BLACK HILLS CORP /SD/ - Quarter Report: 2021 March (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended March 31, 2021

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

For the transition period from __________ to __________.

Commission File Number 001-31303

Black Hills Corporation

Incorporated in South Dakota IRS Identification Number 46-0458824

7001 Mount Rushmore Road

Rapid City, South Dakota 57702

Registrant’s telephone number (605) 721-1700

Former name, former address, and former fiscal year if changed since last report

NONE

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

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

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

Large Accelerated Filer

Accelerated Filer

☐

Non-accelerated Filer

☐

Smaller Reporting Company

☐

Emerging Growth Company

☐

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

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

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common stock of $1.00 par value

BKH

New York Stock Exchange

Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.

Class

Outstanding at April 30, 2021

Common stock, $1.00 par value

62,871,727

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TABLE OF CONTENTS
		Page
Glossary of Terms and Abbreviations		4
Forward-Looking Information		7

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements - unaudited	8
	Condensed Consolidated Statements of Income	8
	Condensed Consolidated Statements of Comprehensive Income	9
	Condensed Consolidated Balance Sheets	10
	Condensed Consolidated Statements of Cash Flows	12
	Condensed Consolidated Statements of Equity	13
	Notes to Condensed Consolidated Financial Statements	14
	Note 1. Management’s Statement	14
	Note 2 . Regulatory Matters	15
	Note 3. Commitments, Contingencies and Guarantees	17
	Note 4 . Revenue	18
	Note 5. Financing	19
	Note 6. Earnings Per Share	20
	Note 7 . Risk Management and Derivatives	20
	Note 8 . Fair Value Measurements	23
	Note 9. Other Comprehensive Income	25
	Note 1 0 . Employee Benefit Plans	26
	Note 1 1 . Income Taxes	27
	Note 1 2 . Business Segment Information	28
	Note 1 3 . Selected Balance Sheet Information	29

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		Page
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
	Executive Summary	30
	Recent Developments	30
	Results of Operations - Consolidated Summary and Overview	32
	Non-GAAP Financial Measure	33
	Electric Utilities	33
	Gas Utilities	36
	Regulatory Matters	38
	Power Generation	39
	Mining	40
	Corporate and Other	41
	Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax Benefit (Expense)	41
	Liquidity and Capital Resources	42
	Cash Flow Activities	42
	Capital Sources	43
	Credit Ratings	43
	Capital Requirements	44
	Critical Accounting Policies Involving Significant Estimates	45
	New Accounting Pronouncements	45

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4.	Controls and Procedures	46

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46

Item 4.	Mine Safety Disclosures	46

Item 6.	Exhibits	46

Signatures		48

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GLOSSARY OF TERMS AND ABBREVIATIONS

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


AFUDC			Allowance for Funds Used During Construction

AOCI			Accumulated Other Comprehensive Income (Loss)

Arkansas Gas			Black Hills Energy Arkansas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Arkansas (doing business as Black Hills Energy).


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

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

BHC			Black Hills Corporation; the Company



Black Hills Colorado IPP			Black Hills Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Electric Generation
Black Hills Electric Generation			Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, providing wholesale electric capacity and energy primarily to our affiliate utilities.
Black Hills Energy			The name used to conduct the business of our utility companies












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









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.
Chief Operating Decision Maker (CODM)			Chief Executive Officer
Choice Gas Program			Regulator-approved programs in Wyoming and Nebraska that allow certain utility customers to select their natural gas commodity supplier, providing for the unbundling of the commodity service from the distribution delivery service.

City of Gillette			Gillette, Wyoming


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

Consolidated Indebtedness to Capitalization Ratio			Any indebtedness outstanding at such time, divided by capital at such time. Capital being consolidated net worth (excluding noncontrolling interest) plus consolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit Facility.
Cooling Degree Day (CDD)			A cooling degree day is equivalent to each degree that the average of the high and low temperatures for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
Corriedale			The 52.5 MW wind farm near Cheyenne, Wyoming, jointly owned by South Dakota Electric and Wyoming Electric, serving as the dedicated wind energy supply to the Renewable Ready program.
COVID-19			The official name for the 2019 novel coronavirus disease announced on February 11, 2020 by the World Health Organization, that is causing a global pandemic.

CP Program			Commercial Paper Program
CPUC			Colorado Public Utilities Commission

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CVA			Credit Valuation Adjustment


Dth			Dekatherm. A unit of energy equal to 10 therms or approximately one million British thermal units (MMBtu)






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




Heating Degree Day (HDD)			A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.


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)
KCC			Kansas Corporation Commission

LIBOR			London Interbank Offered Rate


MMBtu			Million British thermal units

Moody’s			Moody’s Investors Service, Inc.

MW			Megawatts
MWh			Megawatt-hours
Nebraska Gas			Black Hills Nebraska Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Nebraska (doing business as Black Hills Energy)
NOL			Net Operating Loss
NPSC			Nebraska Public Service Commission








OCI			Other Comprehensive Income
PPA			Power Purchase Agreement

PSA			Power Sales Agreement

Pueblo Airport Generation			The 420 MW combined cycle gas-fired power generation plants jointly owned by Colorado Electric (220 MW) and Black Hills Colorado IPP (200 MW). Black Hills Colorado IPP owns and operates this facility. The plants commenced operation on January 1, 2012.
Renewable Advantage			A 200 MW solar facility project to be constructed in Pueblo County, Colorado. The project aims to lower customer energy costs and provide economic and environmental benefits to Colorado Electric’s customers and communities. This project, which was approved by the CPUC in September 2020, will be owned by a third-party renewable energy developer with Colorado Electric purchasing all of the energy generated at the facility under the terms of a 15-year PPA. The project is expected to be placed in service in 2023.
Renewable Ready			Voluntary renewable energy subscription program for large commercial, industrial and governmental agency customers in South Dakota and Wyoming.
Revolving Credit Facility			Our $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which was amended and restated on July 30, 2018, and now terminates on July 30, 2023.

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

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

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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
Winter Storm Uri			February 2021 winter weather event that caused extremely cold temperatures in the central United States and led to unprecedented fluctuations in customer demand and market pricing for natural gas and energy.

WRDC			Wyodak Resources Development Corporation, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings (doing business as Black Hills Energy)
Wygen I			A mine-mouth, coal-fired power plant with a total capacity of 90 MW located at our Gillette, Wyoming energy complex. Black Hills Wyoming owns 76.5% of the facility and Municipal Energy Agency of Nebraska (MEAN) owns the remaining 23.5%.
Wyodak Plant			The 362 MW mine-mouth, coal-fired generation facility near Gillette, Wyoming, jointly owned by PacifiCorp (80%) and South Dakota Electric (20%). Our WRDC mine supplies all of the fuel for the facility.
Wyoming Electric			Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in the Cheyenne, Wyoming area (doing business as Black Hills Energy).
Wyoming Gas			Black Hills Wyoming Gas, LLC, an indirect and wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Wyoming (doing business as Black Hills Energy).

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FORWARD-LOOKING INFORMATION

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

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

Any forward-looking statement contained in this document speaks only as of the date the statement was made. The Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement was made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, such as the COVID-19 pandemic or Winter Storm Uri, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements described in our 2020 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our 2020 Annual Report on Form 10-K, Part II, Item 1A of this Quarterly Report on Form 10-Q and other reports that we file with the SEC from time to time.

