GLOSSARY OF TERMS AND ABBREVIATIONS

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



AFUDC			Allowance for Funds Used During Construction
~~ALJ~~			~~Administrative Law Judge~~
AOCI			Accumulated Other Comprehensive Income (Loss)

Arkansas Gas			Black Hills Energy Arkansas, Inc., ~~a direct,~~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~~

ASC			Accounting Standards Codification
ASU			Accounting Standards Update issued by the FASB
ATM			At-the-market equity offering program
~~Availability~~
Availability			The availability factor of a power plant is the percentage of the time that it is available to provide energy.
~~BHC~~
BHC			Black Hills Corporation; the Company



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












Black Hills Energy Services			Black Hills Energy Services Company, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas commodity supply for the Choice Gas Programs (doing business as Black Hills Energy).
Black Hills Non-regulated Holdings			Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Power			Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy). Also known as South Dakota Electric.
Black Hills Utility Holdings			Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills Wyoming			Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
~~Busch Ranch I~~			~~29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and Black Hills Electric Generation, each having a 50% ownership interest in the wind farm.~~
~~Busch Ranch II~~			~~60 MW wind farm near Pueblo, Colorado, built by Black Hills Electric Generation to provide wind energy to Colorado Electric through a power purchase agreement expiring in November 2044.~~
~~CAPP~~			Customer Appliance Protection Plan, which provides appliance repair services to residential natural gas customers through on-going monthly service agreements. The consolidation of the existing Service Guard and CAPP plans into the revamped Service Guard Comfort Plan is currently underway across our service territories.
~~CARES Act~~			Coronavirus Aid, Relief, and Economic Security Act, signed on March 27, 2020, which is a tax and spending package intended to provide additional economic relief and address the impact of the COVID-19 pandemic.





Cheyenne Light			Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service in the Cheyenne, Wyoming area (doing business as Black Hills Energy). Also known as Wyoming Electric.
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).

~~Table of Contents~~



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

CP Program			Commercial Paper Program
CPUC			Colorado Public Utilities Commission
~~CVA~~

Table of Contents


CVA			Credit Valuation Adjustment
~~Dodd-Frank~~			~~Dodd-Frank Wall Street Reform and Consumer Protection Act~~
~~Dth~~
Dth			Dekatherm. A unit of energy equal to 10 therms or approximately one million British thermal units (MMBtu)
~~FASB~~





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




Heating Degree Day (HDD)			A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
~~HomeServe~~			~~Repair service plans offered to electric and natural gas residential customers that cover parts and labor to repair electrical, gas, heating, cooling, and water systems.~~
~~ICFR~~			~~Internal Controls over Financial Reporting~~
Iowa Gas			Black Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Iowa (doing business as Black Hills Energy).
IPP			Independent power producer
IRS			United States Internal Revenue Service

Kansas Gas			Black Hills Kansas Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Kansas (doing business as Black Hills Energy)
~~MMBtu~~KCC			Kansas Corporation Commission

LIBOR			London Interbank Offered Rate


MMBtu			Million British thermal units
~~Moody’s~~
Moody’s			Moody’s Investors Service, Inc.
MW			~~Megawatts~~
~~MWh~~MW			~~Megawatt-hours~~Megawatts
MWh			Megawatt-hours
Nebraska Gas			Black Hills Nebraska Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Nebraska (doing business as Black Hills Energy)
~~NPSC~~NOL			Net Operating Loss
NPSC			Nebraska Public Service Commission
~~OCI~~







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. The Corriedale wind project will provide 52.5 MW of energy for Renewable Ready subscribers~~customers in ~~Wyoming~~South Dakota and ~~western South Dakota.~~

~~Table of Contents~~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.
~~RMNG~~		Rocky Mountain Natural Gas LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas transmission and wholesale services in western Colorado (doing business as Black Hills Energy).
SDPUC		South Dakota Public Utilities Commission
SEC		United States Securities and Exchange Commission

Service Guard Comfort Plan		~~Home~~Appliance protection plan that provides home appliance repair ~~product offering for both natural gas and electric residential customers~~services through on-going monthly service ~~agreements. The consolidation of the existing Service Guard and CAPP plans into the revamped Service Guard Comfort Plan is currently underway across our service territories.~~agreements to residential utility customers.
~~Service Guard Comfort Plan~~S&P		~~New plan that will consolidate Service Guard and CAPP and provide similar services.~~
~~S&P~~	Standard and Poor’s, a division of The McGraw-Hill Companies, Inc.
South Dakota Electric		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).
~~Tech Services~~SSIR		~~Non-regulated product lines within Black Hills Corporation that 1) provide electrical system construction services to large industrial customers of our electric utilities~~System Safety and ~~2) serve gas transportation customers throughout its service territory by constructing and maintaining customer-owner gas infrastructure facilities, typically through one-time contracts.~~Integrity Rider

Table of Contents


TCJA			Tax Cuts and Jobs Act
~~Utilities~~
Utilities			Black Hills’ Electric and Gas Utilities
Wind Capacity Factor			Measures the amount of electricity a wind turbine produces in a given time period relative to its maximum potential
~~WPSC~~Winter Storm Uri			~~Wyoming Public Service Commission~~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~~
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			~~Wyodak, a~~The 362 MW mine-mouth, coal-fired ~~plant in~~generation facility near Gillette, Wyoming, jointly owned ~~80%~~ by PacifiCorp (80%) and ~~20% by Black Hills Energy~~ South ~~Dakota.~~Dakota Electric (20%). Our WRDC mine supplies all of the fuel for the ~~plant.~~facility.
Wyoming Electric			Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in the Cheyenne, Wyoming area (doing business as Black Hills Energy).
Wyoming Gas			Black Hills Wyoming Gas, LLC, an indirect and wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Wyoming (doing business as Black Hills Energy).

Table of Contents

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.

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


(unaudited)	Three Months Ended March 31,
		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		0		(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

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

Revenue $ 537,050
$ 597,810

Operating expenses:
Fuel, purchased power and cost of natural gas sold 187,879
249,742
Operations and maintenance 125,466
123,584
Depreciation, depletion and amortization 56,402
51,028
Taxes - property and production 14,118
13,325
Total operating expenses 383,865
437,679

Operating income 153,185
160,131

Other income (expense):
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) (35,781 ) (35,016 )
Interest income 328
299
Impairment of investment (6,859 ) —
Other income (expense), net 2,353
(789 )
Total other income (expense) (39,959 ) (35,506 )

Income before income taxes 113,226
124,625
Income tax (expense) (16,002 ) (17,263 )
Net income 97,224
107,362
Net income attributable to noncontrolling interest (4,050 ) (3,554 )
Net income available for common stock $ 93,174
$ 103,808

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

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

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

Table of Contents

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


(unaudited)	Three Months Ended March 31,
		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)		0		55
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $9 and $7, respectively)		(16)		(23)
Reclassification adjustments of benefit plan liability - net loss (net of tax of $(217) and $(95), respectively)		381		502
Derivative instruments designated as cash flow hedges:
Reclassification of net realized losses on settled/amortized interest rate swaps (net of tax of $(190) and $(170), respectively)		523		543
Net unrealized gains (losses) on commodity derivatives (net of tax of $(35) and $54, respectively)		107		(175)
Reclassification of net realized losses on settled commodity derivatives (net of tax of $(8) and $(115), respectively)		23		371
Other comprehensive income, net of 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

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

Net income $ 97,224
$ 107,362

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

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

See Note 119 for additional disclosures.

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

Table of Contents

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


(unaudited)	As of
	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

(unaudited) As of
March 31, 2020 December 31, 2019
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 54,137
$ 9,777
Restricted cash and equivalents 4,027
3,881
Accounts receivable, net 238,903
255,805
Materials, supplies and fuel 92,894
117,172
Derivative assets, current 1,780
342
Income tax receivable, net 22,319
16,446
Regulatory assets, current 49,415
43,282
Other current assets 26,198
26,479
Total current assets 489,673
473,184

Investments 15,250
21,929

Property, plant and equipment 6,808,261
6,784,679
Less: accumulated depreciation and depletion (1,223,979 ) (1,281,493 )
Total property, plant and equipment, net 5,584,282
5,503,186

Other assets:
Goodwill 1,299,454
1,299,454
Intangible assets, net 13,083
13,266
Regulatory assets, non-current 222,814
228,062
Other assets, non-current 24,258
19,376
Total other assets, non-current 1,559,609
1,560,158

TOTAL ASSETS $ 7,648,814
$ 7,558,457

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

Table of Contents

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Continued)


(unaudited)	As of
	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)	0		0

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

(unaudited) As of
March 31, 2020 December 31, 2019
(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 136,344
$ 193,523
Accrued liabilities 203,445
226,767
Derivative liabilities, current 852
2,254
Regulatory liabilities, current 54,345
33,507
Notes payable 319,125
349,500
Current maturities of long-term debt 5,743
5,743
Total current liabilities 719,854
811,294

Long-term debt, net of current maturities 3,136,887
3,140,096

Deferred credits and other liabilities:
Deferred income tax liabilities, net 387,939
360,719
Regulatory liabilities, non-current 504,149
503,145
Benefit plan liabilities 152,693
154,472
Other deferred credits and other liabilities 122,869
124,662
Total deferred credits and other liabilities 1,167,650
1,142,998

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

Equity:
Stockholders’ equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 62,772,978 and 61,480,658 shares, respectively 62,773
61,481
Additional paid-in capital 1,652,861
1,552,788
Retained earnings 838,841
778,776
Treasury stock, at cost – 24,656 and 3,956 shares, respectively (1,925 ) (267 )
Accumulated other comprehensive income (loss) (29,382 ) (30,655 )
Total stockholders’ equity 2,523,168
2,362,123
Noncontrolling interest 101,255
101,946
Total equity 2,624,423
2,464,069

TOTAL LIABILITIES AND TOTAL EQUITY $ 7,648,814
$ 7,558,457

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

Table of Contents

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

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

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

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

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

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

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


(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	0		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	0		99,321
Term loan - borrowings	800,000		0
Term loan - repayments	(200,000)		0
Net (payments) borrowings of Revolving Credit Facility and CP Program	(18,170)		(30,375)

Long-term debt - repayments	(1,436)		(4,291)
Distributions to noncontrolling interest	(4,644)		(4,741)
Other financing activities	(740)		(1,391)
Net cash provided by financing 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		0
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.

