cost	4,343			3,867			3,357			4,343
Expected return on plan assets	(6,100		)	(6,185		)	(5,648		)	(6,100		)
Prior service cost	6			15
Prior service cost (benefit)							—			6
Net loss (gain)	941			2,158			2,093			941
Net periodic benefit cost	$	536		$	1,563		$	1,155		$	536

Defined Benefit Postretirement Healthcare ~~Plans~~Plan

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


	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2020			2019
Service cost	$	454		$	573		$	514		$	454
Interest cost	560			521			412			560
Expected return on plan assets	(57		)	(57		)	(45		)	(57		)
Prior service cost (benefit)	(99		)	(99		)	(137		)	(99		)
Net loss (gain)	—			54			5			—
Net periodic benefit cost	$	858		$	992		$	749		$	858

Supplemental Non-qualified Defined Benefit and Defined Contribution Plans

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


	Three Months Ended March 31,				Three Months Ended March 31,
	2019		2018		2020			2019
Service cost^(a)	$	1,285	$	280	$	(1,370	)	$	1,285
Interest cost	324		293		275			324
Net loss (gain)	134		250		426			134
Net periodic benefit cost	$	1,743	$	823	$	(669	)	$	1,743

~~__________~~


~~(a)~~	~~The increase in service cost for the three months ended March 31, 2019 compared to the same period in 2018 is primarily driven by market returns.~~

Table of Contents

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 ~~2019~~the first quarter of 2020 and anticipated contributions for ~~2019~~2020 and ~~2020~~2021 are as follows (in thousands):


	Contributions Made		Additional Contributions		Contributions		Contributions Made		Additional Contributions		Contributions
	Three Months Ended March 31, 2019		Anticipated for 2019		Anticipated for 2020		Three Months Ended March 31, 2020		Anticipated for 2020		Anticipated for 2021
Defined Benefit Pension Plan	$	—	$	12,700	$	12,700	$	—	$	12,700	$	12,700
Non-pension Defined Benefit Postretirement Healthcare Plans	$	1,109	$	3,326	$	4,271	$	1,335	$	4,006	$	5,364
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans	$	366	$	1,097	$	1,562	$	355	$	1,065	$	1,614

(16~~) COMMITMENTS AND CONTINGENCIES~~(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 ~~2018~~2019 Annual Report on Form 10-K except for those described below.

~~Dividend Restrictions~~

~~Our Revolving Credit Facility~~Future Purchase Agreement - Black Hills Wyoming and ~~other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of March 31, 2019, we were in compliance with the debt covenants.~~

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

Our utilities are generally limited in the amount of dividends allowed to be paid to us as a utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions and financing agreements. As of March 31, 2019, the restricted net assets at ourWyoming Electric ~~Utilities and Gas Utilities were approximately $257 million.~~

~~(17) DISCONTINUED OPERATIONS~~

Results of operations for discontinued operations have been classified as Loss from discontinued operations, net of income taxes in the accompanying Condensed Consolidated Statements of Income. Assets and liabilities of the discontinued operations have been reclassified and reflected on the accompanying Condensed Consolidated Balance Sheets as “Current assets held for sale” and “Current liabilities held for sale”, respectively. Prior periods relating to our discontinued operations have also been reclassified to reflect consistency within our condensed consolidated financial statements.

~~Oil and Gas Segment~~

~~On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture of our Oil and Gas segment in 2018.~~

~~Total assets~~Black Hills Wyoming has a PPA with Wyoming Electric expiring on December 31, 2022, which provides 60 MW of unit-contingent capacity and ~~liabilities~~energy from Black Hills Wyoming’s Wygen I facility. On August 2, 2019, Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for approval of a new 60 MW PPA. On February 21, 2020, the FERC set this filing for hearing. However, the hearing has been placed in abeyance pending a FERC monitored settlement process. Settlement negotiations are ongoing among all parties. Any settlement would require FERC approval. To the extent the parties are unable to reach agreement, the next step in FERC’s process would be to set the matter for hearing. See ~~our Oil and Gas segment~~Note 5 ~~at March 31, 2018 were classified as Current assets held~~ for ~~sale and Current liabilities held for sale on the accompanying Condensed Consolidated Balance Sheets due to the final disposals occurring in 2018.~~additional information.

As of
(in thousands) March 31, 2018
Other current assets $ 4,332
Deferred income tax assets, noncurrent, net

3,739
Property, plant and equipment, net 16,653
Other current liabilities (17,233 )
Other noncurrent liabilities (7,677 )
Net (liabilities) $ (186 )

~~(18) INCOME TAXES~~(14) Income Taxes

~~Income~~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 ~~benefit (expense), net~~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 to 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.

Based on the timing of the CARES Act, for the three months ended March 31, ~~2019~~2020, the related tax benefits from the CARES Act were not material. We are currently reviewing the potential future benefits related to employee retention tax credits and the payroll tax deferral provision to assess the impact on our financial position, results of operations and cash flows.

Table of Contents

Income tax (expense) for the Three Months Ended March 31, 2020 Compared to the Three Months Ended March 31, 2019.

Income tax benefit (expense) for the three months ended March 31, 2020 was ~~$(17)~~$(16) million compared to ~~$26~~$(17) million reported for the same period in ~~2018. The increase in tax expense was primarily due to:~~


•	~~A prior year $49 million tax benefit resulting fromlegal entity restructuring, partially offset by:~~


◦	~~A prior year $2.3 million income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes; and~~


◦	A current year $3.4 million increase in income tax benefit from forecasted federal production tax credits and state investment tax credits as well as $1.8 million of income tax benefit for deferred tax amortization related to tax reform (which is offset by reduced revenue at our utilities).

~~Prior year tax benefit related to legal restructuring~~

~~As part of the Company’s ongoing efforts to continue to integrate the~~legal entities that the Company acquired in recent years, certain legal entity restructuring transactions occurred on March 31, 2018. As a result of these transactions, $49 million of deferred income tax assets, related to goodwill that is amortizable for tax purposes, were recorded and deferred tax benefits of $49 million were recorded to Income tax benefit (expense) on the Condensed Consolidated Statements of Income. Due to this being a common control transaction, it had no effect on the other assets and liabilities of these entities.

~~Prior year TCJA expense~~

~~On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21% effective January 1, 2018. During~~2019. For the three months ended March 31, ~~2018, we recorded approximately $2.3 million~~2020 the effective tax rate was 14.1% compared to 13.9% for the same period in 2019. The higher effective tax rate is primarily due to a discrete tax adjustment related to the impairment of ~~additional~~our investment in equity securities of a privately held oil and gas company partially offset by increased tax ~~expense~~benefits from forecasted federal production tax credits associated with ~~changes in the prior estimated impacts of TCJA related items.~~new wind assets.

(15) Investments

~~(19) ACCRUED LIABILITIES~~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 amount 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 amount and the fair value of the investment at March 31, 2020.

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

March 31, 2019 December 31, 2018 March 31, 2018
Accrued employee compensation, benefits and withholdings $ 48,078
$ 63,742
$ 46,262
Accrued property taxes 43,662
42,510
42,912
Customer deposits and prepayments 39,125
43,574
35,748
Accrued interest and contract adjustment payments 35,149
31,759
30,426
CIAC current portion 1,485
1,485
1,552
Other (none of which is individually significant) 28,573
32,431
37,140
Total accrued liabilities $ 196,072
$ 215,501
$ 194,040



	March 31, 2020		December 31, 2019
Investment in privately held oil and gas company	$	1,500	$	8,359
Cash surrender value of life insurance contracts	13,235		13,056
Other investments	515		514
Total investments	$	15,250	$	21,929

~~(20) LEASES~~(16) Subsequent Events

~~Lessee~~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 the Note 5 disclosure surrounding Colorado Gas’ jurisdictional consolidation and rate review.

There are many uncertainties regarding the COVID-19 pandemic, and the Company is closely monitoring the impact of the pandemic on all aspects of its business, including how it will impact its customers, employees, suppliers, vendors, and business partners. We ~~lease from third parties certain office~~are unable to predict the impact that COVID-19 will have on our financial position and ~~operation center facilities, communication tower sites, equipment,~~operating results due to numerous uncertainties. The Company expects to continue to assess the evolving impact of COVID-19 and ~~materials storage. Our leases have remaining lease terms ranging from less than one year~~intends to ~~37 years, including options~~make adjustments to ~~extend that are reasonably certain to be exercised.~~

~~The components of lease expense were as follows (in thousands):~~

Income Statement Location Three Months Ended March 31, 2019
Operating lease cost Operations and maintenance $ 311
Finance lease cost:
Amortization of right-of-use asset Depreciation, depletion and amortization 17
Interest on lease liabilities Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) 3
Total lease cost $ 331

its responses accordingly.

~~Supplemental balance sheet information related to leases was as follows (in thousands):~~

Balance Sheet Location As of March 31, 2019
Assets:
Operating lease assets Other assets, non-current $ 5,331
Finance lease assets Other assets, non-current 481
Total lease assets $ 5,812

Liabilities:
Current:
Operating leases Accrued liabilities $ 974
Finance leases Accrued liabilities 92

Noncurrent:
Operating leases Other deferred credits and other liabilities 4,563
Finance leases Other deferred credits and other liabilities 391
Total lease liabilities $ 6,020

~~Supplemental cash flow information related to leases was as follows (in thousands):~~

Three Months Ended March 31, 2019
Cash paid included in the measurement of lease liabilities:
Operating cash flows from operating leases $ 246
Operating cash flows from finance lease $ 3
Financing cash flows from finance lease $ 15
Right-of-use assets obtained in exchange for lease obligations:
Operating leases $ 2,328
Finance leases $ —



	~~As of March 31, 2019~~
~~Weighted average remaining lease term (years):~~
~~Operating leases~~	~~8 years~~
~~Finance leases~~	~~5 years~~

~~Weighted average discount rate:~~
~~Operating leases~~	~~4.23~~	%
~~Finance leases~~	~~4.21~~	%

~~As of March 31, 2019, scheduled maturities of lease liabilities for future years were as follows (in thousands):~~

Operating Leases Finance Leases Total
2019 ^(a)
$ 952
$ 83
$ 1,035
2020 936
111
1,047
2021 820
111
931
2022 698
111
809
2023 699
110
809
Thereafter 2,653
9
2,662
Total lease payments^(b)
$ 6,758
$ 535
$ 7,293
Less imputed interest 1,221
52
1,273
Present value of lease liabilities $ 5,537
$ 483
$ 6,020


