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Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2021

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

For the transition period from __________ to __________.

Commission File Number 001-31303

Black Hills Corporation

Incorporated in South Dakota IRS Identification Number 46-0458824

7001 Mount Rushmore Road

Rapid City, South Dakota 57702

Registrant’s telephone number (605) 721-1700

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

NONE

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

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

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

Large Accelerated Filer

Accelerated Filer

☐

Non-accelerated Filer

☐

Smaller Reporting Company

☐

Emerging Growth Company

☐

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

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

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common stock of $1.00 par value

BKH

New York Stock Exchange

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

Class

Outstanding at October 31, 2021

Common stock, $1.00 par value

63,820,271

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

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements - unaudited	8
	Condensed Consolidated Statements of Income	8
	Condensed Consolidated Statements of Comprehensive Income	9
	Condensed Consolidated Balance Sheets	10
	Condensed Consolidated Statements of Cash Flows	12
	Condensed Consolidated Statements of Equity	13
	Notes to Condensed Consolidated Financial Statements	15
	Note 1. Management’s Statement	15
	Note 2. Regulatory Matters	16
	Note 3. Commitments, Contingencies and Guarantees	18
	Note 4. Revenue	18
	Note 5. Financing	21
	Note 6. Earnings Per Share	22
	Note 7. Risk Management and Derivatives	22
	Note 8. Fair Value Measurements	26
	Note 9. Other Comprehensive Income	28
	Note 10. Employee Benefit Plans	29
	Note 11. Income Taxes	30
	Note 12. Business Segment Information	31
	Note 13. Selected Balance Sheet Information	33
	Note 14. Subsequent Events	33

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TABLE OF CONTENTS
		Page
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
	Executive Summary	34
	Recent Developments	34
	Results of Operations	35
	Consolidated Summary and Overview	35
	Non-GAAP Financial Measure	37
	Electric Utilities	37
	Gas Utilities	42
	Regulatory Matters	45
	Power Generation	45
	Mining	47
	Corporate and Other	47
	Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax (Expense)	48
	Liquidity and Capital Resources	49
	Cash Flow Activities	49
	Capital Sources	50
	Credit Ratings	50
	Capital Requirements	51
	Critical Accounting Policies Involving Significant Estimates	52
	New Accounting Pronouncements	52

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52
Item 4.	Controls and Procedures	53

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	53
Item 1A.	Risk Factors	53
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	53

Item 4.	Mine Safety Disclosures	53

Item 6.	Exhibits	54

Signatures		55

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GLOSSARY OF TERMS AND ABBREVIATIONS

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


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

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


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

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

BHC			Black Hills Corporation; the Company



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












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









Cheyenne Light			Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service in the Cheyenne, Wyoming area (doing business as Black Hills Energy). Also known as Wyoming Electric.
Chief Operating Decision Maker (CODM)			Chief Executive Officer
Choice Gas Program			Regulator-approved programs in Wyoming and Nebraska that allow certain utility customers to select their natural gas commodity supplier, providing for the unbundling of the commodity service from the distribution delivery service.

City of Gillette			Gillette, Wyoming


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

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

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CP Program			Commercial Paper Program
CPUC			Colorado Public Utilities Commission


CVA			Credit Valuation Adjustment


Dth			Dekatherm. A unit of energy equal to 10 therms or approximately one million British thermal units (MMBtu)
Economy Energy			Purchased energy that costs less than that produced with the utilities’ owned generation.






FASB			Financial Accounting Standards Board

Fitch			Fitch Ratings Inc.
GAAP			Accounting principles generally accepted in the United States of America


Global Settlement			Settlement with a utility’s commission where the revenue requirement is agreed upon, but the specific adjustments used by each party to arrive at the amount are not specified in public rate orders.

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


Iowa Gas			Black Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Iowa (doing business as Black Hills Energy).
IPP			Independent Power Producer
IRP			Integrated Resource Plan
IRS			United States Internal Revenue Service
IUB			Iowa Utilities Board
Kansas Gas			Black Hills Kansas Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Kansas (doing business as Black Hills Energy).
KCC			Kansas Corporation Commission

LIBOR			London Interbank Offered Rate
MDU			Montana-Dakota Utilities Co., a subsidiary of MDU Resources Group, Inc.


MMBtu			Million British thermal units

Moody’s			Moody’s Investors Service, Inc.