Table of Contents

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY


(unaudited)	Common Stock			Treasury Stock
(in thousands except share amounts)	Shares	Value		Shares	Value		Additional Paid in Capital		Retained Earnings		AOCI		Non controlling Interest		Total
December 31, 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

(unaudited) Common Stock Treasury Stock
(in thousands except share amounts) Shares Value Shares Value Additional Paid in Capital Retained Earnings AOCI Non controlling Interest Total
December 31, 2019 61,480,658
$ 61,481
3,956
$ (267 ) $ 1,552,788
$ 778,776
$ (30,655 ) $ 101,946
$ 2,464,069
Net income available for common stock —
—
—
—
—
93,174
—
4,050
97,224
Other comprehensive income, net of tax —
—
—
—
—
—
1,273
—
1,273
Dividends on common stock ($0.535 per share) —
—
—
—
—
(32,902 ) —
—
(32,902 )
Share-based compensation 69,378
69
20,700
(1,658 ) 2,263
—
—
—
674
Issuance of common stock 1,222,942
1,223
—
—
98,777
—
—
—
100,000
Issuance costs —
—
—
—
(967 ) —
—
—
(967 )
Implementation of ASU 2016-13 Financial Instruments -- Credit Losses —
—
—
—
—
(207 ) —
—
(207 )
Distributions to noncontrolling interest —
—
—
—
—
—
—
(4,741 ) (4,741 )
March 31, 2020 62,772,978
$ 62,773
24,656
$ (1,925 ) $ 1,652,861
$ 838,841
$ (29,382 ) $ 101,255
$ 2,624,423

Common Stock Treasury Stock
(in thousands except share amounts) Shares Value Shares Value Additional Paid in Capital Retained Earnings AOCI Non controlling Interest Total
December 31, 2018 60,048,567
$ 60,049
44,253
$ (2,510 ) $ 1,450,569
$ 700,396
$ (26,916 ) $ 105,835
$ 2,287,423
Net income (loss) available for common stock —
—
—
—
—
103,808
—
3,554
107,362
Other comprehensive income, net of tax —
—
—
—
—
—
457
—
457
Dividends on common stock ($0.505 per share) —
—
—
—
—
(30,332 ) —
—
(30,332 )
Share-based compensation 48,956
49
(20,497 ) 1,078
(589 ) —
—
—
538
Issuance of common stock 280,497
280
—
—
19,719
—
—
—
19,999
Issuance costs —
—
—
—
(289 ) —
—
—
(289 )
Implementation of ASU 2016-02 Leases —
—
—
—
—
3,390
—
—
3,390
Distributions to noncontrolling interest —
—
—
—
—
—
—
(4,846 ) (4,846 )
March 31, 2019 60,378,020
$ 60,378
23,756
$ (1,432 ) $ 1,469,410
$ 777,262
$ (26,459 ) $ 104,543
$ 2,383,702

Table of Contents

BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s ~~2019~~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 ~~2019~~2020 Annual Report on Form ~~10-K filed with the SEC.~~10-K.

Segment Reporting

We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation 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, ~~2020,~~2021, December 31, ~~2019~~2020 and March 31, ~~2019~~2020 financial information. Certain ~~industries~~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 electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our interim results of operations ~~for the three months ended March 31, 2020 and March 31, 2019, and our financial condition as of March 31, 2020 and December 31, 2019~~ are not necessarily indicative of the results of operations ~~and financial condition~~ to be expected for ~~any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.~~an entire year.

~~Reclassification~~

We changed certain classifications of operating expenses on the Consolidated Statements of Income for the three months ended March 31, 2019. Amounts previously reported as Operations and maintenance, Taxes - property and production, and Other operating expenses of ($0.3) million, ($0.3) million, and ($0.4) million, respectively, have been reclassified to Fuel, purchased power and cost of natural gas sold to conform with current year presentation. The prior year reclassifications did not impact previously reported operating income or net income.

COVID-19 Pandemic

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

~~Table of Contents~~

~~Change in Accounting Principle - Pension Accounting Asset Method~~

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

Recently Issued Accounting Standards

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.

Table of Contents

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. The new guidance is effective for interim and annual periods beginning after December 15, 2020 with early adoption permitted. We are currently reviewing this standard to assess the impact on our financial position, results of operations and cash flows.

~~Recently Adopted Accounting Standards~~

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

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

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

~~Simplifying the Test for Goodwill Impairment, ASU 2017-04~~

~~In January 2017, the FASB issued ASU 2017-04,~~ ~~Simplifying the Test for Goodwill Impairment~~ by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit. We adopted this standard prospectively on January 1, ~~2020.~~2021. Adoption of this ~~guidance is~~standard did not ~~expected to~~ have an impact on our financial position, results of operations or cash flows.

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

(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	$	0
Deferred energy and fuel cost adjustments (a) (b)	68,402		39,035
Deferred gas cost adjustments (a) (b)	17,066		3,200
Gas price derivatives (b)	324		2,226
Deferred taxes on AFUDC (c)	7,469		7,491
Employee benefit plans and related deferred taxes (d)	117,886		116,598
Environmental (b)	1,413		1,413

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

Deferred taxes on flow through accounting (d)	51,823		47,515
Decommissioning costs (c)	7,827		8,988
Gas supply contract termination (b)	1,013		2,524
Other regulatory assets (b)	25,806		26,404
Total regulatory 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 ~~FASB issued ASU 2018-15,~~ Notes to the Consolidated Financial Statements in our 2020 Annual Report on Form 10-K.

~~Customer's Accounting~~Table of Contents

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 ~~Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract~~, which aligns the requirements for recording implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software.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 ~~categories~~suppliers who have requested and received approval from FERC to delay billings.

Our Utilities have regulatory mechanisms to recover approximately $559 million of ~~implementation~~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 ~~previously~~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.

Table of Contents

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 ~~charged~~no significant changes to ~~expense as incurred are now capitalized as prepayments~~commitments, contingencies and ~~amortized over~~guarantees from those previously disclosed in Note 3 of our Notes to the ~~term~~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 ~~arrangement. We adopted this standard prospectively on January 1, 2020. Adoption~~end of ~~this guidance did not have~~2023. This agreement will expire 15 years after construction completion. The solar project represents Colorado Electric’s preferred bid in a ~~material impact on our financial position, results of operations or cash flows.~~competitive solicitation process completed in September 2020 through its Renewable Advantage plan.

Table of Contents

~~(2)~~(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 ~~reporting~~reportable segments for the three months ended March 31, ~~2020~~2021 and ~~2019.~~2020. Sales tax and other similar taxes are excluded from revenues.


Three Months Ended March 31, 2020	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues			Total
Three Months Ended March 31, 2021														Three Months Ended March 31, 2021	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues		Total
Customer types:	(in thousands)													Customer types:	(in thousands)
Retail	$	148,640	$	298,247	$	—	$	14,403	$	(7,839	)	$	453,451	Retail	$	198,500	$	341,605	$	0	$	14,083	$	(7,107)	$	547,081
Transportation	—		44,108		—		—		(139		)	43,969		Transportation	0		47,951		0		0		(110)		47,841
Wholesale	5,552		—		25,467		—		(23,612		)	7,407		Wholesale	5,922		0		28,692		0		(24,451)		10,163
Market - off-system sales	4,867		138		—		—		(2,639		)	2,366		Market - off-system sales	7,656		73		0		0		(2,884)		4,845
Transmission/Other	14,857		12,572		—		—		(4,413		)	23,016		Transmission/Other	15,193		10,390		0		0		(5,296)		20,287
Revenue from contracts with customers	$	173,916	$	355,065	$	25,467	$	14,403	$	(38,642	)	$	530,209	Revenue from contracts with customers	$	227,271	$	400,019	$	28,692	$	14,083	$	(39,848)	$	630,217
Other revenues	223		5,708		499		802		(391		)	6,841		Other revenues	137		2,500		471		589		(482)		3,215
Total revenues	$	174,139	$	360,773	$	25,966	$	15,205	$	(39,033	)	$	537,050	Total revenues	$	227,408	$	402,519	$	29,163	$	14,672	$	(40,330)	$	633,432

Timing of revenue recognition:														Timing of revenue recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	14,403	$	(7,839	)	$	6,564	Services transferred at a point in time	$	0	$	0	$	0	$	14,083	$	(7,107)	$	6,976
Services transferred over time	173,916		355,065		25,467		—		(30,803		)	523,645		Services transferred over time	227,271		400,019		28,692		0		(32,741)		623,241
Revenue from contracts with customers	$	173,916	$	355,065	$	25,467	$	14,403	$	(38,642	)	$	530,209	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	$	0	$	14,403	$	(7,839)	$	453,451
Transportation	0		44,108		0		0		(139)		43,969
Wholesale	5,552		0		25,467		0		(23,612)		7,407
Market - off-system sales	4,867		138		0		0		(2,639)		2,366
Transmission/Other	14,857		12,572		0		0		(4,413)		23,016
Revenue from contracts with customers	$	173,916	$	355,065	$	25,467	$	14,403	$	(38,642)	$	530,209
Other 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	$	0	$	0	$	0	$	14,403	$	(7,839)	$	6,564
Services transferred over time	173,916		355,065		25,467		0		(30,803)		523,645
Revenue from contracts with customers	$	173,916	$	355,065	$	25,467	$	14,403	$	(38,642)	$	530,209

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

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

~~Table of Contents~~

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 413. ~~We do not typically incur costs that would be capitalized to obtain or fulfill a revenue contract.~~

~~(3) Business Segment Information~~

Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States.