~~(a)~~	~~Includes lease liabilities for the remaining nine months of 2019.~~


~~(b)~~	~~Lease payments exclude payments to landlords for common area maintenance, real estate taxes, and insurance.~~

~~As previously disclosed in Note 14 of the Notes to the Consolidated Financial Statements in our 2018 Annual Report on Form 10-K, prior to the adoption of ASU 2016-02,~~ ~~Leases (Topic 842),~~ ~~the future minimum payments required under operating lease agreements as of December 31, 2018 were as follows (in thousands):~~

Operating Leases
2019 $ 1,052
2020 464
2021 344
2022 224
2023 216
Thereafter 1,776
Total lease payments
$ 4,076

~~Lessor~~

~~We lease to third parties certain generating station ground leases, communication tower sites, and natural gas pipeline. These leases have remaining terms ranging from less than one year to 35 years.~~

~~The components of lease revenue were as follows (in thousands):~~

Income Statement Location Three Months Ended March 31, 2019
Operating lease income Revenue $ 638

~~As of March 31, 2019, scheduled maturities of lease receivables for future years were as follows (in thousands):~~

Operating Leases
2019 ^(a)
$ 1,652
2020 2,010
2021 1,843
2022 1,793
2023 1,799
Thereafter 55,481
Total lease receivables $ 64,578


~~(a)~~	~~Includes lease receivables for the remaining nine months of 2019.~~

Table of Contents


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

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

Electric Utilities: Our Electric Utilities segment generates, transmits and distributes electricity to approximately ~~212,000~~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 ~~own~~ distribution systems. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates. We also provide non-regulated services through our Tech Services product lines.

Gas Utilities: Our Gas Utilities ~~conduct~~segment conducts natural gas utility operations through our Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming subsidiaries. Our Gas Utilities ~~distribute~~segment distributes and ~~transport~~transports natural gas through our pipeline network to approximately ~~1,054,000~~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.

~~Our Gas Utilities also provide non-regulated services through Black Hills Energy Services.~~ Black Hills Energy Services provides natural gas supply to approximately ~~47,000~~49,000 retail distribution customers under the Choice Gas Program in Nebraska and ~~Wyoming with unbundled natural gas commodity offerings~~Wyoming. Additionally, we provide services under the regulatory-approved Choice Gas Program. We also sell, install and service air conditioning, heating and water-heating equipment, and provide associated repair service and protection plans under various trade names. Service Guard Comfort Plan and CAPP provide appliance repair services to approximately 62,000 and 28,000 residential customers, respectively, through Company technicians and third-party service providers, typically through on-going monthly service agreements. Tech Services ~~serves gas transportation customers throughout our service territory by constructing~~ and ~~maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.~~also offer HomeServe products.

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

Mining: Our Mining segment ~~produces~~extracts coal at our ~~coal~~ 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.

Accounting standards for presentation of segments requires an approach based on the way we organize the segments for making operating decisions and how the chief operating decision maker (CODM) assesses performance. We have changed our segment performance metrics and concluded that adjusted operating income, instead of net income available for common stock that was used previously, is the most relevant metric for measuring segment performance.

The change to our segment performance measure resulted in a revision of the Company’s segment disclosures for all periods to report adjusted operating income as the measure of segment profit and adjust operating income for the power sales agreement as an executory contract and not a capital lease.

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~~Electric Utilities is June through August while the normal peak usage season for our ~~gas utilities~~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 months ended March 31, ~~2019~~2020 and ~~2018~~2019, and our financial condition as of March 31, ~~2019,~~2020 and December 31, ~~2018 and March 31, 2018,~~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 5345.

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

Table of Contents

Results of Operations

~~Executive~~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 employees, customers, 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.

For the three months ended March 31, 2020, we did not experience significant impacts to our financial results and operational activities due to COVID-19.

Decline in revenues and customer loads for the three months ended March 31, 2020, when compared to the same period in the prior year, were driven primarily by weather. We continue to closely monitor loads, particularly in states that have implemented more restrictive stay-at-home executive orders or recommendations. We have proactively communicated with various commercial and industrial customers in our service territories to understand their needs and forecast the potential financial implications. We did not experience a significant increase in bad debt expense for the three months ended March 31, 2020. We have informed both our customers and regulators that disconnections for non-payment will be temporarily suspended. We continue to monitor the impacts of COVID-19 on our cash flows and bad debt expense.

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. For the three months ended March 31, 2020, the Company utilized a combination of its $750 million Revolving Credit Facility and CP Program to meet its funding requirements. In recent weeks, the liquidity for A-2/P-2 rated issuers, which is the Company’s current Commercial Paper rating with S&P and Moody’s, respectively, within the Commercial Paper market has improved which provides additional liquidity options under the Revolving Credit Facility. The Company has no material debt maturities until late 2023, and as of March 31, 2020, had $468 million of liquidity which included cash and available capacity on its Revolving Credit Facility. We also continue to monitor the funding status of our employee benefit plan obligations, which did not materially change during the first quarter 2020.

We are monitoring supply chains, including lead times for key materials and supplies, availability of resources, and status of large capital projects. To date, there have been limited impacts to supply chains including 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 ongoing due to the impacts of COVID-19, including the potential for rescheduling projects. We currently do not anticipate a significant impact 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 minimize the impact to our employees and the service 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 had traveled to an at-risk area, limiting travel to only mission critical purposes and sequestering essential employees.

As we look forward, we anticipate that our 2020 operating results could potentially be impacted as a result of COVID-19, including impact related to the following:

Increased residential load and decreased commercial and industrial demand;

Increased allowance for credit losses and bad debt expense as a result of suspending disconnections and delayed or non-payment from customers;

Disruption in our supply chains impacting our ability to timely execute our capital investment and maintenance project plans;

Volatility in cost of sales due to changes in commodity prices;

Rate actions from our regulators;

Decreased training, travel and outside services related expenses;

Increased operation and maintenance costs if we experience a shortage of labor availability which would lead to deferral of capital projects and sequestration costs for employees deemed critical at our generating facilities; and

Increased tax benefits for employee retention tax credits and reduced cash tax payments for the payroll tax deferral provision and acceleration of alternative minimum tax (“AMT”) credit refunds from the CARES Act

Table of Contents

We provide recurring 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 at a later date.

During these uncertain times, we remain highly focused on the safety and health of our employees, customers, 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.

Consolidated Summary ~~Significant Events~~ and Overview



	Three Months Ended March 31,
	2020				2019
(in millions, except per share amounts)	Income		EPS		Income		EPS

Net income available for common stock	$	93.2	$	1.51	$	103.8	$	1.73

Three Months Ended March 31, ~~2019~~2020 Compared to Three Months Ended March 31, ~~2018.~~2019. Net income from continuing operations available for common stock for the three months ended March 31, 2019 was $104 million, or $1.73 per diluted share, compared to $135 million, or $2.50 per diluted share, reported for the same period in 2018.

The variance to the prior year included the following:

Electric Utilities’ adjusted operating income ~~increased $2.5~~decreased $5.4 million primarily due to ~~favorable~~lower heating demand from warmer winter weather, ~~compared to prior year~~lower power marketing margins and higher operating expenses partially offset by ~~higher operating expenses driven by outside services~~increased mark-to-market on wholesale energy contracts and ~~employee costs;~~increased rider revenues;

Gas Utilities’ adjusted operating income ~~increased $7.9~~decreased $0.4 million primarily due to ~~new rates and favorable~~lower heating demand from warmer winter weather ~~compared to prior year partially offset by~~and higher operating expenses mostly offset by new rates, prior year amortization of excess deferred income taxes, customer growth and increased mark-to-market on non-utility natural gas commodity contracts;

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

A $3.1 million increase in other income primarily due to reduced costs for our non-qualified benefit plan driven by ~~outside services and employee costs; and~~market performance on plan assets.


•	~~A prior year $49 million tax benefit resulting fromlegal entity restructuring partially offset by:~~


◦	~~A prior year $2.3 million income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes; and~~


◦	A current year $3.4 million increase in income tax benefit from forecasted federal production tax credits and state investment tax credits as well as $1.8 million of income tax benefit for deferred tax amortization related to tax reform (which is offset by reduced revenue at our utilities).

Net income available for common stock for the three months ended March 31, 2019 was $104 million, or $1.73 per diluted share, compared to $133 million, or $2.46 per diluted share reported for the same period in 2018. (Loss) from discontinued operations for the three months ended March 31, 2018 was $(2.3) million or $(0.04). There was no (Loss) from discontinued operations for the three months ended March 31, 2019.

Table of Contents

The following table summarizes select financial results by operating segment and details significant items (in thousands):


	Three Months Ended March 31,									Three Months Ended March 31,
	2019			2018			Variance			2020			2019			Variance
Revenue
Revenue	$	635,681		$	611,966		$	23,715		$	576,083		$	635,681		$	(59,598	)
Inter-company eliminations	(37,871		)	(36,577		)	(1,294		)	(39,033		)	(37,871		)	(1,162		)
	$	597,810		$	575,389		$	22,421		$	537,050		$	597,810		$	(60,760	)
Adjusted operating income ^(a)
Electric Utilities	$	41,020		$	38,480		$	2,540		$	35,650		$	41,020		$	(5,370	)
Gas Utilities	103,314			95,443			7,871			102,897			103,314			(417		)
Power Generation	11,967			11,776			191			11,349			11,967			(618		)
Mining	4,337			4,271			66			3,129			4,337			(1,208		)
Corporate and Other	(507		)	(1,696		)	1,189			160			(507		)	667
Operating income	160,131			148,274			11,857			153,185			160,131			(6,946		)

Interest expense, net	(34,717		)	(34,995		)	278			(35,453		)	(34,717		)	(736		)
Impairment of investment										(6,859		)	—			(6,859		)
Other income (expense), net	(789		)	(104		)	(685		)	2,353			(789		)	3,142
Income tax benefit (expense) ^{(b) (c)}	(17,263		)	25,802			(43,065		)
Income from continuing operations	107,362			138,977			(31,615		)
Net (loss) from discontinued operations	—			(2,343		)	2,343
Income tax (expense)										(16,002		)	(17,263		)	1,261
Net income	107,362			136,634			(29,272		)	97,224			107,362			(10,138		)
Net income attributable to noncontrolling interest	(3,554		)	(3,630		)	76			(4,050		)	(3,554		)	(496		)
Net income available for common stock	$	103,808		$	133,004		$	(29,196	)	$	93,174		$	103,808		$	(10,634	)

Amounts attributable to common shareholders:
Net income from continuing operations available for common stock	$	103,808		$	135,347		$	(31,539	)
Net (loss) from discontinued operations	—			(2,343		)	2,343
Net income available for common stock	$	103,808		$	133,004		$	(29,196	)

__________

(a)

~~Due to changes to our segment performance measure,~~ Adjusted operating income ~~was recast~~recognizes intersegment revenues and costs for ~~the three months ended March 31, 2018 for Electric Utilities and Power Generation segments and Corporate and Other. These changes had no~~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 ~~on our~~ consolidated financial results. ~~See segment discussions in the sections below for more information.~~


~~(b)~~	Income tax benefit (expense) for the three months ended March 31, 2019 included a $3.4 million increase in income tax benefit from forecasted federal production tax credits and state investment tax credits as well as $1.8 million of income tax benefit for deferred tax amortization related to tax reform (which is offset by reduced revenue at our utilities).