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


(unaudited)	Three Months Ended March 31,
		2021		2020
		(in thousands, except per share amounts)

Revenue		$	633,432	$	537,050

Operating expenses:
Fuel, purchased power and cost of natural gas sold		293,147		187,879
Operations and maintenance		129,679		125,466
Depreciation, depletion and amortization		57,269		56,402
Taxes - property and production		15,022		14,118

Total operating expenses		495,117		383,865

Operating income		138,315		153,185

Other income (expense):

Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)		(37,825)		(35,781)

Interest income		225		328

Impairment of investment		—		(6,859)
Other income (expense), net		266		2,353
Total other income (expense)		(37,334)		(39,959)

Income before income taxes		100,981		113,226
Income tax (expense)		(494)		(16,002)
Net income		100,487		97,224
Net income attributable to noncontrolling interest		(4,171)		(4,050)
Net income available for common stock		$	96,316	$	93,174

Earnings per share of common stock:
Earnings per share, Basic		$	1.54	$	1.51
Earnings per share, Diluted		$	1.54	$	1.51

Weighted average common shares outstanding:
Basic		62,633		61,778
Diluted		62,691		61,856

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


(unaudited)	Three Months Ended March 31,
		2021		2020
		(in thousands)
Net income		$	100,487	$	97,224

Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (net of tax of $0 and $(17), respectively)		—		55
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $9 and $7, respectively)		(16)		(23)
Reclassification adjustments of benefit plan liability - net loss (net of tax of $(217) and $(95), respectively)		381		502
Derivative instruments designated as cash flow hedges:
Reclassification of net realized losses on settled/amortized interest rate swaps (net of tax of $(190) and $(170), respectively)		523		543
Net unrealized gains (losses) on commodity derivatives (net of tax of $(35) and $54, respectively)		107		(175)
Reclassification of net realized losses on settled commodity derivatives (net of tax of $(8) and $(115), respectively)		23		371
Other comprehensive income, net of tax		1,018		1,273

Comprehensive income		101,505		98,497
Less: comprehensive income attributable to noncontrolling interest		(4,171)		(4,050)
Comprehensive income available for common stock		$	97,334	$	94,447

See Note 9 for additional disclosures.

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


(unaudited)	As of
	March 31, 2021		December 31, 2020
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	13,442	$	6,356
Restricted cash and equivalents	4,483		4,383
Accounts receivable, net	282,382		265,961
Materials, supplies and fuel	102,603		117,400
Derivative assets, current	1,917		1,848
Income tax receivable, net	18,115		19,446
Regulatory assets, current	129,951		51,676
Other current assets	25,722		26,221
Total current assets	578,615		493,291

Property, plant and equipment	7,415,818		7,305,530
Less: accumulated depreciation and depletion	(1,320,525)		(1,285,816)
Total property, plant and equipment, net	6,095,293		6,019,714

Other assets:
Goodwill	1,299,454		1,299,454
Intangible assets, net	11,649		11,944
Regulatory assets, non-current	672,306		226,582
Other assets, non-current	38,882		37,801
Total other assets, non-current	2,022,291		1,575,781

TOTAL ASSETS	$	8,696,199	$	8,088,786

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Continued)


(unaudited)	As of
	March 31, 2021		December 31, 2020
	(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	160,179	$	183,340
Accrued liabilities	230,444		243,612
Derivative liabilities, current	2,526		2,044
Regulatory liabilities, current	13,580		25,061
Notes payable	815,870		234,040
Current maturities of long-term debt	7,000		8,436
Total current liabilities	1,229,599		696,533

Long-term debt, net of current maturities	3,529,158		3,528,100

Deferred credits and other liabilities:
Deferred income tax liabilities, net	428,127		408,624
Regulatory liabilities, non-current	497,810		507,659
Benefit plan liabilities	150,979		150,556
Other deferred credits and other liabilities	135,224		134,667
Total deferred credits and other liabilities	1,212,140		1,201,506

Commitments, contingencies and guarantees (Note 3)

Equity:
Stockholders’ equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 62,909,973 and 62,827,179 shares, respectively	62,910		62,827
Additional paid-in capital	1,658,957		1,657,285
Retained earnings	931,538		870,738
Treasury stock, at cost – 39,940 and 32,492 shares, respectively	(2,564)		(2,119)
Accumulated other comprehensive income (loss)	(26,328)		(27,346)
Total stockholders’ equity	2,624,513		2,561,385
Noncontrolling interest	100,789		101,262
Total equity	2,725,302		2,662,647

TOTAL LIABILITIES AND TOTAL EQUITY	$	8,696,199	$	8,088,786

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


(unaudited)	Three Months Ended March 31,
	2021		2020
Operating activities:	(in thousands)
Net income	$	100,487	$	97,224
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	57,269		56,402
Deferred financing cost amortization	2,214		2,237
Impairment of investment	—		6,859
Stock compensation	3,257		291
Deferred income taxes	153		21,876
Employee benefit plans	2,304		1,235
Other adjustments, net	6,151		892
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	15,932		19,222
Accounts receivable and other current assets	(11,599)		8,171
Accounts payable and other current liabilities	(23,602)		(43,297)
Regulatory assets	(533,006)		20,679
Regulatory liabilities	(5,291)		1,316

Other operating activities, net	(355)		(1,138)
Net cash provided by (used in) operating activities	(386,086)		191,969

Investing activities:
Property, plant and equipment additions	(146,302)		(171,882)
Other investing activities	78		(1,202)
Net cash (used in) investing activities	(146,224)		(173,084)

Financing activities:
Dividends paid on common stock	(35,514)		(32,902)
Common stock issued	—		99,321
Term loan - borrowings	800,000		—
Term loan - repayments	(200,000)		—
Net (payments) borrowings of Revolving Credit Facility and CP Program	(18,170)		(30,375)

Long-term debt - repayments	(1,436)		(4,291)
Distributions to noncontrolling interest	(4,644)		(4,741)
Other financing activities	(740)		(1,391)
Net cash provided by financing activities	539,496		25,621

Net change in cash, restricted cash and cash equivalents	7,186		44,506

Cash, restricted cash and cash equivalents at beginning of period	10,739		13,658
Cash, restricted cash and cash equivalents at end of period	$	17,925	$	58,164

Supplemental cash flow information:
Cash (paid) refunded during the period:
Interest, net of amounts capitalized	$	(21,232)	$	(21,776)
Income taxes	990		—
Non-cash investing and financing activities:
Accrued property, plant and equipment purchases at March 31	51,914		53,011

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY


(unaudited)	Common Stock			Treasury Stock
(in thousands except share amounts)	Shares	Value		Shares	Value		Additional Paid in Capital		Retained Earnings		AOCI		Non controlling Interest		Total
December 31, 2020	62,827,179	$	62,827	32,492	$	(2,119)	$	1,657,285	$	870,738	$	(27,346)	$	101,262	$	2,662,647
Net income	—	—		—	—		—		96,316		—		4,171		100,487
Other comprehensive income (loss), net of tax	—	—		—	—		—		—		1,018		—		1,018


Dividends on common stock ($0.565 per share)	—	—		—	—		—		(35,514)		—		—		(35,514)
Share-based compensation	82,794	83		7,448	(445)		1,672		—		—		—		1,310






Other	—	—		—	—		—		(2)		—		—		(2)

Distributions to noncontrolling interest	—	—		—	—		—		—		—		(4,644)		(4,644)
March 31, 2021	62,909,973	$	62,910	39,940	$	(2,564)	$	1,658,957	$	931,538	$	(26,328)	$	100,789	$	2,725,302


	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	—	—		—	—		—		93,174		—		4,050		97,224
Other comprehensive income (loss), net of tax	—	—		—	—		—		—		1,273		—		1,273
Dividends on common stock ($0.535 per share)	—	—		—	—		—		(32,902)		—		—		(32,902)
Share-based compensation	69,378	69		20,700	(1,658)		2,263		—		—		—		674

Issuance of common stock	1,222,942	1,223		—	—		98,777		—		—		—		100,000
Issuance costs	—	—		—	—		(967)		—		—		—		(967)
Implementation of ASU 2016-13 Financial Instruments -- Credit Losses	—	—		—	—		—		(207)		—		—		(207)
Distributions to noncontrolling interest	—	—		—	—		—		—		—		(4,741)		(4,741)
March 31, 2020	62,772,978	$	62,773	24,656	$	(1,925)	$	1,652,861	$	838,841	$	(29,382)	$	101,255	$	2,624,423

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BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s 2020 Annual Report on Form 10-K)

(1) Management’s Statement

The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company”, “us”, “we” or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with 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 included in our 2020 Annual Report on Form 10-K.