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

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

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

Table of Contents

(5) Financing

Three Months Ended March 31,
2020 2019
Adjusted operating income ^(a):

Electric Utilities $ 35,650
$ 41,020
Gas Utilities 102,897
103,314
Power Generation 11,349
11,967
Mining 3,129
4,337
Corporate and Other 160
(507 )
Operating income 153,185
160,131

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

~~__________~~


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

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

Total assets (net of inter-company eliminations) as of: March 31, 2020 December 31, 2019
Segment:
Electric Utilities $ 2,931,902
$ 2,900,983
Gas Utilities 4,043,539
4,032,339
Power Generation 412,572
417,715
Mining 80,289
77,175
Corporate and Other 180,512
130,245
Total assets $ 7,648,814
$ 7,558,457

Short-term debt

~~(4) Selected Balance Sheet Information~~

~~Accounts Receivable~~

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

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

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

~~Table of Contents~~

~~Materials, Supplies and Fuel~~

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

March 31, 2020 December 31, 2019
Materials and supplies $ 88,346
$ 82,809
Fuel - Electric Utilities 3,049
2,425
Natural gas in storage 1,499
31,938
Total materials, supplies and fuel $ 92,894
$ 117,172

~~Accrued Liabilities~~

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

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

~~Table of Contents~~

~~(5) Regulatory Matters~~

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

March 31, 2020 December 31, 2019
Regulatory assets
Deferred energy and fuel cost adjustments ^(a)
$ 35,687
$ 34,088
Deferred gas cost adjustments ^(a)
—
1,540
Gas price derivatives ^(a)
1,302
3,328
Deferred taxes on AFUDC^(b)
7,739
7,790
Employee benefit plans ^(c)
117,150
115,900
Environmental^(a)
1,439
1,454
Loss on reacquired debt^(a)
24,299
24,777
Renewable energy standard adjustment ^(a)
340
1,622
Deferred taxes on flow through accounting^(c)
44,589
41,220
Decommissioning costs ^(b)
10,248
10,670
Gas supply contract termination ^(a)
7,007
8,485
Other regulatory assets^(a)
22,429
20,470
Total regulatory assets 272,229
271,344
Less current regulatory assets (49,415 ) (43,282 )
Regulatory assets, non-current $ 222,814
$ 228,062

Regulatory liabilities
Deferred energy and gas costs^(a)
$ 40,002
$ 17,278
Employee benefit plan costs and related deferred taxes^(c)
41,518
43,349
Cost of removal^(a)
170,954
166,727
Excess deferred income taxes ^(c)
283,690
285,438
TCJA revenue reserve 5,147
3,418
Other regulatory liabilities^(c)
17,183
20,442
Total regulatory liabilities 558,494
536,652
Less current regulatory liabilities (54,345 ) (33,507 )
Regulatory liabilities, non-current $ 504,149
$ 503,145

~~__________~~


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


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


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

~~Table of Contents~~

~~Regulatory Activity~~

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

~~Black Hills Wyoming and Wyoming Electric~~

~~Wygen 1 FERC Filing~~

Black Hills Wyoming has a PPA with Wyoming Electric expiring on December 31, 2022, which provides 60 MW of unit-contingent capacity and energy from Black Hills Wyoming’s Wygen I facility. On August 2, 2019, Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for approval of a new 60 MW PPA. The agreement would fulfill Wyoming Electric’s capacity need at the expiration of the current agreement on December 31, 2022. If approved, Black Hills Wyoming will continue to deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and continuing for an additional 20 years to December 31, 2042. On February 21, 2020, the FERC set this filing for hearing. However, the hearing has been placed in abeyance pending a FERC monitored settlement process. Settlement negotiations are ongoing among all parties. Any settlement would require FERC approval. To the extent the parties are unable to reach agreement, the next step in FERC’s process would be to set the matter for hearing. We will continue to evaluate our options to fulfill Wyoming Electric’s 60 MW capacity need.

~~Colorado Gas~~

~~Jurisdictional Consolidation and Rate Review~~

On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate rates, tariffs, and services of its 2 existing gas distribution territories. The rate review requested $2.5 million in new revenue to recover investments in safety, reliability and system integrity. Colorado Gas also requested a new rider mechanism to recover future safety and integrity investments in its system. On December 27, 2019, the ALJ issued a recommended decision denying the company’s plan to consolidate rate territories and rider mechanism and also recommended a rate decrease. On April 14, 2020, the CPUC deliberated on the ALJ’s recommended decision and filed exceptions to that decision. The CPUC essentially accepted the ALJ’s recommended decisions, except for return on equity, which they lowered from 9.5% to 9.2%. A final order and new rates are anticipated to be effective in the second quarter of 2020.

~~(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,
2020 2019

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

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

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

~~Table of Contents~~

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

Three Months Ended March 31,
2020 2019

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

~~(7)~~ ~~Notes Payable, Current Maturities and Debt~~

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

March 31, 2020 December 31, 2019
Balance Outstanding
Letters of Credit ^(a)
Balance Outstanding
Letters of Credit ^(a)
Revolving Credit Facility $ 165,000
$ 17,281
$ —
$ 30,274
CP Program 154,125
—
349,500
—
Total $ 319,125
$ 17,281
$ 349,500
$ 30,274


	March 31, 2021				December 31, 2020
	Balance Outstanding		Letters of Credit (a)		Balance Outstanding		Letters of Credit (a)
Term Loan	$	600,000	$	0	$	0	$	0
Revolving Credit Facility	0		16,629		0		24,730
CP Program	215,870		0		234,040		0
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.

~~For~~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 ~~three months ended~~incremental fuel, purchased power and natural gas costs from Winter Storm Uri. The term loan, which matures on November 24, 2021, has an interest rate based on LIBOR plus 75 basis points, carries 0 prepayment penalty and is subject to the same covenant requirements as our Revolving Credit Facility. We repaid $200 million of this term loan in the first quarter of 2021. The interest rate on term loan borrowings on March 31, ~~2020,~~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 ~~utilized a combination of~~are unable to refinance the remaining obligation, we believe it is probable that our ~~$750 million~~ current plans to manage liquidity would be sufficient to meet our obligations.

Revolving Credit Facility and CP Program ~~to meet our business needs and support our capital investment plan.~~

Our net short-term borrowings ~~(payments)~~related to our Revolving Credit Facility and CP Program during the three months ended March 31, ~~2020 were $(30)~~2021 decreased by $18 million. The weighted average interest rate on short-term borrowings related to our Revolving Credit Facility and CP Program ~~borrowings~~ at March 31, ~~2020~~2021 was ~~1.92% and 1.74%, respectively.~~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, ~~2020:~~2021:

As of March 31, 2021

Covenant Requirement

Consolidated Indebtedness to Capitalization Ratio

62.6%

Less than

65%

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

~~South Dakota Electric Series 94A Debt~~

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

Table of Contents

(6) Earnings Per Share

~~(8) Equity~~

~~February 2020 Equity Issuance~~

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

~~ATM Activity~~

Our ATM allows us to sell shares of our common stock with an aggregate value of up to $300 million. The shares may be offered from time to time pursuant to a sales agreement dated August 4, 2017. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. We did not issue any common shares during the three months ended March 31, 2020 under the ATM. During the three months ended March 31, 2019, we issued a total of 0.3 million shares of common stock under the ATM for proceeds of $20 million, net of $0.2 million in issuance costs.

~~(9)~~(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 ~~the COVID-19 pandemic,~~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 ~~our variable debt.~~future debt, including reduced access to liquidity during periods of extreme capital markets volatility, such as the 2008 financial crisis and the COVID-19 pandemic.

Credit Risk

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

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

Table of Contents

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

Although we did not experience material credit losses or customer defaults for the three months ended March 31, 2020, we are monitoring COVID-19 impacts and changes to customer load, consistency in customer payments, requests for deferred or discounted payments, and requests for changes to credit limits to quantify future financial impacts to the allowance for credit losses.

~~Table of Contents~~

Derivatives and Hedging Activity

Our derivative and hedging activities 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 108.