~~(c)~~	~~Income tax benefit (expense) for the three months ended March 31, 2018 included a $49 million tax benefit resulting fromlegal entity restructuring and $2.3 million of income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes.~~

~~Overview of~~ Business ~~Segments~~Segment Highlights and Corporate Activity

Electric Utilities Segment

On April 14, 2020, Colorado Electric ~~Utilities experienced colder winter weather during the three months ended March 31, 2019 compared~~submitted its 30-day report to the ~~same period~~CPUC summarizing the first milestone in ~~2018. Heating degree days~~the Renewable Advantage Plan which is expected to provide cost savings to customers and double its renewable energy portfolio. The bidding process for new renewable energy projects concluded on February 15, 2020, attracting interest from developers in southern Colorado and across the ~~three months ended March~~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 Pueblo and Pueblo County. The winning bid(s) and pricing will be determined in June 2020 when Colorado Electric files its 120-day report to the CPUC.

Construction continues on the $79 million Corriedale project, which is expected to be placed in service by year-end 2020. As a result of COVID-19, we regularly communicate with our key suppliers to maintain visibility into any disruptions they are experiencing in the receipt of supplies and materials from their suppliers. At this time, we have not experienced significant disruption in our supply chain due to COVID-19 which would cause us to adjust the in-service date for this project. If significant disruptions occur and we were unable to complete the project by December 31, 2020, we could experience loss of production tax credits.

On August 2, 2019, ~~were 7% higher than normal, compared~~Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for approval of a new 60 MW PPA. If approved, Wyoming Electric will continue to ~~1% higher than normal~~receive 60 MW of energy from the Wygen I power plant starting January 1, 2023, and for 20 additional years. On February 21, 2020, the ~~same period~~FERC set this filing for hearing. However, the hearing has been placed in ~~2018.~~abeyance pending a FERC monitored settlement process. Settlement negotiations are ongoing among all parties. Any settlement would require FERC approval. To the extent the parties are unable to reach agreement, the next step in FERC’s process would be to set the matter for hearing. We will continue to evaluate our options to fulfill our 60 MW capacity need.

Table of Contents

Gas Utilities Segment

On February 1, 2019, Colorado Gas ~~Utilities experienced colder winter weather during~~filed a rate review with the ~~three months ended March 31,~~CPUC requesting approval to consolidate rates, tariffs, and services of its two existing gas distribution territories. The rate review requested $2.5 million in new revenue to recover investments in safety, reliability and system integrity. Colorado Gas also requested a new rider mechanism to recover future safety and integrity investments in its system. On December 27, 2019, ~~compared~~the ALJ issued a recommended decision denying the company’s plan to consolidate rate territories and rider mechanism and also recommended a rate decrease. On April 14, 2020, the ~~same period~~CPUC deliberated on the ALJ’s recommended decision and filed exceptions to that decision. The CPUC essentially accepted the ALJ’s recommended decisions, except for return on equity, which they lowered from 9.5% to 9.2%. A final order and new rates are anticipated to be effective in ~~2018. Heating degree days for~~ the ~~three months ended March 31, 2019 were 11% higher than normal, compared to 2% higher than normal for the same period in 2018.~~second quarter of 2020.

~~Regulatory activity:~~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 revenue based on a return on equity of 9.40% and a capital structure of 50.23% equity and 49.77% debt. The approval also allows for a rider to recover integrity investments for system safety and reliability.


◦	On March 29, 2019, Nebraska Gas filed an application with the NPSC to consolidate its two gas distribution utilities into a new public utility entity. The filing also requests to consolidate the terms and conditions of the existing tariffs of the two utilities into a single tariff.

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. A rate review is expected to be filed mid-year 2020 to consolidate the rates, tariffs and services of its two utilities.


◦	On March 6, 2019, Wyoming Gas filed an application with the WPSC to consolidate its four gas distribution utilities into a new public utility entity. The filing also requests the new entity adopt the terms and conditions of the existing tariffs.


◦	On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate the base rate areas, tariffs, terms and conditions and adjustment clauses of its two legacy utilities. The rate review also requests $2.5 million in new revenue to recover costs and investments in safety, reliability and system integrity.

Power Generation Segment

On ~~March 11,~~August 2, 2019, Black Hills Wyoming and Wyoming Electric ~~Generation commenced construction on~~jointly filed a request with FERC for approval of a new 60 MW PPA. If approved, Black Hills Wyoming will continue to deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and for 20 additional years. On February 21, 2020, the ~~$71 million, 60-megawatt Busch Ranch II Wind Farm. The wind farm is expected to be completed and~~FERC set this filing for hearing. However, the hearing has been placed in ~~service~~abeyance pending a FERC monitored settlement process. See additional information in ~~2019.~~the Electric Utilities Segment highlights above.

Corporate and Other

On April ~~30, 2019,~~16, 2020, S&P affirmed South Dakota Electric’s credit rating at A.

~~During the three months ended March 31, 2019, we issued a total of 280,497 shares of common stock for net proceeds of approximately $20 million through our ATM equity offering program.~~

On ~~February 28, 2019,~~April 10, 2020, S&P affirmed our BBB+ rating and maintained a ~~Stable~~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.

Operating Results

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.

Table of Contents

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.

For the three months ended March 31, 2020, we did not experience significant impacts to gross margin for any business segment as a result of COVID-19. Prudently incurred fuel, purchased power, and natural gas costs to serve our customers are recovered through cost adjustment mechanisms at each of our regulated utilities.

Our gross margin measure may not be comparable to other companies’ gross margin measure. Furthermore, this measure is not intended to replace operating income, as determined in accordance with GAAP, as an indicator of operating performance.

Electric Utilities


	Three Months Ended March 31,						Three Months Ended March 31,
	2019		2018		Variance		2020		2019		Variance
	(in thousands)						(in thousands)
Revenue	$	182,927	$	173,555	$	9,372	$	174,139	$	182,927	$	(8,788	)

Total fuel and purchased power	73,283		68,738		4,545		64,460		73,283		(8,823		)

Gross margin (non-GAAP)	109,644		104,817		4,827		109,679		109,644		35

Operations and maintenance	47,144		45,093		2,051		50,499		47,144		3,355
Depreciation and amortization	21,480		21,244		236		23,530		21,480		2,050
Total operating expenses	68,624		66,337		2,287		74,029		68,624		5,405

Adjusted operating income ^(a)	$	41,020	$	38,480	$	2,540	$	35,650	$	41,020	$	(5,370	)

~~________________~~


~~(a)~~	Due to changes to our segment performance measure, Adjusted operating income was recast for the three months ended 2018, which resulted in a change of $1.7 million. The impact to Adjusted operating income for the three months ended March 31, 2019 was ($5.4) million. There was no impact on our consolidated Operating income.

Results of Operations for the Electric Utilities for the Three Months Ended March 31, ~~2019~~2020 Compared to the Three Months Ended March 31, ~~2018:~~2019:

Gross margin for the three months ended March 31, ~~2019 increased~~2020 did not change as a result of the following:

(in millions)
Reduction in purchased power capacity charges $ 1.6
Off-system power marketing 1.3
Weather 0.6
Rider recovery 0.4
Residential customer growth 0.3
Other 0.6
Total increase in Gross margin (non-GAAP) $ 4.8



	(in millions)
Increased mark-to-market on wholesale energy contracts	$	1.4
Rider recovery	1.0
Weather	(1.8		)
Off-system power marketing	(1.2		)
Other	0.6
Total change in Gross margin (non-GAAP)	$	—

Operations and maintenance expense increased primarily due to higher ~~outside services expenses~~employee-related costs and higher ~~employee costs~~generation expenses driven by ~~labor and benefits.~~timing of planned outages.

Depreciation and amortization ~~was comparable~~increased primarily due to ~~the same period in the~~a higher asset base driven by prior ~~year.~~year capital expenditures.