Segment Reporting

We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States.

Use of Estimates and Basis of Presentation

The information furnished in the accompanying Condensed Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the March 31, 2021, December 31, 2020 and March 31, 2020 financial information. Certain lines of business in which we operate are highly seasonal, and our interim results of operations are not necessarily indicative of the results of operations to be expected for an entire year.

COVID-19 Pandemic

In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the outbreak a national emergency. The U.S. government has deemed the electric and natural gas utilities to be critical infrastructure sectors that provide essential services during this emergency. As a provider of essential services, the Company has an obligation to provide services to our customers. The Company remains focused on protecting the health of our customers, employees and the communities in which we operate while assuring the continuity of our 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, 2021, there were no material adverse impacts on the Company’s results of operations.

Recently Issued Accounting Standards

Facilitation of the Effects of Reference Rate Reform on Financial Reporting, ASU 2020-04

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which was subsequently amended by ASU 2021-01. The standard provides relief for companies preparing for discontinuation of interest rates, such as LIBOR, and allows optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The amendments in this update are elective and are effective upon the ASU issuance through December 31, 2022. We are currently evaluating whether we will apply the optional guidance as we assess the impact of the discontinuance of LIBOR on our current arrangements and the potential impact on our financial position, results of operations and cash flows.

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Recently Adopted 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. We adopted this standard prospectively on January 1, 2021. Adoption of this standard did not have an impact on our financial position, results of operations or cash flows.

(2) Regulatory Matters

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


	As of		As of
	March 31, 2021		December 31, 2020
Regulatory assets
Winter Storm Uri (a)	$	480,842	$	—
Deferred energy and fuel cost adjustments (a) (b)	68,402		39,035
Deferred gas cost adjustments (a) (b)	17,066		3,200
Gas price derivatives (b)	324		2,226
Deferred taxes on AFUDC (c)	7,469		7,491
Employee benefit plans and related deferred taxes (d)	117,886		116,598
Environmental (b)	1,413		1,413

Loss on reacquired debt (b)	22,386		22,864

Deferred taxes on flow through accounting (d)	51,823		47,515
Decommissioning costs (c)	7,827		8,988
Gas supply contract termination (b)	1,013		2,524
Other regulatory assets (b)	25,806		26,404
Total regulatory assets	802,257		278,258
Less current regulatory assets	(129,951)		(51,676)
Regulatory assets, non-current	$	672,306	$	226,582

Regulatory liabilities
Deferred energy and gas costs (b)	$	426	$	13,253
Employee benefit plan costs and related deferred taxes (d)	40,471		40,256
Cost of removal (b)	177,003		172,902

Excess deferred income taxes (d)	271,492		285,259

Other regulatory liabilities (d)	21,998		21,050
Total regulatory liabilities	511,390		532,720
Less current regulatory liabilities	(13,580)		(25,061)
Regulatory liabilities, non-current	$	497,810	$	507,659

__________

(a) We are in discussions with our regulators regarding the timing of Winter Storm Uri incremental cost recovery. See further information below.

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

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

Regulatory Activity

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

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Winter Storm Uri

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

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

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

Winter Storm Uri Costs by Jurisdiction

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


Costs by Jurisdiction	(in thousands)
Gas Utilities:
Arkansas Gas	$	137,500
Colorado Gas	77,850
Iowa Gas	95,450
Kansas Gas	87,900
Nebraska Gas	79,750
Wyoming Gas	29,409
Gas Utilities Total	$	507,859

Electric Utilities:
Colorado Electric	$	25,500
South Dakota Electric	22,200
Wyoming Electric	3,266
Electric Utilities Total	$	50,966

Total Winter Storm Uri Incremental Costs Recorded to Regulatory Asset	$	558,825

Costs by Regulatory Asset
Winter Storm Uri (a)	$	480,842
Deferred energy and fuel cost adjustments	27,166
Deferred gas cost adjustments (b)	50,817
	$	558,825

__________

(a) We expect to recover most of the Winter Storm Uri incremental costs through a separately tracked regulatory mechanism but also expect to recover a portion through our existing mechanisms.

(b) Incremental natural gas costs from Winter Storm Uri are reflected as an increase in the Deferred gas cost adjustments regulatory asset, net of existing Deferred energy and gas cost regulatory liabilities, for the three months ended March 31, 2021.

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TCJA

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

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

Colorado Gas

Rate Review

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

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

Nebraska Gas

Jurisdictional Consolidation and Rate Review

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

(3) Commitments, Contingencies and Guarantees

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

Power Purchase Agreement - Colorado Electric Renewable Advantage

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

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(4) Revenue

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


Three Months Ended March 31, 2021	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues		Total
Customer types:	(in thousands)
Retail	$	198,500	$	341,605	$	—	$	14,083	$	(7,107)	$	547,081
Transportation	—		47,951		—		—		(110)		47,841
Wholesale	5,922		—		28,692		—		(24,451)		10,163
Market - off-system sales	7,656		73		—		—		(2,884)		4,845
Transmission/Other	15,193		10,390		—		—		(5,296)		20,287
Revenue from contracts with customers	$	227,271	$	400,019	$	28,692	$	14,083	$	(39,848)	$	630,217
Other revenues	137		2,500		471		589		(482)		3,215
Total revenues	$	227,408	$	402,519	$	29,163	$	14,672	$	(40,330)	$	633,432

Timing of revenue recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	14,083	$	(7,107)	$	6,976
Services transferred over time	227,271		400,019		28,692		—		(32,741)		623,241
Revenue from contracts with customers	$	227,271	$	400,019	$	28,692	$	14,083	$	(39,848)	$	630,217


Three Months Ended March 31, 2020	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues		Total
Customer Types:
Retail	$	148,640	$	298,247	$	—	$	14,403	$	(7,839)	$	453,451
Transportation	—		44,108		—		—		(139)		43,969
Wholesale	5,552		—		25,467		—		(23,612)		7,407
Market - off-system sales	4,867		138		—		—		(2,639)		2,366
Transmission/Other	14,857		12,572		—		—		(4,413)		23,016
Revenue from contracts with customers	$	173,916	$	355,065	$	25,467	$	14,403	$	(38,642)	$	530,209
Other revenues	223		5,708		499		802		(391)		6,841
Total Revenues	$	174,139	$	360,773	$	25,966	$	15,205	$	(39,033)	$	537,050

Timing of Revenue Recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	14,403	$	(7,839)	$	6,564
Services transferred over time	173,916		355,065		25,467		—		(30,803)		523,645
Revenue from contracts with customers	$	173,916	$	355,065	$	25,467	$	14,403	$	(38,642)	$	530,209

Contract Balances

The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable further discussed in Note 13.

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(5) Financing

Short-term debt

We had the following Notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:


	March 31, 2021				December 31, 2020
	Balance Outstanding		Letters of Credit (a)		Balance Outstanding		Letters of Credit (a)
Term Loan	$	600,000	$	—	$	—	$	—
Revolving Credit Facility	—		16,629		—		24,730
CP Program	215,870		—		234,040		—
Total Notes payable	$	815,870	$	16,629	$	234,040	$	24,730

_______________

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

Term Loan

On February 24, 2021, we entered into a nine-month, $800 million unsecured term loan to provide additional liquidity and meet our cash needs related to the incremental fuel, purchased power and natural gas costs from Winter Storm Uri. The term loan, which matures on November 24, 2021, has an interest rate based on LIBOR plus 75 basis points, carries no prepayment penalty and is subject to the same covenant requirements as our Revolving Credit Facility. We repaid $200 million of this term loan in the first quarter of 2021. The interest rate on term loan borrowings on March 31, 2021 was 0.86%.