~~Utilities~~

The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ ~~generation~~generating facilities plants or those ~~plants~~facilities under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements) ~~and natural gas sold by our Gas Utilities,~~, expose our utility customers to ~~volatility in~~ natural gas ~~prices.~~price volatility. Therefore, as allowed or required by state ~~utility~~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 ~~utility~~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/or~~and sales during time frames ranging from April ~~2020~~2021 through ~~May 2022.~~August 2023. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price forward contracts to deliver gas to our Choice Gas Program customers. The ~~effective portion of the~~ gain or loss on these designated derivatives is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and reclassified into earnings in the ~~ineffective portion, if any,~~same period that the underlying hedged item is ~~reported~~recognized in ~~Fuel, purchased power and cost of natural gas sold.~~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, 2020		December 31, 2019				March 31, 2021		December 31, 2020
	Units	Notional Amounts	Maximum Term (months)^(a)	Notional Amounts	Maximum Term (months)^(a)		Units	Notional Amounts	Maximum Term (months) (a)	Notional Amounts	Maximum Term (months) (a)
Natural gas futures purchased	MMBtus	920,000	9	1,450,000	12	Natural gas futures purchased	MMBtus	0	0	620,000	3
Natural gas options purchased, net	MMBtus	—	0	3,240,000	3	Natural gas options purchased, net	MMBtus	0	0	3,160,000	3
Natural gas basis swaps purchased	MMBtus	790,000	9	1,290,000	12	Natural gas basis swaps purchased	MMBtus	0	0	900,000	3
Natural gas over-the-counter swaps, net ^(b)	MMBtus	4,620,000	26	4,600,000	24	Natural gas over-the-counter swaps, net (b)	MMBtus	3,590,000	29	3,850,000	17
Natural gas physical contracts, net ^(c)	MMBtus	1,104,725	12	13,548,235	12	Natural gas physical contracts, net (c)	MMBtus	3,107,817	12	17,513,061	22
Electric wholesale contracts ^(c)	MWh	195,825	9	—	0	Electric wholesale contracts (c)	MWh	183,025	9	219,000	12

__________


~~(a)~~	~~Term reflects the maximum forward period hedged.~~


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


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

(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, ~~2020,~~2021, the Company posted ~~$0.5~~$1.4 million related to such provisions, which is included in Other current assets on the Condensed Consolidated Balance Sheets.

Table of Contents

Derivatives by Balance Sheet Classification

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

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


	Balance Sheet Location	March 31, 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	0		(108)
Noncurrent commodity derivatives	Other deferred credits and other liabilities	0		0
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)		0
Total derivatives not designated as hedges		$	(905)	$	(118)

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

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

Derivatives Designated as ~~Hedges~~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, ~~2020~~2021 and ~~2019.~~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)

Three Months Ended March 31, Three Months Ended March 31,
2020 2019 2020 2019
Derivatives in Cash Flow Hedging Relationships Amount of (Gain)/Loss Recognized in OCI Income Statement Location Amount of Gain/(Loss) Reclassified from AOCI into Income
(in thousands) (in thousands)
Interest rate swaps $ 713
$ 713
Interest expense $ (713 ) $ (713 )
Commodity derivatives 257
(320 ) Fuel, purchased power and cost of natural gas sold (486 ) 554
Total $ 970
$ 393
$ (1,199 ) $ (159 )

~~Based on~~As of March 31, ~~2020 prices, a $0.3~~2021, $0.9 million ~~gain would~~of net losses related to our interest rate swaps and commodity derivatives are expected to be ~~realized, reported in pre-tax earnings and~~ reclassified from AOCI ~~during~~into earnings within the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

Table of Contents

Derivatives Not Designated as ~~Hedges~~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, ~~2020~~2021 and ~~2019.~~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

Three Months Ended March 31,
2020 2019
Derivatives Not Designated as Hedging Instruments Income Statement Location Amount of Gain/(Loss) on Derivatives Recognized in Income
(in thousands)
Commodity derivatives - Electric Fuel, purchased power and cost of natural gas sold $ 1,362
$ —
Commodity derivatives - Natural Gas Fuel, purchased power and cost of natural gas sold 766
25
$ 2,128
$ 25

As discussed above, financial instruments used in our regulated ~~utilities~~Gas Utilities are not designated as cash flow hedges. There is no earnings impact ~~for our Gas Utilities~~ because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory asset or Regulatory liability ~~accounts~~ related to the hedges in our Gas Utilities were ~~$1.3~~$0.3 million and ~~$3.3~~$2.2 million as of March 31, ~~2020~~2021 and December 31, ~~2019,~~2020, respectively. For our Electric Utilities, the unrealized gains and losses arising from these derivatives are recognized in the Condensed Consolidated Statements of Income.

~~(10)~~(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.

Table of Contents

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 ~~included~~ in our ~~2019~~2020 Annual Report on Form ~~10-K filed with the SEC.~~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	$	0	$	1,389	$	0	$	0	$	1,389
Commodity derivatives — Electric Utilities	$	0	$	564	$	0	$	0	$	564
Total	$	0	$	1,953	$	0	$	0	$	1,953

Liabilities:
Commodity derivatives — Gas Utilities	$	0	$	625	$	0	$	0	$	625
Commodity derivatives — Electric Utilities	$	0	$	1,944	$	0	$	0	$	1,944
Total	$	0	$	2,569	$	0	$	0	$	2,569

As of March 31, 2020
Level 1 Level 2 Level 3
Cash Collateral and Counterparty
Netting
Total
(in thousands)
Assets:
Commodity derivatives — Gas Utilities $ —
$ 1,949
$ —
$ (13 ) $ 1,936
Commodity derivatives — Electric Utilities —
1,362
—
—
1,362
Total $ —
$ 3,311
$ —
$ (13 ) $ 3,298

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


	As of December 31, 2020
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting		Total
	(in thousands)
Assets:
Commodity derivatives — Gas Utilities	$	0	$	2,504	$	0	$	(1,527)	$	977
Commodity derivatives — Electric Utilities	$	0	$	1,065	$	0	$	0	$	1,065
Total	$	0	$	3,569	$	0	$	(1,527)	$	2,042

Liabilities:
Commodity derivatives — Gas Utilities	$	0	$	2,675	$	0	$	(1,552)	$	1,123
Commodity derivatives — Electric Utilities	$	0	$	921	$	0	$	0	$	921
Total	$	0	$	3,596	$	0	$	(1,552)	$	2,044

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

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

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 1815 to the Consolidated Financial Statements included in our ~~2019~~2020 Annual Report on Form 10-K. ~~The Company has concluded that the market volatility associated with COVID-19 does not require interim re-measurement of our pension plan assets or defined benefit obligations. See~~

~~Note 12~~ ~~for additional information.~~

~~Nonrecurring Fair Value Measurement~~

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

Table of Contents

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, 2020 December 31, 2019

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


	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)~~	(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.


~~(11)~~	~~Other Comprehensive Income (Loss)~~

(9) Other Comprehensive Income

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

The following table details reclassifications out of AOCI and into ~~net~~Net income. The amounts in parentheses below indicate decreases to ~~net~~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,
2020 2019
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

(486 ) 554
(1,199 ) (159 )
Income tax Income tax benefit (expense) 285
35
Total reclassification adjustments related to cash flow hedges, net of tax $ (914 ) $ (124 )

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

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


	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)

Table of Contents

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	0		107		0		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	0		(175)		55		(120)
Amounts reclassified from AOCI	543		371		479		1,393
As of March 31, 2020	$	(14,579)	$	(260)	$	(14,543)	$	(29,382)

Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total
As of December 31, 2019 $ (15,122 ) $ (456 ) $ (15,077 ) $ (30,655 )
Other comprehensive income (loss)
before reclassifications —
(175 ) 55
(120 )
Amounts reclassified from AOCI 543
371
479
1,393
As of March 31, 2020 $ (14,579 ) $ (260 ) $ (14,543 ) $ (29,382 )

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

~~(12)~~(10) Employee Benefit Plans

~~Change in Accounting Principle - Pension Accounting Asset Method~~

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

We evaluated the effect of this change in accounting method and deemed it immaterial to the historical and current financial statements and therefore did not account for the change retrospectively. Accordingly, the Company calculated the cumulative difference using a calculated value versus fair value to determine market-related value for liability-hedging assets of the portfolio. The cumulative effect of this change, as of January 1, 2020, resulted in a decrease to prior service costs, as recorded in Other income (expense), net, of $0.6 million, an increase in Income tax expense of $0.2 million and an increase to Net income of $0.4 million within the accompanying Condensed Consolidated Statements of Income for the three months ended March 31, 2020.

~~Funding Status of Employee Benefit Plans~~

Based on the fair value of assets and estimated discount rate used to value benefit obligations as of March 31, 2020, we estimate the unfunded status of our employee benefit plans to be approximately $46 million compared to $51 million at December 31, 2019. The Company has concluded that the market volatility associated with COVID-19 does not require interim re-measurement of our pension plan assets or defined benefit obligations.