Table of Contents

Operating Statistics


							Electric Revenue				Quantities Sold
	Electric Revenue (in thousands)				Quantities sold (MWh)		(in thousands)				(MWh)
	Three Months Ended March 31,				Three Months Ended March 31,		Three Months Ended March 31,				Three Months Ended March 31,
	2019		2018		2019	2018	2020		2019		2020	2019
Residential	$	57,638	$	55,741	389,178	383,270	$	54,505	$	57,638	373,150	389,178
Commercial	60,963		61,984		505,573	500,136	57,823		60,963		494,308	505,573
Industrial	32,440		30,800		426,614	400,709	32,169		32,440		460,632	426,614
Municipal	4,139		4,141		36,636	36,324	3,878		4,139		36,399	36,636
Subtotal Retail Revenue - Electric	155,180		152,666		1,358,001	1,320,439	148,375		155,180		1,364,489	1,358,001
Contract Wholesale	8,343		9,050		223,020	237,704
Contract Wholesale ^(a)							5,553		8,343		131,778	223,020
Off-system/Power Marketing Wholesale	6,692		4,144		140,850	129,041	4,867		6,692		165,785	140,850
Other	12,712		7,695		—	—	15,344		12,712		—	—
Total Revenue and Energy Sold	182,927		173,555		1,721,871	1,687,184	174,139		182,927		1,662,052	1,721,871
Other Uses, Losses or Generation, net	—		—		97,000	90,855
Other Uses, Losses or Generation, net ^(b)							—		—		90,871	97,000
Total Revenue and Energy	182,927		173,555		1,818,871	1,778,039	174,139		182,927		1,752,923	1,818,871
Less cost of fuel and purchased power ^(a)	73,283		68,738
Gross Margin (non-GAAP) ^(a)	$	109,644	$	104,817
Less cost of fuel and purchased power							64,460		73,283
Gross Margin (non-GAAP)							$	109,679	$	109,644




Three Months Ended March 31,	Electric Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)				Quantities Sold (MWh) ^(b)
	2020		2019		2020		2019		2020	2019
Colorado Electric	$	58,558	$	59,847	$	32,270	$	31,444	550,771	491,682
South Dakota Electric ^(a)	71,611		79,041		55,624		56,308		685,224	845,001
Wyoming Electric	43,970		44,039		21,785		21,892		516,928	482,188
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold	$	174,139	$	182,927	$	109,679	$	109,644	1,752,923	1,818,871

________________

(a)

~~Due to changes to our segment performance measure, Fuel and purchased power was recast for the three months ended March 31, 2018, which resulted in a change of $1.6 million. The impact to Fuel~~Revenue and purchased power for the three months ended March 31, 2020, as well as associated quantities, for certain wholesale contracts have been presented on a net basis. Amounts for the three months ended March 31, 2019 ~~was $8.7 million. There~~ were ~~corresponding changes~~presented on a gross basis and, due to their immaterial nature, were not revised. This presentation change has no impact on Gross ~~margin for each period.~~margin.


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



	Three Months Ended March 31,
Quantities Generated and Purchased (MWh)	2020	2019

Coal-fired	547,829	585,295
Natural Gas and Oil	167,744	124,657
Wind	73,550	55,419
Total Generated	789,123	765,371
Purchased ^(a)	963,800	1,053,500
Total Generated and Purchased	1,752,923	1,818,871

Table of Contents



	Three Months Ended March 31,
Quantities Generated and Purchased (MWh)	2020	2019
Generated:
Colorado Electric	94,051	100,530
South Dakota Electric	472,966	457,369
Wyoming Electric	222,106	207,472
Total Generated	789,123	765,371
Purchased:
Colorado Electric	456,720	391,152
South Dakota Electric ^(a)	212,258	387,632
Wyoming Electric	294,822	274,716
Total Purchased	963,800	1,053,500

Total Generated and Purchased	1,752,923	1,818,871

________________


(a)	Purchased power quantities for the three months ended March 31, 2020, for certain wholesale contracts have been presented on a net basis. Amounts for the three months ended March 31, 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.



	Three Months Ended March 31,
	2020				2019
Heating Degree Days	Actual	Variance from Normal		Actual Variance to Prior Year	Actual	Variance from Normal

Colorado Electric	2,456	(7	)%	(4)%	2,549	(4	)%
South Dakota Electric	3,111	(3	)%	(21)%	3,916	22	%
Wyoming Electric	2,999	(1	)%	(6)%	3,198	—	%
Combined^(a)	2,789	(4	)%	(11)%	3,147	7	%

____________________


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



	Three Months Ended March 31,
Contracted Power Plant Fleet Availability ^(a)	2020		2019
Coal-fired plants	90.8	%	96.2	%
Natural gas-fired plants and Other plants^(b)	83.5	%	90.7	%
Wind	99.0	%	96.8	%
Total Availability	87.1	%	92.9	%

Wind Capacity Factor	45.6	%	42.6	%

____________________


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


(b)	2020 included an unplanned outage at Pueblo Airport Generation.

Table of Contents

Gas Utilities



	Three Months Ended March 31,
	2020		2019		Variance
	(in thousands)
Revenue:
Natural gas - regulated	$	335,897	$	383,875	$	(47,978	)
Other - non-regulated services	24,876		27,205		(2,329		)
Total revenue	360,773		411,080		(50,307		)

Cost of sales:
Natural gas - regulated	153,999		201,050		(47,051		)
Other - non-regulated services	1,363		6,229		(4,866		)
Total cost of sales	155,362		207,279		(51,917		)

Gross margin (non-GAAP)	205,411		203,801		1,610

Operations and maintenance	77,293		77,938		(645		)
Depreciation and amortization	25,221		22,549		2,672
Total operating expenses	102,514		100,487		2,027

Adjusted operating income	$	102,897	$	103,314	$	(417	)

Results of Operations for the Gas Utilities for the Three Months Ended March 31, 2020 Compared to the Three Months Ended March 31, 2019:

Gross margin for the three months ended March 31, 2020 increased as a result of:



	(in millions)
New rates	$	5.1
Prior year amortization of excess deferred income taxes	3.2
Customer growth - distribution	1.5
Increased mark-to-market on non-utility natural gas commodity contracts	0.9
Non-utility - Gas supply services	0.8
Weather	(10.4		)
Decreased transportation and transmission	(0.7		)
Other	1.2
Total increase in Gross margin (non-GAAP)	$	1.6

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

Table of Contents

Operating Statistics




	Gas Revenue (in thousands)						Gross Margin (non-GAAP) (in thousands)						Gas Utilities Quantities Sold & Transported (Dth)
	Three Months Ended March 31,						Three Months Ended March 31,						Three Months Ended March 31,
	2020			2019			2020			2019			2020	2019

Residential	$	207,231		$	241,129		$	103,121		$	105,057		28,230,795	32,838,018
Commercial	80,236			96,139			33,519			35,158			12,834,803	14,990,848
Industrial	5,200			6,014			2,043			2,017			1,061,052	1,182,527
Other	(1,242		)	(4,354		)	(1,242		)	(4,354		)	—	—
Total Distribution	291,425			338,928			137,441			137,878			42,126,650	49,011,393

Transportation and Transmission	44,472			44,947			44,457			44,947			45,055,507	46,316,160

Total Regulated	335,897			383,875			181,898			182,825			87,182,157	95,327,553

Non-regulated Services	24,876			27,205			23,513			20,976

Total Gas Revenue & Gross Margin (non-GAAP)	$	360,773		$	411,080		$	205,411		$	203,801

Electric Revenue (in thousands) Gross Margin (non-GAAP) (in thousands)
Quantities Sold (MWh) ^(a)
Three Months Ended March 31, 2019 2018 2019 2018 2019 2018
Colorado Electric ^(b)
$ 59,847
$ 58,353
$ 31,444
$ 31,746
491,682
487,000
South Dakota Electric 79,041
73,815
56,308
51,376
845,001
828,177
Wyoming Electric 44,039
41,387
21,892
21,695
482,188
462,862
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold $ 182,927
$ 173,555
$ 109,644
$ 104,817
1,818,871
1,778,039


~~(a)~~	~~Total MWh for 2019 includes Other Uses, Losses or Generation, net, which are approximately 5%, 5%, and 6% for Colorado Electric, South Dakota Electric, and Wyoming Electric, respectively.~~


~~(b)~~	Due to changes to our segment performance measure, Gross margin was recast for the three months ended March 31, 2018, which resulted in a change of ($1.6) million. The impact to Gross margin for the three months ended March 31, 2019 was ($8.7) million.

Three Months Ended
March 31,
Quantities Generated and Purchased (MWh) 2019 2018

Coal-fired 585,295
595,600
Natural Gas and Oil 124,657
41,323
Wind 55,419
73,981
Total Generated 765,371
710,904
Purchased 1,053,500
1,067,135
Total Generated and Purchased 1,818,871
1,778,039

Three Months Ended
March 31,
Quantities Generated and Purchased (MWh) 2019 2018
Generated:
Colorado Electric 100,530
92,048
South Dakota Electric 457,369
412,194
Wyoming Electric 207,472
206,662
Total Generated 765,371
710,904
Purchased:
Colorado Electric 391,152
394,952
South Dakota Electric 387,632
415,983
Wyoming Electric 274,716
256,200
Total Purchased 1,053,500
1,067,135

Total Generated and Purchased 1,818,871
1,778,039

Three Months Ended March 31,
2019 2018
Heating Degree Days Actual
Variance from
Normal
Actual Variance to Prior Year Actual
Variance from
Normal

Colorado Electric 2,549
(4 )% 6% 2,406
(9 )%
South Dakota Electric 3,916
22 % 6% 3,699
15 %
Wyoming Electric 3,198
— % 7% 2,984
(7 )%
Combined^(a)
3,147
7 % 6% 2,964
1 %

~~__________~~


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

Electric Utilities Power Plant Availability Three Months Ended March 31,
2019 2018
Coal-fired plants 96.2 % 95.0 %
Natural gas-fired plants and Other plants 90.7 % 96.5 %
Wind 96.8 % 97.1 %
Total availability 92.9 % 96.1 %

Wind capacity factor 42.6 % 50.4 %

~~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 of this Quarterly Report on Form 10-Q and Part I, Items 1 and 2 and Part II, Item 8 of our 2018 Annual Report on Form 10-K filed with the SEC.

~~Gas Utilities~~

Three Months Ended March 31,
2019 2018 Variance
(in thousands)
Revenue:
Natural gas - regulated $ 383,875
$ 370,268
$ 13,607
Other - non-regulated services 27,205
27,076
129
Total revenue 411,080
397,344
13,736

Cost of sales:
Natural gas - regulated 201,050
205,084
(4,034 )
Other - non-regulated services 6,229
4,601
1,628
Total cost of sales 207,279
209,685
(2,406 )

Gross margin (non-GAAP) 203,801
187,659
16,142

Operations and maintenance 77,938
70,906
7,032
Depreciation and amortization 22,549
21,310
1,239
Total operating expenses 100,487
92,216
8,271

Adjusted operating income $ 103,314
$ 95,443
$ 7,871

~~Results of Operations for the Gas Utilities for the Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2018:~~

~~Gross margin~~ ~~for the three months ended March 31, 2019 increased as a result of:~~

(in millions)
New rates $ 8.9
Weather ^(a)
5.2
Customer growth - distribution 1.8
Transport and transmission 1.7
Other 0.9
Excess deferred taxes returned to customers (2.4 )
Total increase in Gross margin (non-GAAP) $ 16.1

~~(a) Heating degree days at the Gas Utilities for the three months ended March 31, 2019 were 11% higher than normal compared to 2% higher than normal in the same period in the prior year.~~

~~Operations and maintenance~~ increased primarily due to $3.3 million of higher outside services expenses and $2.3 million of higher employee costs driven by labor, benefits and additional headcount. Various other expenses comprise the remainder of the increase compared to the same period in the prior year.