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

Revolving Credit Facility and CP Program

Our net short-term borrowings related to our Revolving Credit Facility and CP Program during the three months ended March 31, 2021 decreased by $18 million. The weighted average interest rate on short-term borrowings related to our Revolving Credit Facility and CP Program at March 31, 2021 was 0.23%.

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, which includes letters of credit and certain guarantees issued, by (ii) capital, which includes consolidated indebtedness plus consolidated net worth, which excludes noncontrolling interest in subsidiaries. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding.

Our Revolving Credit Facility and term loans require compliance with the following financial covenant, which we were in compliance with at March 31, 2021:

As of March 31, 2021

Covenant Requirement

Consolidated Indebtedness to Capitalization Ratio

62.6%

Less than

65%

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(6) Earnings Per Share

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


	Three Months Ended March 31,
		2021		2020

Net income available for common stock		$	96,316	$	93,174

Weighted average shares - basic		62,633		61,778
Dilutive effect of:
Equity compensation		58		78
Weighted average shares - diluted		62,691		61,856

Earnings per share of common stock:
Earnings per share, Basic		$	1.54	$	1.51
Earnings per share, Diluted		$	1.54	$	1.51

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


	Three Months Ended March 31,
		2021	2020

Equity compensation		14	12
Restricted stock		19	26

Anti-dilutive shares		33	38

(7) Risk Management and Derivatives

Market and Credit Risk Disclosures

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

Market Risk

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

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

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

Credit Risk

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

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

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

Derivatives and Hedging Activity

Our derivative and hedging activities 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 8.

The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generating facilities plants or those facilities under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to natural gas price volatility. Therefore, as allowed or required by state regulatory 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’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Condensed Consolidated Balance Sheets in accordance with the state regulatory commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Condensed Consolidated Statements of Income.

We periodically use wholesale power purchase and sale contracts to manage purchased power costs and load requirements associated with serving our electric customers that are considered derivative instruments due to not qualifying for the normal purchases and normal sales exception to derivative accounting. Changes in the fair value of these commodity derivatives are recognized in the Condensed Consolidated Statements of Income.

We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risk using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and sales during time frames ranging from April 2021 through August 2023. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price forward contracts to deliver gas to our Choice Gas Program customers. The gain or loss on these designated derivatives is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and reclassified into earnings in the same period that the underlying hedged item is recognized in earnings. Effectiveness of our hedging position is evaluated at least quarterly.

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


		March 31, 2021		December 31, 2020
	Units	Notional Amounts	Maximum Term (months) (a)	Notional Amounts	Maximum Term (months) (a)
Natural gas futures purchased	MMBtus	—	0	620,000	3
Natural gas options purchased, net	MMBtus	—	0	3,160,000	3
Natural gas basis swaps purchased	MMBtus	—	0	900,000	3
Natural gas over-the-counter swaps, net (b)	MMBtus	3,590,000	29	3,850,000	17
Natural gas physical contracts, net (c)	MMBtus	3,107,817	12	17,513,061	22
Electric wholesale contracts (c)	MWh	183,025	9	219,000	12

__________

(a) Term reflects the maximum forward period hedged.

(b) As of March 31, 2021, 442,900 MMBtus of natural gas over-the-counter swaps purchases were designated as cash flow hedges.

(c) Volumes exclude derivative contracts that qualify for the normal purchases and normal sales exception permitted by GAAP.

We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At March 31, 2021, the Company posted $1.4 million related to such provisions, which is included in Other current assets on the Condensed Consolidated Balance Sheets.

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Derivatives by Balance Sheet Classification

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

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


	Balance Sheet Location	March 31, 2021		December 31, 2020
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets, current	$	285	$	181
Noncurrent commodity derivatives	Other assets, non-current	4		43
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current	—		(108)
Noncurrent commodity derivatives	Other deferred credits and other liabilities	—		—
Total derivatives designated as hedges		$	289	$	116

Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets, current	$	1,632	$	1,667
Noncurrent commodity derivatives	Other assets, non-current	32		151
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current	(2,526)		(1,936)
Noncurrent commodity derivatives	Other deferred credits and other liabilities	(43)		—
Total derivatives not designated as hedges		$	(905)	$	(118)

Derivatives Designated as Hedge Instruments

The impacts of cash flow hedges on our Condensed Consolidated Statements of Comprehensive Income and Condensed Consolidated Statements of Income are presented below for the three months ended March 31, 2021 and 2020. Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.


	Three Months Ended March 31,					Three Months Ended March 31,
	2021		2020			2021		2020
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	173		257		Fuel, purchased power and cost of natural gas sold	(31)		(486)
Total	$	886	$	970		$	(744)	$	(1,199)

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

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Derivatives Not Designated as Hedge Instruments

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Condensed Consolidated Statements of Income for the three months ended March 31, 2021 and 2020. Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.


		Three Months Ended March 31,
		2021		2020
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	$	(1,524)	$	1,362
Commodity derivatives - Natural Gas	Fuel, purchased power and cost of natural gas sold	366		766
		$	(1,158)	$	2,128

As discussed above, financial instruments used in our regulated Gas Utilities are not designated as cash flow hedges. There is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory asset or Regulatory liability related to the hedges in our Gas Utilities were $0.3 million and $2.2 million as of March 31, 2021 and December 31, 2020, respectively. For our Electric Utilities, the unrealized gains and losses arising from these derivatives are recognized in the Condensed Consolidated Statements of Income.

(8) Fair Value Measurements

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

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

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

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

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

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

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Recurring Fair Value Measurements

Derivatives

The commodity contracts for our Utilities segments are valued using the market approach and include forward strip pricing at liquid delivery points, exchange-traded futures, options, basis swaps and over-the-counter swaps and options (Level 2) for wholesale electric energy and natural gas contracts. For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable contract. For over-the-counter instruments, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a CVA based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position. For additional information, see Note 1 of our Notes to the Consolidated Financial Statements in our 2020 Annual Report on Form 10-K.


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

Liabilities:
Commodity derivatives — Gas Utilities	$	—	$	625	$	—	$	—	$	625
Commodity derivatives — Electric Utilities	$	—	$	1,944	$	—	$	—	$	1,944
Total	$	—	$	2,569	$	—	$	—	$	2,569


	As of December 31, 2020
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting		Total
	(in thousands)
Assets:
Commodity derivatives — Gas Utilities	$	—	$	2,504	$	—	$	(1,527)	$	977
Commodity derivatives — Electric Utilities	$	—	$	1,065	$	—	$	—	$	1,065
Total	$	—	$	3,569	$	—	$	(1,527)	$	2,042

Liabilities:
Commodity derivatives — Gas Utilities	$	—	$	2,675	$	—	$	(1,552)	$	1,123
Commodity derivatives — Electric Utilities	$	—	$	921	$	—	$	—	$	921
Total	$	—	$	3,596	$	—	$	(1,552)	$	2,044

Pension and Postretirement Plan Assets

Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about the fair value measurements of their assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 15 to the Consolidated Financial Statements included in our 2020 Annual Report on Form 10-K.

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Other fair value measures

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

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


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

__________

(a) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified as Level 2 in the fair value hierarchy. Carrying amount of long-term debt is net of deferred financing costs.