~~Table of Contents~~

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

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

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

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

Table of Contents

Supplemental Non-qualified Defined Benefit and Defined Contribution Plans

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


	Three Months Ended March 31,
		2021		2020
Service cost		$	693	$	(1,370)
Interest cost		177		275

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

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

~~Table of Contents~~

Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made in the first quarter of ~~2020~~2021 and anticipated contributions for ~~2020~~2021 and ~~2021~~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	$	0	$	0	$	3,788
Non-pension Defined Benefit Postretirement Healthcare Plan	$	1,382	$	4,145	$	5,241
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans	$	482	$	1,445	$	1,967

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

~~(13) Commitments and Contingencies~~

(11) Income Taxes

~~There have been~~

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 ~~significant~~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 ~~commitments and contingencies~~our valuation allowance against the state NOL carryforwards from ~~those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our~~ ~~2019~~ ~~Annual Report on Form 10-K except for those described below.~~

~~Future Purchase Agreement - Black Hills Wyoming and Wyoming Electric~~

~~(14) Income Taxes~~

~~CARES Act~~

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

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

~~Eligible wages or employer-paid health benefits must be paid for the period of time during which an employee~~Winter Storm Uri. Therefore, we did not ~~provide services. However, employees do not need to stop providing all services to~~record an additional valuation allowance against the ~~employer for the credit to potentially apply.~~

~~Additionally, the CARES Act accelerates the amount~~state NOL carryforwards as of ~~alternative minimum tax (“AMT”) credits that can be refunded for the 2018 and 2019 annual tax returns.~~

~~Based on the timing of the CARES Act, for the three months ended~~ March 31, 2020, the related tax benefits from the CARES Act were not material. We are currently reviewing the potential future benefits related to employee retention tax credits and the payroll tax deferral provision to assess the impact on our financial position, results of operations and cash flows.2021.

~~Table of Contents~~

Income ~~tax (expense) for the~~ Tax Benefit (Expense) and Effective Tax Rates

Three Months Ended March 31, ~~2020~~2021 Compared to the Three Months Ended March 31, ~~2019.~~2020

Income tax ~~benefit~~ (expense) for the three months ended March 31, ~~2020~~2021 was ~~$(16)~~$(0.5) million compared to ~~$(17)~~$(16) million reported for the same period in ~~2019.~~2020. For the three months ended March 31, ~~2020~~2021 the effective tax rate was ~~14.1%~~0.5% compared to ~~13.9%~~14.1% for the same period in ~~2019.~~2020. The ~~higher~~lower effective tax rate is primarily due to ~~a discrete tax adjustment related to the impairment~~$7.6 million of ~~our investment in equity securities of a privately held oil and gas company partially offset by~~ increased tax benefits from ~~forecasted~~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.

~~(15) Investments~~

Table of Contents

~~In February 2018, we contributed $28 million~~(12) Business Segment Information

Our reportable segments are based on our method of ~~assets~~internal reporting, which is generally segregated by differences in ~~exchange for equity securities in a privately held oil~~products, services and ~~gas company as we divested our Oil and Gas segment. The carrying value~~regulation. All of our ~~investment~~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	$	0	$	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	$	0	$	0	$	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	$	0	$	174,139
Gas Utilities	354,287		5,708		778		0		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	$	0	$	0	$	537,050

Table of Contents



	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		0		(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 ~~equity securities was recorded at cost. We review this investment on a periodic basis~~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 ~~determine whether a significant event or change in circumstances has occurred that may have an adverse effect on the value of the investment.~~

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

During the first quarter of 2020, we assessed our investment for impairment as a result of continued adverse changes in future natural gas prices and liquidity concerns at the privately held oil and gas company. We performed an internal analysis to compute the fair value of our investment, utilizing a consistent methodology as applied during the third quarter of 2019. Based on the results of the valuation, we concluded that the carrying value of the investment exceeded fair value. As a result, we recorded a pre-tax impairment loss of $6.9 millioncredit losses for the three months ended March 31, 2021 and 2020, ~~which was the difference between the carrying amount~~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 ~~the fair value of the investment at March 31, 2020.~~Fuel

The following ~~table presents~~amounts by major classification are included in Materials, supplies and fuel on the ~~carrying value of our investments~~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

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

~~(16) Subsequent Events~~

We evaluated all subsequent event activity and concluded that no subsequent events have occurred that would require recognition in the condensed consolidated financial statements or disclosures, with the exception of the Note 5 disclosure surrounding Colorado Gas’ jurisdictional consolidation and rate review.

There are many uncertainties regarding the COVID-19 pandemic, and the Company is closely monitoring the impact of the pandemic on all aspects of its business, including how it will impact its customers, employees, suppliers, vendors, and business partners. We are unable to predict the impact that COVID-19 will have on our financial position and operating results due to numerous uncertainties. The Company expects to continue to assess the evolving impact of COVID-19 and intends to make adjustments to its responses accordingly.

Table of Contents

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.~~

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

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

Executive Summary

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

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

~~Gas Utilities: Our Gas Utilities segment conducts~~ natural gas utility ~~operations through our~~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 subsidiaries. Our Gas Utilities segment distributes~~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 ~~transports~~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.

Table of Contents

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.

fuel cost recovery mechanisms. Black Hills Energy Services ~~provides~~offers fixed contract pricing for non-regulated gas supply services to our regulated natural gas ~~supply to approximately 49,000 retail distribution~~ customers ~~under~~and $8.2 million of increased cost of natural gas sold during Winter Storm Uri is not recoverable through the ~~Choice Gas Program in Nebraska and Wyoming.~~regulatory construct. Additionally, we ~~provide services under~~incurred $0.7 million of interest expense for the ~~Service Guard Comfort Plan and Tech Services and also offer HomeServe products.~~

~~Power Generation~~:three months ended March 31, 2021, related to our $800 million term loan. Our non-regulated Power Generation segment ~~produces electric power~~benefited from ~~its non-regulated generating plants~~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 ~~sells~~regulatory actions.

COVID-19 Update

For the ~~electric capacity and energy primarily~~three months ended March 31, 2021, we did not experience significant impacts to our ~~utilities under long-term contracts.~~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.

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

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.

~~Our reportable segments are based on our method~~

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 ~~internal reporting,~~renewable energy upon construction of a new solar facility, to be owned by TC Colorado Solar, LLC, which is ~~generally segregated~~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.

Table of Contents

Results of Operations

The segment information does not include inter-company eliminations. Minor differences in ~~products, services and regulation.~~amounts may result due to rounding. All of our operations and assets are located within the United States. All of our non-utility business segments support our utilities. Certain unallocated corporate expenses that support our operating segmentsamounts are presented ~~as Corporate and Other.~~

on a pre-tax basis unless otherwise indicated.

Certain ~~industries~~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, ~~2020~~2021 and ~~2019~~,2020, and our financial condition as of March 31, ~~2020~~2021 and December 31, ~~2019,~~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.

~~See~~ ~~Forward-Looking Information~~ ~~in the~~ ~~Liquidity and Capital Resources~~ ~~section of this Item 2, beginning on Page~~ 45.

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

~~Table of Contents~~

~~Results of Operations~~

~~COVID-19 Pandemic~~

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

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

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

We continue to maintain adequate liquidity to operate our businesses and fund our capital investment program. In February 2020, the Company issued $100 million in equity to support its 2020 capital investment program. For the three months ended March 31, 2020, the Company utilized a combination of its $750 million Revolving Credit Facility and CP Program to meet its funding requirements. In recent weeks, the liquidity for A-2/P-2 rated issuers, which is the Company’s current Commercial Paper rating with S&P and Moody’s, respectively, within the Commercial Paper market has improved which provides additional liquidity options under the Revolving Credit Facility. The Company has no material debt maturities until late 2023, and as of March 31, 2020, had $468 million of liquidity which included cash and available capacity on its Revolving Credit Facility. We also continue to monitor the funding status of our employee benefit plan obligations, which did not materially change during the first quarter 2020.

We are monitoring supply chains, including lead times for key materials and supplies, availability of resources, and status of large capital projects. To date, there have been limited impacts to supply chains including availability of supplies and materials and lead times. Capital projects are ongoing without material disruption to schedules. Our third party resources continue to support our business plans without disruption. Contingency plans are ongoing due to the impacts of COVID-19, including the potential for rescheduling projects. We currently do not anticipate a significant impact on our capital investment plan for 2020.

We continue to work closely with local health, public safety and government officials to minimize the spread of COVID-19 and minimize the impact to our employees and the service we provide to our customers. Some of the actions the Company has taken include implementing protocols for our field operations personnel to continue to safely and effectively interact with our customers, asking employees to work from home to the extent possible, quarantining employees if they had traveled to an at-risk area, limiting travel to only mission critical purposes and sequestering essential employees.