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

~~Operating Statistics~~

Gas Revenue (in thousands)
Gross Margin(non-GAAP)(in thousands)
Gas Utilities Quantities Sold & Transported (Dth)
Three Months Ended
March 31, Three Months Ended
March 31, Three Months Ended
March 31,
2019 2018 2019 2018 2019 2018

Residential $ 241,129
$ 234,751
$ 105,057
$ 96,777
32,838,018
30,096,237
Commercial 96,139
95,005
35,158
32,203
14,990,848
13,949,121
Industrial 6,014
5,982
2,017
1,674
1,182,527
1,183,617
Other ^(a)
(4,354 ) (7,531 ) (4,354 ) (7,531 ) —
—
Total Distribution 338,928
328,207
137,878
123,123
49,011,393
45,228,975

Transportation and Transmission 44,947
42,061
44,947
42,061
46,316,160
44,733,475

Total Regulated 383,875
370,268
182,825
165,184
95,327,553
89,962,450

Non-regulated Services 27,205
27,076
20,976
22,475

Total Gas Revenue & Gross Margin (non-GAAP) $ 411,080
$ 397,344
$ 203,801
$ 187,659


~~(a)~~	~~Includes~~ ~~reserve to revenue to reflect the reduction of the lower federal income tax rate from the TCJA on our existing rate tariffs.~~

Revenue (in thousands)
Gross Margin (non-GAAP)(in thousands)

Gas Utilities Quantities Sold & Transported (Dth)

Three Months Ended
March 31, Three Months Ended
March 31, Three Months Ended
March 31,
2019 2018 2019 2018 2019 2018

Arkansas $ 79,391
$ 70,388
$ 44,282
$ 35,917
12,424,196
11,878,626
Colorado 76,471
71,398
37,600
33,145
13,176,925
11,703,351
Iowa 65,641
67,884
23,050
22,426
15,663,687
15,502,989
Kansas 41,217
42,381
18,119
17,897
10,443,270
10,297,328
Nebraska 108,797
106,761
56,073
53,860
28,999,018
27,987,224
Wyoming 39,563
38,532
24,677
24,414
14,620,457
12,592,932
Total Gas Revenue & Gross Margin (non-GAAP) $ 411,080
$ 397,344
$ 203,801
$ 187,659
95,327,553
89,962,450




	Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)				Gas Utilities Quantities Sold & Transported (Dth)
	Three Months Ended March 31,				Three Months Ended March 31,				Three Months Ended March 31,
	2020		2019		2020		2019		2020	2019

Arkansas Gas	$	74,845	$	79,391	$	48,855	$	44,282	10,962,948	12,424,196
Colorado Gas	72,606		76,471		38,006		37,600		13,096,405	13,176,925
Iowa Gas	54,824		65,641		21,328		23,050		14,280,273	15,663,687
Kansas Gas	33,494		41,217		18,603		18,119		9,914,858	10,443,270
Nebraska Gas	83,666		108,797		51,666		56,073		26,509,036	28,999,018
Wyoming Gas	41,338		39,563		26,953		24,677		12,418,637	14,620,457
Total Gas Revenue & Gross Margin (non-GAAP)	$	360,773	$	411,080	$	205,411	$	203,801	87,182,157	95,327,553

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

Table of Contents

Three Months Ended March 31,
2019 2018
Heating Degree Days Actual
Variance
from Normal
Actual Variance to Prior Year Actual
Variance
from Normal
Arkansas ^(a)
2,101 —% 3% 2,048 (3)%
Colorado 3,030 3% 12% 2,704 (8)%
Iowa 3,830 14% 8% 3,531 5%
Kansas ^(a)
2,779 13% 13% 2,470 —%
Nebraska 3,483 15% 9% 3,207 6%
Wyoming 3,513 10% 8% 3,244 1%
Combined ^(b)
3,449 11% 9% 3,159 2%




	Three Months Ended March 31,
	2020			2019
Heating Degree Days:	Actual	Variance from Normal	Actual Variance to Prior Year	Actual	Variance from Normal
Arkansas Gas ^(a)	1,659	(21)%	(21)%	2,101	—%
Colorado Gas	2,829	(3)%	(7)%	3,030	3%
Iowa Gas	3,181	(6)%	(17)%	3,830	14%
Kansas Gas ^(a)	2,304	(7)%	(17)%	2,779	13%
Nebraska Gas	2,835	(7)%	(19)%	3,483	15%
Wyoming Gas	3,217	1%	(8)%	3,513	10%
Combined Gas ^(b)	2,918	(6)%	(15)%	3,449	11%

__________


(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 ~~of this Quarterly Report on Form 10-Q~~ and Part I, Items 1 and 2 and Part II, Item 8 of our ~~2018~~2019 Annual Report on Form 10-K filed with the SEC.

Power Generation

Three Months Ended March 31,
2019 2018 Variance
(in thousands)
Revenue $ 25,245
$ 23,939
$ 1,306

Operations and maintenance 8,688
8,127
561
Depreciation and amortization 4,590
4,036
554
Total operating expense 13,278
12,163
1,115

Adjusted operating income ^(a)
$ 11,967
$ 11,776
$ 191

~~________________~~


~~(a)~~	Due to changes to our segment performance measure, Adjusted operating income was recast for the three months ended March 31, 2018, which resulted in a change of ($1.6) million. The impact to Adjusted operating income for the three months ended March 31, 2019 was $0.7 million. There was no impact on our consolidated Operating income.



	Three Months Ended March 31,
	2020		2019		Variance
	(in thousands)
Revenue	$	25,966	$	25,245	$	721

Fuel expense	2,285		2,626		(341		)
Operations and maintenance	6,997		6,062		935
Depreciation and amortization	5,335		4,590		745
Total operating expense	14,617		13,278		1,339

Adjusted operating income	$	11,349	$	11,967	$	(618	)

Results of Operations for Power Generation for the Three Months Ended March 31, ~~2019~~2020 Compared to the Three Months Ended March 31, ~~2018:~~ 2019:

Revenue increased in the current year driven by an increase in MWh sold due to ~~increased~~new wind ~~megawatt hours sold~~assets and ~~higher power purchase agreement prices.~~additional Black Hills Colorado IPP fired-engine hours. Operating expenses increased in the current year primarily due to higher ~~employee costs~~maintenance expense and ~~higher~~ depreciation from new wind assets.

The following table summarizes MWh for our Power Generation segment:


	Three Months Ended March 31,		Three Months Ended March 31,
	2019	2018	2020	2019
Quantities Sold, Generated and Purchased (MWh) ^(a)
Sold
Black Hills Colorado IPP ^(b)	205,973	232,375
Black Hills Wyoming ^(c)	164,049	165,601
Black Hills Electric Generation ^(d)	12,864	—
Black Hills Colorado IPP			265,225	205,973
Black Hills Wyoming ^(b)			156,352	164,049
Black Hills Electric Generation			97,279	33,753
Total Sold	382,886	397,976	518,856	403,775

Generated
Black Hills Colorado IPP ^(b)	205,973	232,375
Black Hills Wyoming ^(c)	132,593	134,029
Black Hills Electric Generation ^(d)	12,864	—
Black Hills Colorado IPP			265,225	205,973
Black Hills Wyoming ^(b)			126,485	132,593
Black Hills Electric Generation			97,279	33,753
Total Generated	351,430	366,404	488,989	372,319

Purchased
Black Hills Wyoming ^(c)(b)	25,579	31,917	29,856	25,579
Total Purchased	25,579	31,917	29,856	25,579

____________


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


(b)	~~Decrease from the prior year is a result of the impact of Colorado Electric’s wind generation replacing natural-gas generation.~~


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


~~(d)~~	~~Increase from prior year is driven primarily by Black Hills Electric Generation’s acquisition of a 50% ownership interest in Busch Ranch I on December 11, 2018.~~

~~The following table provides certain operating statistics for our plants within the Power Generation segment:~~


	Three Months Ended March 31,				Three Months Ended March 31,
Contracted Power Plant Fleet Availability ^(a)					2020		2019
	2019		2018
Contracted power plant fleet availability:
Coal-fired plant(b)	94.8	%	94.7	%	89.3	%	94.8	%
Natural gas-fired plants	95.6	%	99.5	%	99.5	%	95.6	%
Wind ^(a)	90.4	%	N/A		99.3	%	90.4	%
Total availability	94.1	%	98.3	%
Total Availability					97.8	%	94.1	%

Wind Capacity Factor					30.4	%	28.2	%

~~____________~~____________________


(a)	~~Black Hills Electric Generation acquired~~Availability and Wind Capacity Factor are calculated using a ~~50% ownership interest in Busch Ranch I~~weighted average based on ~~December 11, 2018.~~capacity of our generating fleet.


(b)	2020 included a planned outage at Wygen I.

Table of Contents

Mining


	Three Months Ended March 31,							Three Months Ended March 31,
	2019		2018		Variance			2020		2019		Variance
	(in thousands)							(in thousands)
Revenue	$	16,429	$	17,128	$	(699	)	$	15,205	$	16,429	$	(1,224	)

Operations and maintenance	9,913		10,922		(1,009		)	9,826		9,913		(87		)
Depreciation, depletion and amortization	2,179		1,935		244			2,250		2,179		71
Total operating expenses	12,092		12,857		(765		)	12,076		12,092		(16		)

Adjusted operating income	$	4,337	$	4,271	$	66		$	3,129	$	4,337	$	(1,208	)

Results of Operations for Mining for the Three Months Ended March 31, 2020 Compared to the Three Months Ended March 31, 2019:

Current year revenue decreased due to 10% fewer tons sold driven primarily by decreased demand at the Wyodak Plant and timing of planned spring outages at our coal-fired generation facilities partially offset by an increase 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 March 31,
2019 2018
Tons of coal sold 997
1,078
Cubic yards of overburden moved 1,994
2,022

Revenue per ton $ 15.87
$ 15.89

~~Results of Operations for Mining for the Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2018:~~

Current year revenue decreased due to 8% fewer tons sold driven by a planned outage at the Wyodak power plant. Operating expenses decreased primarily due to lower royalties and production taxes on decreased revenues, and lower major maintenance expenses.