MW			Megawatts
MWh			Megawatt-hours
Nebraska Gas			Black Hills Nebraska Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Nebraska (doing business as Black Hills Energy).
Neil Simpson II			A mine-mouth, coal-fired power plant owned and operated by South Dakota Electric with a total capacity of 90 MW located at our Gillette, Wyoming energy complex.
NOL			Net Operating Loss
NPSC			Nebraska Public Service Commission








OCI			Other Comprehensive Income
OSHA			Occupational Safety & Health Administration
PPA			Power Purchase Agreement

PSA			Power Sales Agreement

Pueblo Airport Generation			The 420 MW combined cycle gas-fired power generating plants jointly owned by Colorado Electric (220 MW) and Black Hills Colorado IPP (200 MW). Black Hills Colorado IPP operates this facility. The plants commenced operation on January 1, 2012.
Ready Wyoming			A 285-mile, multi-phase transmission expansion project in Wyoming. This transmission project will serve the growing needs of customers by enhancing resiliency of Wyoming Electric’s overall electric system and and expanding access to power markets and renewable resources. The project will help Wyoming Electric maintain top-quartile reliability and enable economic development in the Cheyenne, Wyoming region.

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Renewable Advantage			A 200 MW solar facility project to be constructed in Pueblo County, Colorado. The project aims to lower customer energy costs and provide economic and environmental benefits to Colorado Electric’s customers and communities. This project, which was approved by the CPUC in September 2020, will be owned by a third-party renewable energy developer with Colorado Electric purchasing all of the energy generated at the facility under the terms of a 15-year PPA. The project is expected to be placed in service in 2023.
Renewable Ready			Voluntary renewable energy subscription program for large commercial, industrial and governmental agency customers in South Dakota and Wyoming.
Revolving Credit Facility			Our $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which was amended and restated on July 19, 2021, and now terminates on July 19, 2026.

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

Service Guard Comfort Plan			Appliance protection plan that provides home appliance repair services through on-going monthly service agreements to residential utility customers.
S&P			S&P Global Ratings, a division of S&P Global Inc.
South Dakota Electric			Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and Wyoming (doing business as Black Hills Energy).
SSIR			System Safety and Integrity Rider
TCJA			Tax Cuts and Jobs Act
Tech Services			Non-regulated product lines delivered by our Utilities that 1) provide electrical system construction services to large industrial customers of our electric utilities, and 2) serve gas transportation customers throughout its service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.
Utilities			Black Hills’ Electric and Gas Utilities
Wind Capacity Factor			Measures the amount of electricity a wind turbine produces in a given time period relative to its maximum potential.
Winter Storm Uri			February 2021 winter weather event that caused extreme cold temperatures in the central United States and led to unprecedented fluctuations in customer demand and market pricing for natural gas and energy.

WPSC			Wyoming Public Service Commission
WRDC			Wyodak Resources Development Corporation, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, providing coal supply primarily to five on-site, mine-mouth generating facilities (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%.
Wygen II			A mine-mouth, coal-fired power plant owned by Wyoming Electric with a total capacity of 95 MW located at our Gillette, Wyoming energy complex.
Wygen III			A mine-mouth, coal-fired power plant operated by South Dakota Electric with a total capacity of 110 MW located at our Gillette, Wyoming energy complex. South Dakota Electric owns 52% of the power plant, MDU owns 25% and the City of Gillette owns the remaining 23%.
Wyodak Plant			The 362 MW mine-mouth, coal-fired generating facility near Gillette, Wyoming, jointly owned by PacifiCorp (80%) and South Dakota Electric (20%). Our WRDC mine supplies all of the fuel for the facility.
Wyoming Electric			Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in the Cheyenne, Wyoming area (doing business as Black Hills Energy).
Wyoming Gas			Black Hills Wyoming Gas, LLC, an indirect and wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Wyoming (doing business as Black Hills Energy).

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FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q includes “forward-looking statements” as defined by the SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation, the risk factors described in Item 1A of Part I 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, and the following:

•Our ability to obtain adequate cost recovery for our utility operations through regulatory proceedings and favorable rulings on periodic applications to recover costs for capital additions, plant retirements and decommissioning, fuel, transmission, purchased power, and other operating costs and the timing in which new rates would go into effect;

•Our ability to complete our capital program in a cost-effective and timely manner;

•Our ability to execute on our strategy;

•Our ability to successfully execute our financing plans;

•Our ability to achieve our greenhouse gas emissions intensity reduction goals;

•Board of Directors’ approval of any future quarterly dividends;

•The impact of future governmental regulation;

•The effects of inflation and volatile energy prices; and

•Other factors discussed from time to time in our filings with the SEC.

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time-to-time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events or otherwise.