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

~~Increased residential load and decreased commercial and industrial demand;~~

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

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

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

~~Rate actions from our regulators;~~

~~Decreased training, travel and outside services related expenses;~~

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

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

~~Table of Contents~~

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

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

Consolidated Summary 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

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

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

(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, ~~2020~~2021 Compared to Three Months Ended March 31, ~~2019.~~2020

The variance to the prior year included the following:

•Electric Utilities’ adjusted operating income decreased ~~$5.4~~$14 million primarily due to ~~lower heating demand~~Colorado Electric’s TCJA-related bill credits to customers, impacts from ~~warmer winter weather, lower power marketing margins~~Winter Storm Uri and ~~higher operating expenses~~unfavorable mark-to-market adjustments on wholesale energy contracts partially offset by increased ~~mark-to-market on wholesale energy contracts~~rider revenues and ~~increased rider revenues;~~lower operating expenses;

•Gas Utilities’ adjusted operating income decreased ~~$0.4~~$0.8 million primarily due to ~~lower heating demand from warmer winter weather~~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 ~~amortization~~favorable true-up of ~~excess deferred income taxes, customer growth and increased mark-to-market on non-utility natural gas commodity contracts;~~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; ~~and~~

Table of Contents

•A ~~$3.1~~$2.1 million ~~increase~~decrease in other income primarily due to ~~reduced costs~~prior year credits for our non-qualified benefit plan driven by market performance on plan ~~assets.~~assets; and

~~Table of Contents~~•

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

Three Months Ended March 31,
2020 2019 Variance
Revenue
Revenue $ 576,083
$ 635,681
$ (59,598 )
Inter-company eliminations (39,033 ) (37,871 ) (1,162 )
$ 537,050
$ 597,810
$ (60,760 )
Adjusted operating income^(a)

Electric Utilities $ 35,650
$ 41,020
$ (5,370 )
Gas Utilities 102,897
103,314
(417 )
Power Generation 11,349
11,967
(618 )
Mining 3,129
4,337
(1,208 )
Corporate and Other 160
(507 ) 667
Operating income 153,185
160,131
(6,946 )

Interest expense, net (35,453 ) (34,717 ) (736 )
Impairment of investment (6,859 ) —
(6,859 )
Other income (expense), net 2,353
(789 ) 3,142
Income tax (expense) (16,002 ) (17,263 ) 1,261
Net income 97,224
107,362
(10,138 )
Net income attributable to noncontrolling interest (4,050 ) (3,554 ) (496 )
Net income available for common stock $ 93,174
$ 103,808
$ (10,634 )

~~__________~~


~~(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.

~~Business Segment Highlights and Corporate Activity~~

~~Electric Utilities Segment~~

~~On April 14, 2020, Colorado Electric submitted its 30-day report to the CPUC summarizing the first milestone~~A $15.5 million decrease in the Renewable Advantage Plan which is expected to provide cost savings to customers and double its renewable energy portfolio. The bidding process for new renewable energy projects concluded on February 15, 2020, attracting interest from developers in southern Colorado and across the U.S. In total, Colorado Electric received 54 bids from 25 bidders for renewable energy projects at varying sizes, prices, technology types and locations, with the majority of projects to be sited in Pueblo and Pueblo County. The winning bid(s) and pricing will be determined in June 2020 when Colorado Electric files its 120-day report to the CPUC.

Construction continues on the $79 million Corriedale project, which is expected to be placed in service by year-end 2020. As a result of COVID-19, we regularly communicate with our key suppliers to maintain visibility into any disruptions they are experiencing in the receipt of supplies and materials from their suppliers. At this time, we have not experienced significant disruption in our supply chainincome tax expense due to ~~COVID-19 which would cause us to adjust the in-service date for this project. If significant disruptions occur~~lower pre-tax income and ~~we were unable to complete the project~~a lower effective tax rate driven primarily by ~~December 31, 2020, we could experience loss~~tax benefits from Colorado Electric’s TCJA-related bill credits, amortization of excess deferred income taxes and federal production tax ~~credits.~~credits associated with new wind assets.

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

~~Table of Contents~~

~~Gas Utilities Segment~~

On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate rates, tariffs, and services of its two existing gas distribution territories. The rate review requested $2.5 million in new revenue to recover investments in safety, reliability and system integrity. Colorado Gas also requested a new rider mechanism to recover future safety and integrity investments in its system. On December 27, 2019, the ALJ issued a recommended decision denying the company’s plan to consolidate rate territories and rider mechanism and also recommended a rate decrease. On April 14, 2020, the CPUC deliberated on the ALJ’s recommended decision and filed exceptions to that decision. The CPUC essentially accepted the ALJ’s recommended decisions, except for return on equity, which they lowered from 9.5% to 9.2%. A final order and new rates are anticipated to be effective in the second quarter of 2020.

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

On January 1, 2020, Nebraska Gas completed the legal consolidation of its two natural gas utilities, having received approval from the NPSC on October 29, 2019. A rate review is expected to be filed mid-year 2020 to consolidate the rates, tariffs and services of its two utilities.

~~Power Generation Segment~~

On August 2, 2019, Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for approval of a new 60 MW PPA. If approved, Black Hills Wyoming will continue to deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and for 20 additional years. On February 21, 2020, the FERC set this filing for hearing. However, the hearing has been placed in abeyance pending a FERC monitored settlement process. See additional information in the Electric Utilities Segment ~~highlights above.~~

~~Corporate and Other~~

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

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

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

Operating Results

A discussion of operating results from our business segments and Corporate activities follows in the sections below. Revenues for operating segments in the following sections are presented in total and by retail class. For disaggregation of revenue by contract type and operating segment, see follows.

~~Note 2~~ ~~of the Notes to Condensed Consolidated Financial Statements for more information.~~

Non-GAAP Financial Measure

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

~~Table of Contents~~

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

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

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

Electric Utilities

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

Total fuel and purchased power 64,460
73,283
(8,823 )

Gross margin (non-GAAP) 109,679
109,644
35

Operations and maintenance 50,499
47,144
3,355
Depreciation and amortization 23,530
21,480
2,050
Total operating expenses 74,029
68,624
5,405

Adjusted operating income $ 35,650
$ 41,020
$ (5,370 )

~~Results of Operations~~Operating results for the Electric Utilities ~~for the~~ 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)

Table of Contents

Three Months Ended March 31, ~~2020~~2021 Compared to the Three Months Ended March 31, ~~2019:~~2020:

Gross margin for the three months ended March 31, ~~2020 did not change~~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)

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

(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 ~~increased~~decreased primarily due to ~~higher employee-related costs and higher generation~~prior year expenses ~~driven by timing of planned outages.~~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.

~~Table of Contents~~

Operating Statistics

Electric Revenue Quantities Sold
(in thousands) (MWh)
Three Months Ended
March 31, Three Months Ended
March 31,
2020 2019 2020 2019
Residential $ 54,505
$ 57,638
373,150
389,178
Commercial 57,823
60,963
494,308
505,573
Industrial 32,169
32,440
460,632
426,614
Municipal 3,878
4,139
36,399
36,636
Subtotal Retail Revenue - Electric 148,375
155,180
1,364,489
1,358,001
Contract Wholesale ^(a)
5,553
8,343
131,778
223,020
Off-system/Power Marketing Wholesale 4,867
6,692
165,785
140,850
Other 15,344
12,712
—
—
Total Revenue and Energy Sold 174,139
182,927
1,662,052
1,721,871
Other Uses, Losses or Generation, net ^(b)
—
—
90,871
97,000
Total Revenue and Energy 174,139
182,927
1,752,923
1,818,871
Less cost of fuel and purchased power 64,460
73,283

Gross Margin (non-GAAP) $ 109,679
$ 109,644


		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

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

~~________________~~


~~(a)~~	Revenue and purchased power for the three months ended March 31, 2020, as well as associated quantities, for certain wholesale contracts have been presented on a net basis. Amounts for the three months ended March 31, 2019 were presented on a gross basis and, due to their immaterial nature, were not revised. This presentation change has no impact on Gross margin.


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

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

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

~~Table of Contents~~

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

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

~~________________~~


~~(a)~~	Purchased power quantities for the three months ended March 31, 2020, for certain wholesale contracts have been presented on a net basis. Amounts for the three months ended March 31, 2019 were presented on a gross basis and, due to their immaterial nature, were not revised. This presentation change has no impact on Gross margin.

Table of Contents


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

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

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

~~____________________~~________________

(a) 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

~~(a)~~

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

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

Wind Capacity Factor 45.6 % 42.6 %

~~____________________~~

~~(a)~~

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

~~(b)~~

~~2020 included an unplanned outage at Pueblo Airport Generation.~~


	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.

Table of Contents


	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

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

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

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

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

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

~~Results of Operations~~Operating results for the Gas Utilities ~~for the~~ 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)

Table of Contents

Three Months Ended March 31, ~~2020~~2021 Compared to the Three Months Ended March 31, ~~2019:~~2020

Gross margin for the three months ended March 31, ~~2020~~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

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

(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 ~~primarily~~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

Table of Contents

~~Operating Statistics~~

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

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

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

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

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

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



	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

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

Gas Utilities Quantities Sold & Transported (Dth)

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

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

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

~~Table of Contents~~

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

~~__________~~


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

~~(b)~~

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



	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 52 of the Notes to Condensed Consolidated Financial Statements and Part I, Items 1 and 2 and Part II, Item 8 of our ~~2019~~2020 Annual Report on Form ~~10-K filed with the SEC.~~10-K.

Table of Contents

Power Generation

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

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

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

~~Results of Operations for~~Our Power Generation ~~for the~~ 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, ~~2020~~2021 Compared to the Three Months Ended March 31, ~~2019:~~2020:

~~Revenue~~Operating income increased ~~in the current year driven by an increase in MWh sold~~$1.7 million due to ~~new wind assets and additional~~Winter Storm Uri’s favorable impact to Black Hills ~~Colorado IPP fired-engine hours. Operating expenses~~Wyoming under the economy energy PSA. Revenue also increased ~~in the current year primarily~~ due to higher ~~maintenance expense and depreciation from new wind assets.~~Wygen I MWh sold driven by a prior year planned outage.