	Three Months Ended March 31,
	2020		2019
Tons of coal sold	896		997
Cubic yards of overburden moved	2,267		1,994

Revenue per ton	$	16.08	$	15.87

Corporate and Other

Three Months Ended March 31,
2,019 2.018 Variance
(in thousands)
Adjusted operating (loss) ^(a)
$ (507 ) $ (1,696 ) $ 1,189



	Three Months Ended March 31,
	2020		2019			Variance
	(in thousands)
Adjusted operating income (loss)	$	160	$	(507	)	$	667

~~________________~~


~~(a)~~	Due to changes to our segment performance measure, Adjusted operating loss was recast for the three months ended March 31, 2018, which results in a change of ($0.1) million. The impact to Adjusted operating loss for the three months ended March 31, 2019 was $4.7 million. There was no impact on our consolidated Operating income.

~~Results~~

Interest Expense, Impairment of ~~Operations for Corporate~~Investment, Other Income (Expense) and Income Tax (Expense)



	Three Months Ended March 31,
	2020			2019			Variance
	(in thousands)
Interest expense, net	$	(35,453	)	$	(34,717	)	$	(736	)
Impairment of investment	(6,859		)	—			$	(6,859	)
Other income (expense), net	2,353			(789		)	$	3,142
Income tax (expense)	(16,002		)	(17,263		)	$	1,261

Consolidated Interest expense, Impairment of investment, Other income (expense) and Income tax (expense) for the Three Months Ended March 31, ~~2019~~2020 Compared to the Three Months Ended March 31, ~~2018:~~2019.

Impairment of Investment

For the three months ended March 31, 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~~increase in ~~Adjusted operating loss was primarily due to prior year expenses related to the oil and gas segment that were not reclassified to discontinued operations.~~

~~Consolidated interest expense,~~ Other income ~~(expense) and Income tax (expense) benefit~~

~~Interest Expense~~

~~Interest expense, net~~ for the three months ended March 31, ~~2019 was $35 million~~2020, compared to ~~$35 million for~~ the same period in ~~2018.~~the prior year was primarily due to reduced costs for our non-qualified benefit plan which are driven by market performance on plan assets.

Income Tax (Expense)

~~Other (Expense) Income~~

~~Other (expense) income, net for~~For the three months ended March 31, ~~2019~~2020, the effective tax rate was ~~$(0.8) million~~14.1% compared to ~~$(0.1) million~~13.9% for the same period in ~~2018.~~

~~Income Tax Benefit (Expense)~~

~~Income~~2019. The higher effective tax ~~benefit (expense), net for the three months ended March 31, 2019 was $(17) million compared to $26 million for the same period in 2018. The increase in tax expense was~~rate is primarily due ~~to:~~to a 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.


•	~~A prior year $49 million tax benefit resulting fromlegal entity restructuring partially offset by:~~


◦	~~A prior year $2.3 million income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes; and~~


◦	A current year $3.4 million increase in income tax benefit from forecasted federal production tax credits and state investment tax credits as well as $1.8 million of income tax benefit for deferred tax amortization related to tax reform (which is offset by reduced revenue at our utilities).

Critical Accounting Policies Involving Significant Accounting Estimates

There have been no material changes in our critical accounting estimates from those reported in our ~~2018~~2019 Annual Report on Form 10-K filed with the ~~SEC.~~SEC except for Pension and Other Postretirement Benefits provided below. We continue to closely monitor the rapidly evolving and uncertain impact of COVID-19 on our critical accounting estimates including, but not limited to, collectibility of customer receivables, recoverability of regulatory assets, impairment risk of goodwill and long-lived assets, valuation of pension assets and liabilities, and contingent liabilities. For more information on our critical accounting estimates, see Part II, Item 7 of our ~~2018~~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

~~OVERVIEW~~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 Results of Operations section above.

Our Company requires significant cash to support and grow our business. Our predominant source of cash is supplied by our operations and supplemented with corporate financings. This cash is used for, among other things, working capital, capital expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations, and redemption of outstanding debt and equity securities when required or financially appropriate. As discussed in more detail below under income taxes, we expect an increase in working capital requirements as a result of complying with the TCJA and the impact of providing TCJA benefits to customers.

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

We believe that our cash on hand, operating cash flows, existing borrowing capacity and ability to complete new debt and equity financings, taken in their entirety, provide sufficient capital resources to fund our ongoing operating requirements, debt maturities, anticipated dividends, and anticipated capital expenditures discussed in this section.

~~Significant Factors Affecting Liquidity~~

Although we believe we have sufficient resources to fund our cash requirements, there are many factors with the potential to influence our cash flow position, including seasonality, commodity prices, significant capital projects and acquisitions, requirements imposed by state and federal agencies, and economic market conditions. We have implemented risk mitigation programs, where possible, to stabilize cash flow; however, the potential for unforeseen events affecting cash needs will continue to exist.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 March 31, ~~2019,~~2020, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts. For the three months ended March 31, 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.

~~Income Tax~~

~~The TCJA required revaluation of federal deferred tax assets and liabilities using the new lower corporate tax rate of 21%.~~

~~We have reached agreements with regulators in six states and are working with regulators in our seventh state, as well as~~

FERC regarding returning benefits to customers. Our working capital requirements increased as a result of complying with the TCJA and providing the benefits of the TCJA to customers. This will negatively impact our cash flows by approximately $40 million to $45 million per year for each of the next several years.

Cash Flow Activities

The following table summarizes our cash flows for the three months ended March 31, 2020 (in thousands):


Cash provided by (used in):	2019			2018			Variance			2020			2019			Variance
Operating activities	$	175,893		$	169,875		$	6,018		$	191,969		$	175,893		$	16,076
Investing activities	$	(145,027	)	$	(73,554	)	$	(71,473	)	$	(173,084	)	$	(145,027	)	$	(28,057	)
Financing activities	$	(39,292	)	$	(80,656	)	$	41,364		$	25,621		$	(39,292	)	$	64,913

Table of Contents

~~Year-to-Date 2019~~Three Months Ended March 31, 2020 Compared to ~~Year-to-Date 2018~~Three Months Ended March 31, 2019

Operating Activities

Net cash provided by operating activities was ~~$176~~$192 million for the three months ended March 31, ~~2019,~~2020, compared to net cash provided by operating activities of ~~$170~~$176 million for the same period in ~~2018~~2019 for an increase of $6$16 million. The variance was primarily attributable to:

Cash earnings ~~(income from continuing operations~~(net income plus non-cash adjustments) were ~~$18~~$4 million ~~higher~~lower for the three months ended March 31, ~~2019~~2020 compared to the same period in the prior ~~year;~~year primarily driven by lower operating income at the Electric Utilities and Mining segments;

Net cash ~~outflows~~inflows from changes in operating assets and liabilities were ~~$15~~$5.0 million for the three months ended March 31, ~~2019,~~2020, compared to net cash outflows of $1$15 million in the same period in the prior year. This ~~$14~~$20 million increase was primarily due to:


◦	Cash inflows increased by ~~approximately $7~~$14 million primarily as a result of decreases in natural gas in storage and higher collections of accounts receivable partially offset by ~~higher~~increased materials ~~inventory~~ and ~~natural gas in storage for the three months ended March 31, 2019 compared to the same period in the prior year;~~supplies purchases;


◦	Cash outflows ~~decreased~~increased by ~~approximately $29~~$1.6 million as a result of ~~increases~~decreases in accounts payable and accrued liabilities primarily driven by higher employee costs and other working capital ~~requirements; and~~requirements partially offset by lower interest paid;


◦	Cash inflows ~~decreased~~increased by ~~approximately $53~~$11 million primarily as a result of changes in our current regulatory assets ~~and liabilities~~ driven by ~~differences in~~the timing of recovery from fuel cost ~~adjustments~~adjustments; and ~~revenue reserved in the prior year~~


◦	Net cash outflows increased by $2.9 million from other operating activities primarily due to ~~the TCJA tax rate change that has subsequently been returned to customers.~~higher employee benefits costs and outside services.

Investing Activities

Net cash used in investing activities was ~~$145~~$173 million for the three months ended March 31, ~~2019,~~2020, compared to net cash used in investing activities of ~~$74~~$145 million for the same period in ~~2018~~2019 for a variance of ~~$71~~$28 million. The variance was primarily attributable to:

Capital expenditures of ~~approximately $144~~$172 million for the three months ended March 31, ~~2019~~2020 compared to ~~$70~~$144 million for the same period in the prior year. Higher current year expenditures are driven by higher programmatic safety, reliability and integrity spending at our Gas Utilities and Electric Utilities segments and the ~~Busch Ranch II~~Corriedale wind project at our ~~Power Generation segment and increased programmatic spending at our Gas and~~ Electric ~~Utilities; and~~

A $24 million investment made in the prior year partially offset by a $20 million change in net cash provided by investing activities from discontinued operations primarily due to the prior year sale of assets held for sale.Utilities segment.

Financing Activities

Net cash ~~used in~~provided by financing activities for the three months ended March 31, ~~2019~~2020 was ~~$39~~$26 million, compared to ~~$81~~$39 million of net cash used in financing activities for the same period in ~~2018 for a variance~~2019, an increase of ~~$41 million. This variance is primarily~~$65 million due ~~to:~~to the following:

~~Lower~~Increase of $79 million in common stock issued driven by current year net proceeds of $99 million through an underwritten registered transaction as compared to prior year net proceeds of $20 million issued through our ATM;

$12 million of higher repayments of short-term ~~borrowings of $26 million;~~

~~Current year issuance of common stock for net proceeds of approximately $20 million through our ATM equity offering program;~~and long-term debt; and

$~~4.9~~2.6 million of higher current year dividend payments.

Dividends

Dividends paid on our common stock totaled ~~$30~~$33 million for the three months ended March 31, ~~2019,~~2020, or ~~$0.505~~$0.535 per share per quarter. On April ~~29, 2019,~~27, 2020, our board of directors declared a quarterly dividend of ~~$0.505~~$0.535 per share payable June 1, ~~2019,~~2020, equivalent to an annual dividend of ~~$2.02~~$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.