(9) Other Comprehensive Income

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

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


	Location on the Condensed Consolidated Statements of Income		Amount Reclassified from AOCI
		Three Months Ended March 31,
			2021		2020
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense		$	(713)	$	(713)
Commodity contracts	Fuel, purchased power and cost of natural gas sold		(31)		(486)
			(744)		(1,199)
Income tax	Income tax benefit		198		285
Total reclassification adjustments related to cash flow hedges, net of tax			$	(546)	$	(914)

Amortization of components of defined benefit plans:
Prior service cost	Operations and maintenance		$	25	$	30
Actuarial gain (loss)	Operations and maintenance		(598)		(597)
			(573)		(567)
Income tax	Income tax benefit		208		88
Total reclassification adjustments related to defined benefit plans, net of tax			$	(365)	$	(479)
Total reclassifications			$	(911)	$	(1,393)

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


	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps		Commodity Derivatives		Employee Benefit Plans		Total
As of December 31, 2020	$	(12,558)	$	2	$	(14,790)	$	(27,346)
Other comprehensive income (loss)
before reclassifications	—		107		—		107
Amounts reclassified from AOCI	523		23		365		911
As of March 31, 2021	$	(12,035)	$	132	$	(14,425)	$	(26,328)

	Derivatives Designated as Cash Flow Hedges
	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)

(10) 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,
		2021		2020
Service cost		$	1,259	$	1,353
Interest cost		2,328		3,357
Expected return on plan assets		(5,219)		(5,648)

Net loss (gain)		1,829		2,093
Net periodic benefit cost		$	197	$	1,155

Defined Benefit Postretirement Healthcare Plan

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


	Three Months Ended March 31,
		2021		2020
Service cost		$	559	$	514
Interest cost		265		412
Expected return on plan assets		(34)		(45)
Prior service cost (benefit)		(109)		(137)
Net loss (gain)		117		5
Net periodic benefit cost		$	798	$	749

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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,
		2021		2020
Service cost		$	693	$	(1,370)
Interest cost		177		275

Net loss (gain)		439		426
Net periodic benefit cost		$	1,309	$	(669)

Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made in the first quarter of 2021 and anticipated contributions for 2021 and 2022 are as follows (in thousands):


	Contributions Made		Additional Contributions		Contributions
	Three Months Ended March 31, 2021		Anticipated for 2021		Anticipated for 2022
Defined Benefit Pension Plan	$	—	$	—	$	3,788
Non-pension Defined Benefit Postretirement Healthcare Plan	$	1,382	$	4,145	$	5,241
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans	$	482	$	1,445	$	1,967

(11) Income Taxes

Winter Storm Uri

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

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

Income Tax Benefit (Expense) and Effective Tax Rates

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

Income tax (expense) for the three months ended March 31, 2021 was $(0.5) million compared to $(16) million reported for the same period in 2020. For the three months ended March 31, 2021 the effective tax rate was 0.5% compared to 14.1% for the same period in 2020. The lower effective tax rate is primarily due to $7.6 million of increased tax benefits from Colorado Electric’s TCJA-related bill credits to customers (which is offset by reduced revenue), $1.5 million of increased tax benefits from amortization of excess deferred income taxes and $1.3 million of increased tax benefits from federal production tax credits associated with new wind assets.

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(12) 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. All of our operations and assets are located within the United States.

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

Segment information was as follows (in thousands):


Total assets (net of intercompany eliminations) as of:	March 31, 2021		December 31, 2020
Electric Utilities	$	3,217,474	$	3,120,928
Gas Utilities	4,900,939		4,376,204
Power Generation	406,742		404,220
Mining	76,097		77,085
Corporate and Other	94,947		110,349
Total assets	$	8,696,199	$	8,088,786


Three Months Ended March 31, 2021	External Operating Revenue				Inter-company Operating Revenue				Total Revenues
	Contract Customers		Other Revenues		Contract Customers		Other Revenues
Segment:
Electric Utilities	$	220,500	$	137	$	6,771	$	—	$	227,408
Gas Utilities	398,499		2,408		1,520		92		402,519
Power Generation	4,241		421		24,451		50		29,163
Mining	6,977		249		7,106		340		14,672
Inter-company eliminations	—		—		(39,848)		(482)		(40,330)
Total	$	630,217	$	3,215	$	—	$	—	$	633,432



Three Months Ended March 31, 2020	External Operating Revenue				Inter-company Operating Revenue				Total Revenues
	Contract Customers		Other Revenues		Contract Customers		Other 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

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	Three Months Ended March 31,
		2021		2020
Adjusted operating income:
Electric Utilities		$	21,813	$	35,650
Gas Utilities		102,094		102,897
Power Generation		14,269		11,349
Mining		3,261		3,129
Corporate and Other		(3,122)		160
Operating income		138,315		153,185

Interest expense, net		(37,600)		(35,453)
Impairment of investment		—		(6,859)
Other income (expense), net		266		2,353
Income tax (expense)		(494)		(16,002)
Net income		100,487		97,224
Net income attributable to noncontrolling interest		(4,171)		(4,050)
Net income available for common stock		$	96,316	$	93,174

(13) Selected Balance Sheet Information

Accounts Receivable and Allowance for Credit Losses

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


	March 31, 2021		December 31, 2020
Accounts receivable, trade	$	199,548	$	146,899
Unbilled revenue	91,085		126,065
Less: Allowance for credit losses	(8,251)		(7,003)
Accounts receivable, net	$	282,382	$	265,961

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


	Balance at Beginning of Year		Additions Charged to Costs and Expenses		Recoveries and Other Additions		Write-offs and Other Deductions		Balance at March 31,
2021	$	7,003	$	1,877	$	1,014	$	(1,643)	$	8,251
2020	$	2,444	$	3,519	$	922	$	(1,723)	$	5,162

Materials, Supplies and Fuel

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


	March 31, 2021		December 31, 2020
Materials and supplies	$	88,088	$	85,250
Fuel - Electric Utilities	1,590		1,531
Natural gas in storage	12,925		30,619
Total materials, supplies and fuel	$	102,603	$	117,400

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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, 2021		December 31, 2020
Accrued employee compensation, benefits and withholdings	$	57,347	$	77,806
Accrued property taxes	49,267		47,105
Customer deposits and prepayments	50,194		52,185
Accrued interest	45,896		31,520
Other (none of which is individually significant)	27,740		34,996
Total accrued liabilities	$	230,444	$	243,612

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

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

Executive Summary

We are a customer-focused, growth-oriented electric and natural gas utility company with a mission of Improving Life with Energy and a vision to be the Energy Partner of Choice. The Company provides electric and natural gas utility service to 1.3 million customers over 800 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming.

Recent Developments

Winter Storm Uri

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


	(in millions)
Incremental fuel, purchased power and natural gas costs recorded to regulatory assets	$	558.8

Electric Utilities wholesale power margin sharing	$	3.2
Electric Utilities non-recoverable fuel costs	2.1
Black Hills Energy Services non-recoverable natural gas costs	8.2
Interest expense from $800 million term loan	0.7
Less Power Generation favorable net impact	(1.7)
Incremental costs recorded as expenses, net	$	12.5

Total incremental costs related to Winter Storm Uri, net	$	571.3

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

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

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

COVID-19 Update

For the three months ended March 31, 2021, we did not experience significant impacts to our financial results, liquidity or operational activities due to COVID-19. We continue to monitor loads, customers’ ability to pay, the potential for supply chain disruption that may impact our capital and maintenance project plans, the availability of third-party resources to execute our business plans and the capital markets to ensure we have the liquidity necessary to support our financial needs. State orders lifting temporarily suspended disconnections have been issued in all of our jurisdictions.

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

As we look forward, our operating results from COVID-19 could be affected as discussed in the “Risk Factors” section in Part I, Item 1A of our 2020 Annual Report on Form 10-K.

Business Segment Highlights and Corporate Activity

Electric Utilities Segment

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

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

Gas Utilities Segment

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

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

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Results of Operations

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

Certain lines of business in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements. In particular, the normal peak usage season for our Electric Utilities is June through August while the normal peak usage season for our Gas Utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three months ended March 31, 2021 and 2020, and our financial condition as of March 31, 2021 and December 31, 2020, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period or for the entire year.