~~The following table summarizes MWh for our Power Generation segment:~~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,
2020 2019
Quantities Sold, Generated and Purchased
(MWh) ^(a)

Sold
Black Hills Colorado IPP 265,225
205,973
Black Hills Wyoming ^(b)
156,352
164,049
Black Hills Electric Generation 97,279
33,753
Total Sold 518,856
403,775

Generated
Black Hills Colorado IPP 265,225
205,973
Black Hills Wyoming ^(b)
126,485
132,593
Black Hills Electric Generation 97,279
33,753
Total Generated 488,989
372,319

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

~~____________~~

~~(a)~~

~~Company uses and losses are not included in the quantities sold, generated, and purchased.~~


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

Three Months Ended March 31,
Contracted Power Plant Fleet Availability ^(a)
2020 2019

Coal-fired plant ^(b)
89.3 % 94.8 %
Natural gas-fired plants 99.5 % 95.6 %
Wind 99.3 % 90.4 %
Total Availability 97.8 % 94.1 %

Wind Capacity Factor 30.4 % 28.2 %

~~____________________~~


~~(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.~~


		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.

Table of Contents


	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

Three Months Ended March 31,

2020 2019 Variance

(in thousands)
Revenue $ 15,205
$ 16,429
$ (1,224 )

Operations and maintenance 9,826
9,913
(87 )
Depreciation, depletion and amortization 2,250
2,179
71
Total operating expenses 12,076
12,092
(16 )

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

~~Results of Operations for Mining for the~~

Three Months Ended March 31, ~~2020~~2021 Compared to the Three Months Ended March 31, ~~2019:~~2020:

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

Current year revenue decreased due to 10% fewer tons sold driven primarily by decreased demand at the Wyodak Plant and timing of planned spring outages at our coal-fired generation facilities partially offset by an increase in price per ton sold driven by contract price adjustments based on actual mining costs.

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

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

Revenue per ton $ 16.08
$ 15.87

Table of Contents

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.

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

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

~~Consolidated Interest expense, Impairment of investment, Other income (expense) and Income tax (expense) for the~~ Three Months Ended March 31, ~~2020~~2021 Compared to the Three Months Ended March 31, ~~2019.~~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

~~For~~In the ~~three months ended March 31, 2020,~~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. ~~The remaining book value of our investment is $1.5 million, and this is our only remaining investment in oil and gas exploration and production activities. See~~ ~~Note 15~~ ~~of the Notes to Condensed Consolidated Financial Statements for additional details.~~

Other Income (Expense)

The ~~increase~~decrease in Other income ~~for the three months ended March 31, 2020, compared to the same period in the prior year~~ was primarily due to ~~reduced costs~~prior year credits for our non-qualified benefit plan ~~which are~~ driven by market performance on plan assets.

Income Tax (Expense)

For the three months ended March 31, ~~2020,~~2021, the effective tax rate was ~~14.1%~~0.5% compared to ~~13.9%~~14.1% for the same period in ~~2019.~~2020. The ~~higher~~lower effective tax rate is primarily due to ~~a discrete tax adjustment related to the impairment~~$7.6 million of ~~our investment in equity securities of a privately held oil and gas company partially offset by~~ increased tax benefits from ~~forecasted~~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.

~~Critical Accounting Policies Involving Significant Accounting Estimates~~

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

~~Pension and Other Postretirement Benefits~~

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

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

~~See~~

~~Note 12~~Table of ~~the Notes to Condensed Consolidated Financial Statements for additional information.~~Contents

Liquidity and Capital Resources

There have been no material changes in Liquidity and Capital Resources from those reported in Item 7 of our ~~2019~~2020 Annual Report on Form 10-K ~~filed with the SEC~~ except as described ~~below and within the “COVID-19 Pandemic” discussion in the Results of Operations section above.~~below.

~~Collateral Requirements~~

Our utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas which have performance assurance provisions that allow the counterparty to require collateral postings under certain conditions, including when requested on a reasonable basis due to a deterioration in our financial condition or nonperformance. A significant downgrade in our credit ratings, such as a downgrade to a level below investment grade, could result in counterparties requiring collateral postings under such adequate assurance provisions. The amount of credit support that we may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions and the amounts owed by or to the counterparty. At March 31, 2020, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts. For the three months ended March 31, ~~2020,~~2021, we did not experience ~~any requests~~significant impacts to ~~post additional collateral, including for concerns over a potential deterioration of~~ our liquidity or financial condition due to ~~COVID-19.~~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, ~~2020~~ (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

Cash provided by (used in): 2020 2019 Variance
Operating activities $ 191,969
$ 175,893
$ 16,076
Investing activities $ (173,084 ) $ (145,027 ) $ (28,057 )
Financing activities $ 25,621
$ (39,292 ) $ 64,913

~~Table of Contents~~

Three Months Ended March 31, ~~2020~~2021 Compared to Three Months Ended March 31, ~~2019~~2020

Operating ~~Activities~~Activities:

Net cash provided by operating activities was ~~$192~~$578 million ~~for the three months ended March 31, 2020, compared to net cash provided by operating activities of $176 million for~~lower than the same period in ~~2019 for an increase of $16 million.~~2020. The variance to the prior year was primarily attributable to:

•Cash earnings (net income plus non-cash adjustments) were $4$15 million lower for the three months ended March 31, ~~2020~~2021 compared to the same period in the prior year primarily driven by lower operating income at ~~the~~our Electric ~~Utilities and Mining segments;~~Utilities;

•Net ~~cash~~ inflows from changes in certain operating assets and liabilities were ~~$5.0~~$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, ~~2020,~~2021 compared to ~~net cash outflows of $15 million in the same period in the prior year. This $20 million increase was primarily due to:~~


◦	Cash inflows increased by $14 million primarily as a result of decreases in natural gas in storage and higher collections of accounts receivable partially offset by increased materials and supplies purchases;


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


◦	~~Cash inflows increased by $11 million primarily as a result of changes in our current regulatory assets driven by the timing of recovery from fuel cost adjustments; and~~


◦	~~Net cash outflows increased by $2.9 million from other operating activities primarily due to higher employee benefits costs and outside services.~~

~~Investing Activities~~

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

~~Capital expenditures of~~ $172 ~~million for the three months ended March 31, 2020 compared to $144~~ million for the same period in the prior year. ~~Higher~~Lower current year expenditures are driven by ~~higher~~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.

Table of Contents

Financing ~~Activities~~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, ~~2020 was $26~~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 ~~compared~~ to ~~$39~~$120 million of ~~net~~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.

Table of Contents

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 ~~used~~flow information in ~~financing activities~~the Con densed Consolidat ed Statements of Cash Flows in the Condensed Consolidated Financial Statements.

(b) Includes actual capital expenditures for the ~~same period in 2019, an increase of $65 million due to the following:~~three months ended March 31, 2021.

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

~~$12 million of higher repayments of short-term and long-term debt; and~~

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

Dividends

Dividends paid on our common stock totaled ~~$33~~$36 million for the three months ended March 31, ~~2020,~~2021, or ~~$0.535~~$0.565 per share per quarter. On April ~~27, 2020,~~26, 2021, our board of directors declared a quarterly dividend of ~~$0.535~~$0.565 per share payable June 1, ~~2020,~~2021, equivalent to an annual dividend of ~~$2.14~~$2.26 per share. The amount of any future cash dividends to be declared and paid, if any, will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our Revolving Credit Facility and our future business prospects.

~~Financing Transactions and Short-Term Liquidity~~

~~Revolving Credit Facility and CP Program~~

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

Contents

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

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

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

~~Covenant Requirements~~

Unconditional Purchase Obligations

The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on certain liens, restrictions on certain transactions, and maintenance of a certain Consolidated Indebtedness to Capitalization Ratio. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. We were in compliance with these covenants as of March 31, 2020.

See Note 73 of the Notes to Condensed Consolidated Financial Statements for ~~more information.~~recent updates to our purchase obligations.

Covenants within Wyoming Electric’s financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of March 31, 2020, we were in compliance with these covenants.

~~Financing Activities~~

Critical Accounting Policies Involving Significant Estimates

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

On February 27, 2020, we issued 1.2 million shares of common stock to a single investor through an underwritten registered transaction at a price of $81.77 per share for proceeds of $99 million, net of $1.0 million of issuance costs.