~~Debt~~

Financing Transactions and Short-Term Liquidity

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

Revolving Credit Facility and CP Program

On July 30, 2018, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 30, 2023 with two one-year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. See Note 8 for more information.

~~We have a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the~~Our Revolving Credit Facility and ~~the~~ CP Program ~~either individually or in the aggregate, cannot exceed $750 million. See Note 8 for more information.~~

~~Our Revolving Credit Facility~~ had the following borrowings, outstanding letters of credit, and available capacity (in millions):


		Current		Revolver Borrowings at		CP Program Borrowings at		Letters of Credit at		Available Capacity at			Current		Revolver Borrowings at		CP Program Borrowings at		Letters of Credit at		Available Capacity at
Credit Facility	Expiration	Capacity		March 31, 2019				March 31, 2019				Expiration	Capacity		March 31, 2020		March 31, 2020		March 31, 2020
Revolving Credit Facility	July 30, 2023	$	750	$	—	$	165	$	14	$	571
Revolving Credit Facility and CP Program												July 30, 2023	$	750	$	165	$	154	$	17	$	414

The weighted average interest ~~rate~~rates on CP Program and Revolving Credit Facility borrowings at March 31, ~~2019 was 2.71%.~~2020 were 1.74% and 1.92%, respectively. CP Program and Revolving Credit Facility ~~and CP Program financing~~borrowing activity for the three months ended March 31, ~~2019~~2020 was (dollars in millions):

For the Three Months Ended March 31, 2019
Maximum amount outstanding - commercial paper (based on daily outstanding balances) $ 237
Maximum amount outstanding - revolving credit facility (based on daily outstanding balances) $ —
Average amount outstanding - commercial paper (based on daily outstanding balances) $ 172
Average amount outstanding - revolving credit facility (based on daily outstanding balances) $ —
Weighted average interest rates - commercial paper 2.70 %
Weighted average interest rates - revolving credit facility — %



	For the Three Months Ended March 31, 2020
Maximum amount outstanding - CP Program (based on daily outstanding balances)	$	366
Maximum amount outstanding - Revolving Credit Facility (based on daily outstanding balances)	$	165
Average amount outstanding - CP Program (based on daily outstanding balances)	$	288
Average amount outstanding - Revolving Credit Facility (based on daily outstanding balances)	$	150
Weighted average interest rates - CP Program	1.84		%
Weighted average interest rates - Revolving Credit Facility	1.92		%

Covenant Requirements

The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on certain liens, restrictions on certain transactions, and maintenance of a certain Consolidated Indebtedness to Capitalization Ratio. Under the Revolving Credit Facility, our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness (which includes letters of credit and certain guarantees issued), by (ii) Capital, which is Consolidated Indebtedness plus Consolidated Net Worth (which excludes noncontrolling interests 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. We were in compliance with these covenants as of March 31, ~~2019.~~2020. See Note 7 of the Notes to Condensed Consolidated Financial Statements for more information.

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

~~Financing Activities~~

~~Financing activities for the three months ended March 31, 2019 consisted of the following:~~

We issued a total of 280,497 shares of common stock under the ATM equity offering program for $20 million, net of $0.2 million in commissions. As of March 31, 2019, there were no shares that were sold, but not settled.

~~Short-term borrowings from our CP Program.~~

~~Future Financing Plans~~

~~Evaluating refinancing options for our $200 million senior notes due July 15, 2020 and the $300 million Corporate term loan due July 30, 2020.~~

~~Continue our ATM equity offering program to issue an additional $60 to $80 million of common stock for the remainder of 2019.~~

~~Dividend Restrictions~~

As a utility holding company which owns several regulated utilities, we are subject to various regulations that could influence our liquidity. Our utilities in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming have regulatory agreements in which they cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40% of their total capitalization; and neither Black Hills Utility Holdings nor its subsidiaries can extend credit to the Company except in the ordinary course of business and upon reasonable terms consistent with market terms. The use of our utility assets as collateral generally requires the prior approval of the state regulators in the state in which the utility assets are located. Additionally, our utility subsidiaries may generally be limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may have further restrictions under the Federal Power Act.

As a result of our holding company structure, our right as a common shareholder to receive assets of any of our direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities, and guarantee holders. See Note 16 for more information.

Our credit facilities and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be deemed to have occurred if we did not comply with certain financial or other covenants.

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 March 31, ~~2019,~~2020, we were in compliance with these covenants.

Financing Activities

Financing activities for the three months ended March 31, 2020 consisted of the following:

Short-term borrowings from our Revolving Credit Facility and CP Program.

~~There have been no other material changes~~Table of Contents

Future Financing Plans

We anticipate the following financing activities in 2020:

Renew our ~~financing transactions~~shelf registration and ATM;

Refinance a portion of short-term ~~liquidity from those reported in Item 7 of~~borrowings held through the Revolving Credit Facility and CP Program to long-term debt; and

Continue to assess debt and equity needs to support our ~~2018~~ ~~Annual Report on Form 10-K filed with the SEC.~~capital expenditure plan.

Credit Ratings

Financing for operational needs and capital expenditure requirements not satisfied by operating cash flows depends upon the cost and availability of external funds through both short and long-term financing. The inability to raise capital on favorable terms could negatively affect our ability to maintain or expand our businesses. Access to funds is dependent upon factors such as general economic and capital market conditions, regulatory authorizations and policies, the Company’s credit ratings, cash flows from routine operations and the credit ratings of counterparties. After assessing the current operating performance, liquidity and the credit ratings of the Company, management believes that the Company will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. BHC notes that credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.

The following table represents the credit ratings and outlook and risk profile of BHC at March 31, ~~2019:~~2020:



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

__________


(a)	On ~~February 28, 2019,~~April 10, 2020, S&P affirmed our BBB+ rating and maintained a Stable outlook.


(b)	On December ~~12, 2018,~~20, 2019, Moody’s affirmed our Baa2 rating and maintained a Stable outlook.


(c)	On ~~October 11, 2018,~~August 29, 2019, Fitch affirmed our BBB+ rating and maintained a Stable outlook.

The following table represents the credit ratings of South Dakota Electric at March 31, ~~2019:~~2020:



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

__________


(a)	On April ~~30, 2019,~~16, 2020, S&P affirmed A rating.


(b)	On December ~~12, 2018,~~20, 2019, Moody’s affirmed A1 rating.


(c)	On ~~October 11, 2018,~~August 29, 2019, Fitch affirmed A rating.

Capital Requirements

Capital Expenditures


	Actual		Planned										Actual		Planned
Capital Expenditures by Segment	Three Months Ended March 31, 2019 ^(a)		2019^(b)		2020		2021		2022		2023		Three Months Ended March 31, 2020 ^(a)		2020 ^(b)		2021		2022		2023		2024
(in millions)
Electric Utilities ^(c)	$	35	$	205	$	221	$	203	$	170	$	137	$	49	$	246	$	203	$	170	$	137	$	152
Gas Utilities ^(c)	58		464		323		289		277		274		113		391		309		285		316		293
Power Generation	28		84		9		8		10		4		5		7		9		11		6		6
Mining	4		8		7		11		10		7		1		8		12		9		9		9
Corporate and Other	7		16		22		8		5		7		5		17		22		11		12		10
	$	132	$	777	$	582	$	519	$	472	$	429	$	173	$	669	$	555	$	486	$	480	$	470

__________

(a) Expenditures for the three months ended March 31, ~~2019~~2020 include the impact of accruals for property, plant and equipment.

(b) Includes actual capital expenditures for the three months ended March 31, ~~2019.~~

~~(c) Planned capital expenditures increased for 2019 through 2023 primarily due to increased programmatic integrity spending.~~2020.

We are monitoring supply chains, including lead times for key materials and supplies, availability of resources, and status of large capital projects. To date, there have been limited impacts to supply chains including availability of supplies and materials and lead times and capital projects are ongoing without material disruption to schedules. Our third party resources continue to ~~evaluate~~support our business plans without disruption. Contingency plans are ongoing due to the impacts of COVID-19, including the potential ~~future acquisitions and other growth opportunities when they arise. As~~for rescheduling projects. We currently do not anticipate a ~~result,~~significant impact on our capital ~~expenditures may vary significantly from the estimates identified above.~~investment plan for 2020.

Contractual Obligations

There have been no significant changes in contractual obligations from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our ~~2018~~2019 Annual Report on Form ~~10-K.~~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.

~~Guarantees~~Off-Balance Sheet Commitments

There have been no significant changes to ~~guarantees~~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 207 of the Notes to ~~the~~Condensed Consolidated Financial Statements in ~~our 2018 Annual~~this Quarterly Report on Form ~~10-K.~~10-Q.

New Accounting Pronouncements

Other than the pronouncements reported in our ~~2018~~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.

FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements as defined by the SEC. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts” and similar expressions, and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 2 - Management’s Discussion & Analysis of Financial Condition and Results of Operations.

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

Any forward-looking statement contained in this document speaks only as of the date the statement was made. The Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement was made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, such as the COVID-19 pandemic, 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 ~~2018~~2019 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our ~~2018~~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

~~Utilities~~

Our utility customers are exposed to natural gas price volatility. Therefore, as allowed or required by state utility commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, optionsInformation regarding our quantitative and ~~basis swaps to reduce our customers’ underlying exposure to these fluctuations. We also reduce the commodity price~~qualitative disclosures about market risk is disclosed in ~~the unregulated area~~Item 7A of our ~~business by using over-the-counter and exchange traded options and swaps with counterparties in anticipation~~Annual Report on Form 10-K. See Note 9 of ~~forecasted purchases and/or sales. The fair value of our utilities’ derivative contracts is summarized below (in thousands) as of:~~the Notes to Condensed Consolidated Financial Statements for updates to market risks during the three months ended March 31, 2020.

March 31, 2019 December 31, 2018 March 31, 2018
Net derivative (liabilities) assets $ (2,203 ) $ (2,214 ) $ (6,002 )
Cash collateral offset in Derivatives 3,621
4,386
5,078
Cash collateral included in Other current assets 1,717
2,880
2,020
Net asset (liability) position $ 3,135
$ 5,052
$ 1,096

~~Financing Activities~~

From time-to-time, we have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations and anticipated debt refinancings. At March 31, 2019, December 31, 2018 and March 31, 2018, we had no outstanding interest rate swap agreements.