Consolidated Summary and Overview


	Three Months Ended March 31,
		2021		2020
		(in thousands except per share amounts)




Adjusted operating income (a)
Electric Utilities		$	21,813	$	35,650
Gas Utilities		102,094		102,897
Power Generation		14,269		11,349
Mining		3,261		3,129
Corporate and Other		(3,122)		160
Operating income		138,315		153,185

Interest expense, net		(37,600)		(35,453)
Impairment of investment		—		(6,859)
Other income (expense), net		266		2,353
Income tax (expense)		(494)		(16,002)
Net income		100,487		97,224
Net income attributable to noncontrolling interest		(4,171)		(4,050)
Net income available for common stock		96,316		93,174

Total earnings per share of common stock, Diluted		$	1.54	$	1.51

__________

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

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

The variance to the prior year included the following:

•Electric Utilities’ adjusted operating income decreased $14 million primarily due to Colorado Electric’s TCJA-related bill credits to customers, impacts from Winter Storm Uri and unfavorable mark-to-market adjustments on wholesale energy contracts partially offset by increased rider revenues and lower operating expenses;

•Gas Utilities’ adjusted operating income decreased $0.8 million primarily due to Winter Storm Uri costs incurred by Black Hills Energy Services and higher operating expenses mostly offset by new rates and higher heating demand from colder winter weather;

•Power Generation’s adjusted operating income increased $2.9 million primarily due to favorable impacts from Winter Storm Uri;

•Corporate and Other expenses increased $3.3 million primarily due to a prior year favorable true-up of employee costs allocated to our subsidiaries in the current year, which is offset in our reportable segments;

•A $2.1 million increase in interest expense due to higher debt balances partially offset by lower rates;

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

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•A $2.1 million decrease in other income primarily due to prior year credits for our non-qualified benefit plan driven by market performance on plan assets; and

•A $15.5 million decrease in income tax expense due to lower pre-tax income and a lower effective tax rate driven primarily by tax benefits from Colorado Electric’s TCJA-related bill credits, amortization of excess deferred income taxes and federal production tax credits associated with new wind assets.

Segment Operating Results

A discussion of operating results from our business segments follows.

Non-GAAP Financial Measure

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

Gross margin for our Electric Utilities is calculated as operating revenue less cost of fuel and purchased power. Gross margin for our Gas Utilities is calculated as operating revenue less cost of natural gas sold. Our gross margin is impacted by the fluctuations in power and natural gas purchases and other fuel supply costs. However, while these fluctuating costs impact gross margin as a percentage of revenue, they only impact total gross margin if the costs cannot be passed through to our customers.

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

Electric Utilities

Operating results for the Electric Utilities were as follows (in thousands):


	Three Months Ended March 31,
		2021		2020		Variance

Revenue		$	227,408	$	174,139	$	53,269

Total fuel and purchased power		132,069		64,460		67,609

Gross margin (non-GAAP)		95,339		109,679		(14,340)

Operations and maintenance		48,577		50,499		(1,922)
Depreciation and amortization		24,949		23,530		1,419
Total operating expenses		73,526		74,029		(503)

Adjusted operating income		$	21,813	$	35,650	$	(13,837)

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

Gross margin for the three months ended March 31, 2021 decreased as a result of the following:


	(in millions)
TCJA-related bill credits (a)	$	(9.3)
Winter Storm Uri impacts (b)	(5.3)
Mark-to-market on wholesale energy contracts	(2.9)
Rider recovery	1.3
Weather	1.1
Residential customer growth	0.3
Other	0.5
Total change in Gross margin (non-GAAP)	$	(14.3)

________________

(a) In February 2021, Colorado Electric delivered TCJA-related bill credits to its customers. These bill credits were offset by a reduction in income tax expense and resulted in a minimal impact to Net Income.

(b) As a result of Winter Storm Uri, our Electric Utilities incurred a $3.2 million negative impact to our regulated wholesale power margins due to higher fuel costs and $2.1 million of incremental fuel costs that are not recoverable through our fuel cost recovery mechanisms.

Operations and maintenance expense decreased primarily due to prior year expenses related to the municipalization efforts in Pueblo, Colorado.

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

Operating Statistics


		Revenue (in thousands)					Quantities Sold (MWh)
	Three Months Ended March 31,					Three Months Ended March 31,
		2021		2020			2021	2020

Residential		$	72,760	$	54,505		396,086	373,150
Commercial		77,007		57,823			492,955	494,308
Industrial		43,009		32,169			415,191	460,632
Municipal		5,020		3,878			36,242	36,399
Subtotal Retail Revenue - Electric		197,796		148,375			1,340,474	1,364,489
Contract Wholesale (a)		8,465		5,553			156,995	131,778
Off-system/Power Marketing Wholesale		5,113		4,867			127,583	165,785
Other		16,034		15,344			—	—
Total Revenue and Energy Sold		227,408		174,139			1,625,052	1,662,052
Other Uses, Losses or Generation, net		—		—			130,975	90,871
Total Revenue and Energy		227,408		174,139			1,756,027	1,752,923
Less cost of fuel and purchased power		132,069		64,460
Gross Margin (non-GAAP)		$	95,339	$	109,679

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Three Months Ended March 31,	Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)				Quantities Sold (MWh)(a)
	2021		2020		2021		2020		2021	2020
Colorado Electric	$	79,741	$	58,558	$	24,091	$	32,270	606,343	550,771
South Dakota Electric	95,336		71,611		49,550		55,624		657,779	685,224
Wyoming Electric	52,331		43,970		21,698		21,785		491,905	516,928
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold	$	227,408	$	174,139	$	95,339	$	109,679	1,756,027	1,752,923

________________

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


	Three Months Ended March 31,
Quantities Generated and Purchased (MWh)		2021	2020

Generated:
Coal		482,978	547,829
Natural Gas and Oil		132,105	167,744
Wind		62,295	73,550
Total Generated		677,378	789,123
Purchased		1,078,649	963,800
Total Generated and Purchased		1,756,027	1,752,923


	Three Months Ended March 31,
Quantities Generated and Purchased (MWh)		2021	2020
Generated:
Colorado Electric		90,256	94,051
South Dakota Electric		434,322	472,966
Wyoming Electric		152,800	222,106
Total Generated		677,378	789,123

Purchased:
Colorado Electric		516,087	456,720
South Dakota Electric		223,457	212,258
Wyoming Electric		339,105	294,822
Total Purchased		1,078,649	963,800

Total Generated and Purchased		1,756,027	1,752,923


	Three Months Ended March 31,
	2021			2020
Heating Degree Days	Actual	Variance from Normal		Actual	Variance from Normal

Colorado Electric	2,731	3	%	2,456	(7)	%
South Dakota Electric	3,324	3	%	3,111	(3)	%
Wyoming Electric	3,261	8	%	2,999	(1)	%
Combined (a)	3,040	4	%	2,789	(4)	%

____________________

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

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	Three Months Ended March 31,
Contracted generating facilities availability by fuel type (a)		2021		2020
Coal (b)		83.7	%	90.8	%
Natural Gas and diesel oil (b) (c)		87.6	%	83.5	%
Wind		93.5	%	99.0	%
Total availability		87.2	%	87.1	%

Wind capacity factor		43.1	%	45.6	%

____________________

(a) Availability and wind capacity factor are calculated using a weighted average based on capacity of our generating fleet.

(b) 2021 included a planned outage at Wygen II and unplanned outages at Neil Simpson II and Pueblo Airport Generation.

Gas Utilities

Operating results for the Gas Utilities were as follows (in thousands):


	Three Months Ended March 31,
		2021		2020		Variance
Revenue:
Natural gas - regulated		$	378,077	$	335,897	$	42,180
Other - non-regulated services		24,442		24,876		(434)
Total revenue		402,519		360,773		41,746

Cost of sales:
Natural gas - regulated		182,967		153,999		28,968
Other - non-regulated services		10,083		1,363		8,720
Total cost of sales		193,050		155,362		37,688

Gross margin (non-GAAP)		209,469		205,411		4,058

Operations and maintenance		82,200		77,293		4,907
Depreciation and amortization		25,175		25,221		(46)
Total operating expenses		107,375		102,514		4,861

Adjusted operating income		$	102,094	$	102,897	$	(803)

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

Gross margin for the three months ended March 31, 2021 increased as a result of:


	(in millions)
New rates	$	9.2
Weather	7.5
Black Hills Energy Services Winter Storm Uri costs (a)	(8.2)
Non-utility Gas Supply Services	(1.2)
Mark-to-market on non-utility natural gas commodity contracts	(0.4)
Other	(2.8)
Total increase in Gross margin (non-GAAP)	$	4.1

__________

(a) Black Hills Energy Services offers fixed contract pricing for non-regulated gas supply services to our regulated natural gas customers. The increased cost of natural gas sold during Winter Storm Uri is not recoverable through a regulatory mechanism.