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

~~Table of Contents~~

~~Future Financing Plans~~

~~We anticipate the following financing activities in 2020:~~

~~Renew our shelf registration and ATM;~~

~~Refinance a portion of short-term borrowings held through the Revolving Credit Facility and CP Program to long-term debt; and~~

~~Continue to assess debt and equity needs to support our capital expenditure plan.~~

~~Credit Ratings~~

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



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

~~__________~~


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


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


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

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



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

~~__________~~


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


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


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

~~Capital Requirements~~

~~Capital Expenditures~~

Actual Planned Planned Planned Planned Planned
Capital Expenditures by Segment
Three Months Ended March 31, 2020 ^(a)
2020 ^(b)
2021 2022 2023 2024
(in millions)
Electric Utilities $ 49
$ 246
$ 203
$ 170
$ 137
$ 152
Gas Utilities 113
391
309
285
316
293
Power Generation 5
7
9
11
6
6
Mining 1
8
12
9
9
9
Corporate and Other 5
17
22
11
12
10
$ 173
$ 669
$ 555
$ 486
$ 480
$ 470

~~__________~~

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

~~(b) Includes actual capital expenditures for the three months ended March 31, 2020.~~

~~We are monitoring supply chains, including lead times for key materials and supplies, availability of resources, and status of large capital projects. To date, there~~There have been ~~limited impacts to supply chains including availability of supplies and materials and lead times and capital projects are ongoing without~~no material ~~disruption to schedules. Our third party resources~~changes in our critical accounting estimates from those reported in our 2020 Annual Report on Form 10-K. We continue to ~~support our business plans without disruption. Contingency plans are ongoing due to~~closely monitor the impacts of COVID-19 ~~including the potential for rescheduling projects. We currently do not anticipate a significant impact~~and Winter Storm Uri on our ~~capital investment plan for 2020.~~

~~Contractual Obligations~~

~~There have been no significant changes in contractual obligations from those previously disclosed in Note 19~~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 ~~Notes to the Consolidated Financial Statements in our 2019~~2020 Annual Report on Form ~~10-K except for the items described in~~ 10-K.

~~Note 13~~ ~~of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.~~

~~Off-Balance Sheet Commitments~~

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

New Accounting Pronouncements

Other than the pronouncements reported in our ~~2019~~2020 Annual Report on Form 10-K ~~filed with the SEC~~ and those discussed in Note 1 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements that are expected to have a material effect on our financial position, results of operations, or cash flows.

~~FORWARD-LOOKING INFORMATION~~

Any forward-looking statement contained in this document speaks only as of the date the statement was made. The Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement was made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, such as the COVID-19 pandemic, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements described in our ~~2019~~ ~~Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our~~ ~~2019~~ ~~Annual Report on Form 10-K, Part II,~~ ~~Item 1A~~ ~~of this Quarterly Report on Form 10-Q and other reports that we file with the SEC from time to time.~~


~~ITEM 3.~~	ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

~~Information regarding~~

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

~~Note 9~~ ~~of the Notes to Condensed Consolidated Financial Statements for updates to market risks during the three months ended March 31, 2020.~~

ITEM 4. CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of March 31, ~~2020.~~2021. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at March 31, ~~2020.~~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, ~~2020,~~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. Although we have altered some work routines due to the COVID-19 pandemic, the changes in our work environment (i.e. remote work arrangements) have not materially impacted our internal controls over financial reporting and have not adversely affected the Company’s ability to maintain operations, including financial reporting systems, ICFR, and disclosure controls and procedures.

Table of Contents

PART II. OTHER INFORMATION


~~ITEM 1.~~	~~LEGAL PROCEEDINGS~~

ITEM 1.LEGAL PROCEEDINGS

For information regarding legal proceedings, see Note 193 in Item 8 of our ~~2019~~2020 Annual Report on Form 10-K and Note 133 in Item 1 of Part I of this Quarterly Report on Form ~~10-Q, which information from~~ ~~Note 13~~ ~~is incorporated by reference into this item.~~10-Q.


~~ITEM 1A.~~	~~RISK FACTORS~~

ITEM 1A.RISK FACTORS

There are no material changes to the risk factors previously disclosed in Item 1A of Part I in our ~~2019~~2020 Annual Report on Form ~~10-K filed with the SEC except as shown below:~~10-K.

~~Our business, results~~

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

The following table contains monthly information about our acquisitions of ~~operations, financial condition and cash flows could be adversely affected by the recent coronavirus (COVID-19) pandemic.~~

We are responding to the global pandemic of COVID-19 by taking steps to mitigate the potential risks to us posed by its spread. We provide an essential service to our customers which means it is critical we keep our employees who operate our businesses healthy and minimize unnecessary exposure to the virus. We continue to execute our business continuity plan and have implemented a comprehensive set of actionsequity securities for the health and safety of our customers, employees, business partners and the communities we serve. We have taken extra precautions for our employees who work in the field and for employees who continue to work in our facilities and we have implemented work from home policies where appropriate. We have implemented sequestration plans for employees critical to maintaining reliable service.

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

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

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

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

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

~~Reduced availability and productivity of our employees;~~

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

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

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

~~Reduced training, travel and outside services related expenses.~~

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

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

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

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

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


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

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

~~Table of Contents~~

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

~~Cause a deterioration~~share withholding provisions of the ~~credit quality~~Omnibus Incentive Plan for payment of ~~our counterparties, including gas commodity contract counterparties, power purchase agreement counterparties, contractors or retail customers, that could result in credit losses;~~taxes associated with the vesting of various equity compensation plans.

~~Cause impairment of goodwill or long-lived assets;~~

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

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

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

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

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

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

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

To date, we have not experienced significant impacts to our results of operations, financial condition, cash flows or business plans. However, the situation remains fluid and it is difficult to predict with certainty the potential impact of COVID-19 on our business, results of operations, financial condition and cash flows.


~~ITEM 4.~~	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.


~~ITEM 6.~~Exhibit Number			~~EXHIBITS~~Description



~~Exhibit Number~~		~~Description~~

Exhibit 3.1*





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

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

Exhibit 4.1*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).

Table of Contents


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).

Exhibit 4.2*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).

Exhibit 4.3*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).




Exhibit 4.4*4.4	Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the Registrant’s Form 10-K for 2000).

~~Exhibit 18.1~~10.1	~~Preferability letter from Deloitte & Touche LLP regarding change in pension accounting asset method.~~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).

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

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

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

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

~~Exhibit 95~~95*	Mine Safety and Health Administration Safety Data.
101.INS*
~~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~~101.SCH*		XBRL Taxonomy Extension Schema Document
~~101.CAL~~101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document
~~101.DEF~~101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document
~~101.LAB~~101.LAB*		XBRL Taxonomy Extension Label Linkbase Document
~~101.PRE~~101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document
104*
~~104~~	Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)

~~__________~~


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

Table of Contents

SIGNATURES

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

BLACK HILLS CORPORATION


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

			~~/s/ 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, ~~2020~~2021


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


~~TABLE OF CONTENTS~~
			~~Page~~
~~Glossary of Terms and Abbreviations~~		4

~~PART I. FINANCIAL INFORMATION~~

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


TABLE OF CONTENTS
					Page
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			3230
		Executive Summary			30
		Recent Developments			30
		Results of Operations - Consolidated Summary and Overview			3332
		Non-GAAP Financial Measure			3633
		Electric Utilities ~~Segment~~			3733
		Gas Utilities ~~Segment~~			4036
		Regulatory Matters			4238
		Power Generation ~~Segment~~			4239
		Mining ~~Segment~~			4340
		Corporate and Other			4341
		Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax Benefit (Expense)			4341
		Liquidity and Capital Resources			42
		Cash Flow Activities			42
		Capital Sources			43
		Credit Ratings			43
		Capital Requirements			44
		Critical Accounting Policies Involving Significant ~~Accounting~~ Estimates			4345
		~~Liquidity and Capital Resources~~New Accounting Pronouncements			4345
		~~Cash Flow Activities~~			43
Item 3.		~~Dividends~~		44
	~~Financing Transactions and Short-Term Liquidity~~	44
	~~Capital Requirements~~	45
	~~Contractual Obligations~~	45
	~~Off-Balance Sheet Commitments~~	45
	~~New Accounting Pronouncements~~	45
	~~Forward-Looking Information~~	45
~~Item 3.~~	Quantitative and Qualitative Disclosures About Market Risk		45
Item 4.		Controls and Procedures			46

PART II. OTHER INFORMATION
Item 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			4746

Item 6.		Exhibits			4746

Signatures					4948



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

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



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



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



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



	Electric Revenue				Quantities Sold
	(in thousands)				(MWh)
	Three Months Ended March 31,				Three Months Ended March 31,
	2020		2019		2020	2019
Residential	$	54,505	$	57,638	373,150	389,178
Commercial	57,823		60,963		494,308	505,573
Industrial	32,169		32,440		460,632	426,614
Municipal	3,878		4,139		36,399	36,636
Subtotal Retail Revenue - Electric	148,375		155,180		1,364,489	1,358,001
Contract Wholesale ^(a)	5,553		8,343		131,778	223,020
Off-system/Power Marketing Wholesale	4,867		6,692		165,785	140,850
Other	15,344		12,712		—	—
Total Revenue and Energy Sold	174,139		182,927		1,662,052	1,721,871
Other Uses, Losses or Generation, net ^(b)	—		—		90,871	97,000
Total Revenue and Energy	174,139		182,927		1,752,923	1,818,871
Less cost of fuel and purchased power	64,460		73,283
Gross Margin (non-GAAP)	$	109,679	$	109,644




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



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

Wind Capacity Factor	45.6	%	42.6	%



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




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

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

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

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

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

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



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



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



	Actual		Planned		Planned		Planned		Planned		Planned
Capital Expenditures by Segment	Three Months Ended March 31, 2020 ^(a)		2020 ^(b)		2021		2022		2023		2024
(in millions)
Electric Utilities	$	49	$	246	$	203	$	170	$	137	$	152
Gas Utilities	113		391		309		285		316		293
Power Generation	5		7		9		11		6		6
Mining	1		8		12		9		9		9
Corporate and Other	5		17		22		11		12		10
	$	173	$	669	$	555	$	486	$	480	$	470