ITEM 4. CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of ~~1934)~~1934, as amended (the “Exchange Act”)) as of March 31, ~~2019.~~2020. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at March 31, ~~2019.~~2020.

Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the ~~Security~~ Exchange Act ~~of 1934, as amended,~~ is recorded, processed, summarized and reported, within the time periods specified in the ~~Commission’s~~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 March 31, ~~2019,~~2020, there have been no changes in our internal ~~control~~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.

~~BLACK HILLS CORPORATION~~

Table of Contents

~~Part II — Other Information~~

PART II. OTHER INFORMATION


ITEM 1.	~~Legal Proceedings~~LEGAL PROCEEDINGS

For information regarding legal proceedings, see Note 19 in Item 8 of our ~~2018~~2019 Annual Report on Form 10-K and Note 1316 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 1316 is incorporated by reference into this item.


ITEM 1A.	~~Risk Factors~~RISK FACTORS

There are no material changes to the risk factors previously disclosed in Item 1A of Part I in our ~~2018~~2019 Annual Report on Form 10-K filed with the ~~SEC.~~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.


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

~~There were no unregistered securities sold during~~We are responding to the global pandemic of COVID-19 by taking steps to mitigate the potential risks to us posed by its spread. We provide an essential service to our customers which means it is critical we keep our employees who operate our businesses healthy and minimize unnecessary exposure to the virus. We continue to execute our business continuity plan and have implemented a comprehensive set of actions for the health and safety of our customers, employees, business partners and the communities we serve. We have taken extra precautions for our employees who work in the field and for employees who continue to work in our facilities and we have implemented work from home policies where appropriate. We have implemented sequestration plans for employees critical to maintaining reliable service.

We have informed both our customers and regulators that disconnections for non-payment will be temporarily suspended. We have instituted measures to ensure our supply chain remains open to us. We continue to implement strong physical and cyber-security measures to ensure our systems remain functional to both serve our operational needs with a remote workforce and to provide uninterrupted service to our customers.

For the three months ended March 31, ~~2019.~~2020, the impacts of COVID-19 had a minimal financial impact on our business, operations and financial condition. In particular, we experienced minimal financial impacts to the following due to COVID-19:

Volatility in electricity and natural gas usage from our residential, commercial and industrial customers resulting in a minimal decrease in total demand;

Delayed payments from an isolated population of our commercial and industrial customers within hard-hit industries;

Minimal disruptions receiving the materials and supplies necessary to maintain operations and continue executing our capital investment plans as planned;

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 due to sequestration of mission critical and essential employees; and

Reduced training, travel and outside services related expenses.

Should the COVID-19 pandemic continue for a prolonged period, or impact the areas we serve more significantly than it has today, our business, operations and financial condition could be impacted in more significant ways. The continued spread of COVID-19 and efforts to contain the virus could have the following impacts, in addition to exacerbating the impacts described above:

Adversely impact our strategic business plans, growth strategy and capital investment plans;

Adversely impact electricity and natural gas demand from our customers, particularly from businesses, commercial and industrial customers;

Reduce the availability and productivity of our employees and third-party resources;

Cause us to experience an increase in costs as a result of our emergency measures;



•								Result in 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;

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

Table of Contents

Cause delays and disruptions in the supply chain resulting in disruptions in the commercial operation dates of certain projects impacting qualification criteria for certain tax credits and potential damages in our power purchase agreements;

Cause a 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;

Cause impairment of goodwill or long-lived assets;

Adversely impact our ability to develop, construct and operate facilities;

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

Cause a deterioration in our financial metrics or the business environment that adversely impacts our credit ratings;

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

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

Cause delays in our ability to change rates through regulatory proceedings; and

Cause other risks to 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 not experienced significant 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~~MINE SAFETY DISCLOSURES

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


~~ITEM 5.~~	~~Other Information~~

~~None.~~


ITEM 6.	~~Exhibits~~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).

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 18.1	Preferability letter from Deloitte & Touche LLP regarding change in pension accounting asset method.

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 pursuant 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.

Table of Contents

SIGNATURES

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

BLACK HILLS CORPORATION



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

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

Dated:	May ~~3, 2019~~5, 2020

5749



Three Months Ended March 31, 2018	Electric Utilities		Gas Utilities			Power Generation ^(a)		Mining		Inter-company Revenues ^(a)			Total
Customer Types:
Retail	$	147,057	$	341,394		$	—	$	16,557	$	(7,842	)	$	497,166
Transportation	—		41,669			—		—		(409		)	41,260
Wholesale	9,050		—			14,769		—		(13,049		)	10,770
Market - Off-System Sales	4,144		427			—		—		(2,522		)	2,049
Transmission/Other	13,071		12,670			—		—		(3,631		)	22,110
Revenue from contracts with customers	$	173,322	$	396,160		$	14,769	$	16,557	$	(27,453	)	$	573,355
Other Revenues	233		1,184		^(b)	9,170		571		(9,124		)	2,034
Total Revenues	$	173,555	$	397,344		$	23,939	$	17,128	$	(36,577	)	$	575,389

Timing of Revenue Recognition:
Services transferred at a point in time	$	—	$	—		$	—	$	16,557	$	(7,842	)	$	8,715
Services transferred over time	173,322		396,160			14,769		—		(19,611		)	564,640
Revenue from contracts with customers	$	173,322	$	396,160		$	14,769	$	16,557	$	(27,453	)	$	573,355



	Accounts		Unbilled		Less Allowance for			Accounts
March 31, 2019	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	45,764	$	31,075	$	(535	)	$	76,304
Gas Utilities	138,005		62,566		(4,008		)	196,563
Power Generation	3,167		—		—			3,167
Mining	2,791		—		—			2,791
Corporate	3,946		—		(169		)	3,777
Total	$	193,673	$	93,641	$	(4,712	)	$	282,602



	Income Statement Location	Three Months Ended March 31, 2019
Operating lease cost	Operations and maintenance	$	311
Finance lease cost:
Amortization of right-of-use asset	Depreciation, depletion and amortization	17
Interest on lease liabilities	Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	3
Total lease cost		$	331



	Three Months Ended March 31, 2019
Cash paid included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	246
Operating cash flows from finance lease	$	3
Financing cash flows from finance lease	$	15
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	2,328
Finance leases	$	—



	Operating Leases
2019	$	1,052
2020	464
2021	344
2022	224
2023	216
Thereafter	1,776
Total lease payments	$	4,076



	Income Statement Location	Three Months Ended March 31, 2019
Operating lease income	Revenue	$	638



	Operating Leases
2019 ^(a)	$	1,652
2020	2,010
2021	1,843
2022	1,793
2023	1,799
Thereafter	55,481
Total lease receivables	$	64,578



	(in millions)
Reduction in purchased power capacity charges	$	1.6
Off-system power marketing	1.3
Weather	0.6
Rider recovery	0.4
Residential customer growth	0.3
Other	0.6
Total increase in Gross margin (non-GAAP)	$	4.8




	Electric Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)				Quantities Sold (MWh) ^(a)
Three Months Ended March 31,	2019		2018		2019		2018		2019	2018
Colorado Electric ^(b)	$	59,847	$	58,353	$	31,444	$	31,746	491,682	487,000
South Dakota Electric	79,041		73,815		56,308		51,376		845,001	828,177
Wyoming Electric	44,039		41,387		21,892		21,695		482,188	462,862
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold	$	182,927	$	173,555	$	109,644	$	104,817	1,818,871	1,778,039



	(in millions)
New rates	$	8.9
Weather ^(a)	5.2
Customer growth - distribution	1.8
Transport and transmission	1.7
Other	0.9
Excess deferred taxes returned to customers	(2.4		)
Total increase in Gross margin (non-GAAP)	$	16.1



	Gas Revenue (in thousands)						Gross Margin(non-GAAP)(in thousands)						Gas Utilities Quantities Sold & Transported (Dth)
	Three Months Ended March 31,						Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2019			2018			2019	2018

Residential	$	241,129		$	234,751		$	105,057		$	96,777		32,838,018	30,096,237
Commercial	96,139			95,005			35,158			32,203			14,990,848	13,949,121
Industrial	6,014			5,982			2,017			1,674			1,182,527	1,183,617
Other ^(a)	(4,354		)	(7,531		)	(4,354		)	(7,531		)	—	—
Total Distribution	338,928			328,207			137,878			123,123			49,011,393	45,228,975

Transportation and Transmission	44,947			42,061			44,947			42,061			46,316,160	44,733,475

Total Regulated	383,875			370,268			182,825			165,184			95,327,553	89,962,450

Non-regulated Services	27,205			27,076			20,976			22,475

Total Gas Revenue & Gross Margin (non-GAAP)	$	411,080		$	397,344		$	203,801		$	187,659



	Revenue (in thousands)				Gross Margin (non-GAAP)(in thousands)				Gas Utilities Quantities Sold & Transported (Dth)
	Three Months Ended March 31,				Three Months Ended March 31,				Three Months Ended March 31,
	2019		2018		2019		2018		2019	2018

Arkansas	$	79,391	$	70,388	$	44,282	$	35,917	12,424,196	11,878,626
Colorado	76,471		71,398		37,600		33,145		13,176,925	11,703,351
Iowa	65,641		67,884		23,050		22,426		15,663,687	15,502,989
Kansas	41,217		42,381		18,119		17,897		10,443,270	10,297,328
Nebraska	108,797		106,761		56,073		53,860		28,999,018	27,987,224
Wyoming	39,563		38,532		24,677		24,414		14,620,457	12,592,932
Total Gas Revenue & Gross Margin (non-GAAP)	$	411,080	$	397,344	$	203,801	$	187,659	95,327,553	89,962,450



	Three Months Ended March 31,
	2,019			2.018			Variance
	(in thousands)
Adjusted operating (loss) ^(a)	$	(507	)	$	(1,696	)	$	1,189



	For the Three Months Ended March 31, 2019
Maximum amount outstanding - commercial paper (based on daily outstanding balances)	$	237
Maximum amount outstanding - revolving credit facility (based on daily outstanding balances)	$	—
Average amount outstanding - commercial paper (based on daily outstanding balances)	$	172
Average amount outstanding - revolving credit facility (based on daily outstanding balances)	$	—
Weighted average interest rates - commercial paper	2.70		%
Weighted average interest rates - revolving credit facility	—		%

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

New York Stock Exchange