Operations and maintenance expense increased primarily due to $5.5 million of higher employee related costs and outside services expenses driven by higher headcount and higher stock compensation expense related to market performance partially offset by $1.0 million of lower travel and training expenses.

Depreciation and amortization was comparable to the same period in the prior year due to lower depreciation rates approved in the Nebraska Gas and Colorado Gas rate reviews mostly offset by increased depreciation due to a higher asset base driven by prior year capital expenditures.

Operating Statistics



	Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)				Quantities Sold & Transported (Dth)
	Three Months Ended March 31,				Three Months Ended March 31,				Three Months Ended March 31,
	2021		2020		2021		2020		2021	2020

Residential	$	234,397	$	207,231	$	110,148	$	103,121	30,568,738	28,230,795
Commercial	91,089		80,236		35,484		33,519		13,812,321	12,834,803
Industrial	4,902		5,200		1,789		2,043		898,289	1,061,052
Other	(472)		(1,242)		(472)		(1,242)		—	—
Total Distribution	329,916		291,425		146,949		137,441		45,279,348	42,126,650

Transportation and Transmission	48,161		44,472		48,161		44,457		45,314,438	45,055,507

Total Regulated	378,077		335,897		195,110		181,898		90,593,786	87,182,157

Non-regulated Services	24,442		24,876		14,359		23,513

Total Gas Revenue & Gross Margin (non-GAAP)	$	402,519	$	360,773	$	209,469	$	205,411

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	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,
	2021		2020		2021		2020		2021	2020

Arkansas Gas	$	86,994	$	74,845	$	51,949	$	48,855	13,306,734	10,962,948
Colorado Gas	79,122		72,606		38,212		38,006		13,366,015	13,096,405
Iowa Gas	56,754		54,824		22,631		21,328		14,313,973	14,280,273
Kansas Gas	40,063		33,494		18,766		18,603		10,462,797	9,914,858
Nebraska Gas	93,098		83,666		49,932		51,666		27,284,101	26,509,036
Wyoming Gas	46,488		41,338		27,979		26,953		11,860,166	12,418,637
Total Gas Revenue & Gross Margin (non-GAAP)	$	402,519	$	360,773	$	209,469	$	205,411	90,593,786	87,182,157



	Three Months Ended March 31,
	2021		2020
Heating Degree Days:	Actual	Variance from Normal	Actual	Variance from Normal
Arkansas Gas (a)	2,121	1%	1,659	(21)%
Colorado Gas	2,965	1%	2,829	(3)%
Iowa Gas	3,422	1%	3,181	(6)%
Kansas Gas (a)	2,576	5%	2,304	(7)%
Nebraska Gas	3,097	2%	2,835	(7)%
Wyoming Gas	3,425	7%	3,217	1%
Combined Gas (b)	3,186	3%	2,918	(6)%

__________

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

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

Regulatory Matters

For more information on recent regulatory activity and enacted regulatory provisions with respect to the states in which our Utilities operate, see Note 2 of the Notes to Condensed Consolidated Financial Statements and Part I, Items 1 and 2 and Part II, Item 8 of our 2020 Annual Report on Form 10-K.

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Power Generation

Our Power Generation segment operating results were as follows (in thousands):


	Three Months Ended March 31,
		2021		2020		Variance

Revenue		$	29,163	$	25,966	$	3,197

Fuel expense		2,671		2,285		386
Operations and maintenance		7,358		6,997		361
Depreciation and amortization		4,865		5,335		(470)
Total operating expense		14,894		14,617		277

Adjusted operating income		$	14,269	$	11,349	$	2,920

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

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

Operating Statistics


	Revenue (in thousands)				Quantities Sold (MWh) (a)
Three Months Ended March 31,	2021		2020		2021	2020
Black Hills Colorado IPP	$	14,254	$	14,179	239,194	265,225
Black Hills Wyoming (b)	13,433		10,158		164,957	156,352
Black Hills Electric Generation	1,476		1,629		96,294	97,279
Total Power Generation Revenue and Quantities Sold	$	29,163	$	25,966	500,445	518,856


		Three Months Ended March 31,
Quantities Generated and Purchased (MWh) (a)	Fuel Type		2021	2020
Generated
Black Hills Colorado IPP	Natural Gas		239,194	265,225
Black Hills Wyoming (b)	Coal		136,104	126,485
Black Hills Electric Generation	Wind		96,294	97,279
Total Generated			471,592	488,989

Purchased
Black Hills Wyoming (b)	Various		29,567	29,856
Total Purchased			29,567	29,856

____________

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

(b) Under the 20-year economy energy PSA with the City of Gillette effective September 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 that Black Hills Wyoming has with South Dakota Electric to cover energy imbalances.

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	Three Months Ended March 31,
Contracted generating facilities availability by fuel type (a)		2021		2020

Coal (b)		97.0	%	89.3	%
Natural gas		98.6	%	99.5	%
Wind		94.2	%	99.3	%
Total availability		96.7	%	97.8	%

Wind capacity factor		32.6	%	30.4	%

____________________

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

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

Mining

Our Mining segment operating results were as follows (in thousands):


	Three Months Ended March 31,
		2021		2020		Variance

Revenue		$	14,672	$	15,205	$	(533)

Operations and maintenance		9,197		9,826		(629)
Depreciation, depletion and amortization		2,214		2,250		(36)
Total operating expenses		11,411		12,076		(665)

Adjusted operating income		$	3,261	$	3,129	$	132

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

Adjusted operating income was comparable to the same period in the prior year.

Operating Statistics

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


	Three Months Ended March 31,
		2021		2020
Tons of coal sold		875		896
Cubic yards of overburden moved		1,822		2,267

Revenue per ton		$	16.09	$	16.08

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Corporate and Other

Corporate and Other operating results were as follows (in thousands):


	Three Months Ended March 31,
		2021		2020		Variance

Adjusted operating income (loss)		$	(3,122)	$	160	$	(3,282)

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

The variance in Adjusted operating income (loss) was primarily due to a prior year favorable true-up of employee costs which was allocated to our subsidiaries in the current year. This allocation was offset in our reportable segments and had no impact to consolidated results.

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


	Three Months Ended March 31,
	2021		2020		Variance
	(in thousands)
Interest expense, net	$	(37,600)	$	(35,453)	$	(2,147)
Impairment of investment	—		(6,859)		$	6,859
Other income (expense), net	266		2,353		$	(2,087)
Income tax (expense)	(494)		(16,002)		$	15,508

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

Interest Expense

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

Impairment of Investment

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

Other Income (Expense)

The decrease in Other income was primarily due to prior year credits for our non-qualified benefit plan driven by market performance on plan assets.

Income Tax (Expense)

For the three months ended March 31, 2021, the effective tax rate was 0.5% compared to 14.1% for the same period in 2020. The lower effective tax rate is primarily due to $7.6 million of increased tax benefits from Colorado Electric’s TCJA-related bill credits to customers (which is offset by reduced revenue), $1.5 million of increased tax benefits from amortization of excess deferred income taxes and $1.3 million of increased tax benefits from federal production tax credits associated with new wind assets.

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Liquidity and Capital Resources

There have been no material changes in Liquidity and Capital Resources from those reported in Item 7 of our 2020 Annual Report on Form 10-K except as described below.

For the three months ended March 31, 2021, we did not experience significant impacts to our liquidity or financial condition due to the COVID-19 pandemic.

In response to the February 2021 Winter Storm Uri, we took steps to maintain adequate liquidity to operate our businesses and fund our capital investment program as discussed in the Recent Developments above and in further detail in Note 5 of the Notes to Condensed Consolidated Financial Statements.

Cash Flow Activities

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


Cash provided by (used in):	2021		2020		Variance
Operating activities	$	(386,086)	$	191,969	$	(578,055)
Investing activities	$	(146,224)	$	(173,084)	$	26,860
Financing activities	$	539,496	$	25,621	$	513,875

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

Operating Activities:

Net cash provided by operating activities was $578 million lower than the same period in 2020. The variance to the prior year was primarily attributable to:

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

•Net inflows from changes in certain operating assets and liabilities were $563 million lower, primarily attributable to:

◦Cash outflows increased by $560 million as a result of changes in our regulatory assets and liabilities primarily driven by incremental costs from Winter Storm Uri;

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

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

•Cash inflows increased by $0.8 million for other operating activities.

Investing Activities:

Net cash used in investing activities was $27 million lower than the same period in 2020. The variance to the prior year was primarily attributable to:

•Capital expenditures of $146 million for the three months ended March 31, 2021 compared to $172 million for the same period in the prior year. Lower current year expenditures are driven by lower programmatic safety, reliability and integrity spending at our Gas Utilities and Electric Utilities segments and the prior year Corriedale wind project at our Electric Utilities segment.

•Cash outflows decreased by $1.3 million for other investing activities.

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Financing Activities:

Net cash provided by financing activities was $514 million higher than the same period in 2020. The variance to the prior year was primarily attributable to:

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

•Cash inflows decreased $99 million due to the prior year issuance of common stock;

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

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

Capital Sources

Term Loan

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

Revolving Credit Facility and CP Program

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


		Current		Short-term borrowings at		Letters of Credit (a) at		Available Capacity at
Credit Facility	Expiration	Capacity		March 31, 2021		March 31, 2021		March 31, 2021
Revolving Credit Facility and CP Program	July 30, 2023	$	750	$	216	$	17	$	517

__________

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

The weighted average interest rate on short-term borrowings related to our Revolving Credit Facility and CP Program at March 31, 2021 was 0.23%. Short-term borrowing activity related to our Revolving Credit Facility and CP Program for the three months ended March 31, 2021 was:


	(dollars in millions)
Maximum amount outstanding (based on daily outstanding balances)	$	311
Average amount outstanding (based on daily outstanding balances)	$	199
Weighted average interest rates	0.24		%

Covenant Requirements

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

Future Financing Plans

We will continue to assess debt and equity needs to support our capital investment plans and other key strategic objectives. In 2021, we expect to fund our capital plan and strategic objectives by using cash generated from operating activities, our Revolving Credit Facility and CP Program, and issuing $100 million to $120 million of common stock under the ATM. As discussed in the Recent Developments above and in further detail in Note 5 of the Notes to Condensed Consolidated Financial Statements, on February 24, 2021, we entered into an $800 million term loan maturing on November 24, 2021. We expect to refinance a portion of the term loan with longer-term debt.

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Credit Ratings

After assessing the current operating performance, liquidity and the credit ratings of the Company, management believes that the Company will have access to the capital markets at prevailing market rates for companies with comparable credit ratings.

The following table represents the credit ratings and outlook and risk profile of BHC at March 31, 2021:


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

__________

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

(b) On December 21, 2020, Moody’s reported Baa2 rating and maintained a Stable outlook.

The following table represents the credit ratings of South Dakota Electric at March 31, 2021:


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

__________

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

(b) On December 21, 2020, Moody’s reported A1 rating.

Capital Requirements

Capital Expenditures


	Actual		Forecasted
Capital Expenditures by Segment	Three Months Ended March 31, 2021 (a)		2021 (b)		2022		2023		2024		2025
(in millions)
Electric Utilities	$	52	$	240	$	180	$	143	$	156	$	154
Gas Utilities	73		377		347		339		330		326
Power Generation	3		10		9		6		4		5
Mining	1		9		9		9		9		10
Corporate and Other	3		11		5		13		13		13
Incremental Projects (c)	—		—		50		100		100		100
	$	132	$	647	$	600	$	610	$	612	$	608

__________

(a) Includes accruals for property, plant and equipment as disclosed in supplemental cash flow information in the Con densed Consolidat ed Statements of Cash Flows in the Condensed Consolidated Financial Statements.

(b) Includes actual capital expenditures for the three months ended March 31, 2021.

Dividends

Dividends paid on our common stock totaled $36 million for the three months ended March 31, 2021, or $0.565 per share per quarter. On April 26, 2021, our board of directors declared a quarterly dividend of $0.565 per share payable June 1, 2021, equivalent to an annual dividend of $2.26 per share. The amount of any future cash dividends to be declared and paid, if any, will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our Revolving Credit Facility and our future business prospects.

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Unconditional Purchase Obligations

See Note 3 of the Notes to Condensed Consolidated Financial Statements for recent updates to our purchase obligations.

Critical Accounting Policies Involving Significant Estimates

There have been no material changes in our critical accounting estimates from those reported in our 2020 Annual Report on Form 10-K. We continue to closely monitor the impacts of COVID-19 and Winter Storm Uri on our critical accounting estimates including, but not limited to, collectibility of customer receivables, recoverability through regulatory assets, impairment risk of goodwill and long-lived assets, valuation of pension assets and liabilities, and contingent liabilities. For more information on our critical accounting estimates, see Part II, Item 7 of our 2020 Annual Report on Form 10-K.

New Accounting Pronouncements

Other than the pronouncements reported in our 2020 Annual Report on Form 10-K 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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes to our quantitative and qualitative disclosures about market risk previously disclosed in Item 7A of our Annual Report on Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of March 31, 2021. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at March 31, 2021.

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

Changes in Internal Control over Financial Reporting

During the quarter ended March 31, 2021, there have been no changes in our internal controls over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS

For information regarding legal proceedings, see Note 3 in Item 8 of our 2020 Annual Report on Form 10-K and Note 3 in Item 1 of Part I of this Quarterly Report on Form 10-Q.

ITEM 1A.RISK FACTORS

There are no material changes to the risk factors previously disclosed in Item 1A of Part I in our 2020 Annual Report on Form 10-K.

ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table contains monthly information about our acquisitions of equity securities for the three months ended March 31, 2021:


Period	Total Number of Shares Purchased (a)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
January 1, 2021 - January 31, 2021	116.0	$	60.06	—	—
February 1, 2021 - February 28, 2021	11,696.0	61.92		—	—
March 1, 2021 - March 31, 2021	1.4	59.86		—	—









Total	11,813	$	61.90	—	—

_____________

(a) Shares were acquired under the share withholding provisions of the Omnibus Incentive Plan for payment of taxes associated with the vesting of various equity compensation plans.

ITEM 4. MINE SAFETY DISCLOSURES

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

ITEM 6. EXHIBITS

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


Exhibit Number			Description










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).
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).
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).
4.1.1			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).
4.1.2			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).
4.1.3			Third Supplemental Indenture dated as of July 16, 2010 (filed as Exhibit 4 to Registrant’s Form 8-K filed on July 15, 2010).

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4.1.4			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).
4.1.5			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).
4.1.6			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).
4.1.7			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).
4.1.8			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).
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)).
4.2.1			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)).
4.2.2			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)).
4.2.3			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).
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).
4.3.1			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).
4.3.2			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).
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).
10.1			Credit Agreement dated as of February 24, 2021 among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and U.S. Bank National Association, as Administrative Agent (filed as Exhibit 10.1 to the Registrant’s Form 8–K filed on February 25, 2021).
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.
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.
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.
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.
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)

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 5, 2021