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


(unaudited)	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(in thousands, except per share amounts)

Revenue	$	380,590	$	346,590	$	1,386,594	$	1,210,554

Operating expenses:
Fuel, purchased power and cost of natural gas sold	94,057		71,686		495,678		331,194
Operations and maintenance	122,277		122,759		375,201		365,533
Depreciation, depletion and amortization	59,159		56,348		174,871		169,413
Taxes - property and production	15,224		13,563		45,390		42,062
Total operating expenses	290,717		264,356		1,091,140		908,202

Operating income	89,873		82,234		295,454		302,352

Other income (expense):

Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	(38,604)		(36,521)		(115,098)		(108,067)
Interest income	586		480		1,278		1,028
Impairment of investment	—		—		—		(6,859)
Other income (expense), net	1,560		(1,193)		1,635		(703)
Total other income (expense)	(36,458)		(37,234)		(112,185)		(114,601)

Income before income taxes	53,415		45,000		183,269		187,751
Income tax (expense)	(5,253)		(4,651)		(6,333)		(25,484)
Net income	48,162		40,349		176,936		162,267
Net income attributable to non-controlling interest	(4,050)		(4,066)		(11,347)		(11,844)
Net income available for common stock	$	44,112	$	36,283	$	165,589	$	150,423

Earnings per share of common stock:
Earnings per share, Basic	$	0.70	$	0.58	$	2.63	$	2.41
Earnings per share, Diluted	$	0.70	$	0.58	$	2.63	$	2.41

Weighted average common shares outstanding:
Basic	63,341		62,575		62,950		62,310
Diluted	63,436		62,630		63,046		62,362

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


(unaudited)	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(in thousands)
Net income	$	48,162	$	40,349	$	176,936	$	162,267

Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (net of tax of $0, $0, $0 and $(17), respectively)	—		—		—		55
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $6, $6, $21 and $19, respectively)	(19)		(18)		(53)		(60)
Reclassification adjustments of benefit plan liability - net loss (net of tax of $(139), $(149), $(513) and $(426), respectively)	459		448		1,280		1,365
Derivative instruments designated as cash flow hedges:
Reclassification of net realized losses on settled/amortized interest rate swaps (net of tax of $(55), $(168), $(395) and $(508), respectively)	657		544		1,743		1,630
Net unrealized gains (losses) on commodity derivatives (net of tax of $(1,437), $(112), $(1,776) and $(44), respectively)	4,430		401		5,476		181
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $81, $(41), $87 and $(172), respectively)	(250)		137		(269)		562
Other comprehensive income, net of tax	5,277		1,512		8,177		3,733

Comprehensive income	53,439		41,861		185,113		166,000
Less: comprehensive income attributable to non-controlling interest	(4,050)		(4,066)		(11,347)		(11,844)
Comprehensive income available for common stock	$	49,389	$	37,795	$	173,766	$	154,156

See Note 9 for additional disclosures.

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


(unaudited)	As of
	September 30, 2021		December 31, 2020
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	10,181	$	6,356
Restricted cash and equivalents	4,753		4,383
Accounts receivable, net	181,956		265,961
Materials, supplies and fuel	145,743		117,400
Derivative assets, current	12,316		1,848
Income tax receivable, net	17,472		19,446
Regulatory assets, current	213,031		51,676
Other current assets	42,274		26,221
Total current assets	627,726		493,291

Property, plant and equipment	7,697,880		7,305,530
Less: accumulated depreciation and depletion	(1,380,304)		(1,285,816)
Total property, plant and equipment, net	6,317,576		6,019,714

Other assets:
Goodwill	1,299,454		1,299,454
Intangible assets, net	11,063		11,944
Regulatory assets, non-current	617,024		226,582
Other assets, non-current	37,547		37,801
Total other assets, non-current	1,965,088		1,575,781

TOTAL ASSETS	$	8,910,390	$	8,088,786

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Continued)


(unaudited)	As of
	September 30, 2021		December 31, 2020
	(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	142,130	$	183,340
Accrued liabilities	249,835		243,612
Derivative liabilities, current	3,471		2,044
Regulatory liabilities, current	30,156		25,061
Notes payable	332,525		234,040
Current maturities of long-term debt	—		8,436
Total current liabilities	758,117		696,533

Long-term debt, net of current maturities	4,125,571		3,528,100

Deferred credits and other liabilities:
Deferred income tax liabilities, net	445,036		408,624
Regulatory liabilities, non-current	496,261		507,659
Benefit plan liabilities	150,727		150,556
Other deferred credits and other liabilities	134,776		134,667
Total deferred credits and other liabilities	1,226,800		1,201,506

Commitments, contingencies and guarantees (Note 3)

Equity:
Stockholders’ equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 63,865,151 and 62,827,179 shares, respectively	63,865		62,827
Additional paid-in capital	1,726,277		1,657,285
Retained earnings	929,369		870,738
Treasury stock, at cost – 43,885 and 32,492 shares, respectively	(2,819)		(2,119)
Accumulated other comprehensive income (loss)	(19,169)		(27,346)
Total stockholders’ equity	2,697,523		2,561,385
Non-controlling interest	102,379		101,262
Total equity	2,799,902		2,662,647

TOTAL LIABILITIES AND TOTAL EQUITY	$	8,910,390	$	8,088,786

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


(unaudited)	Nine Months Ended September 30,
	2021		2020
Operating activities:	(in thousands)
Net income	$	176,936	$	162,267
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	174,871		169,413
Deferred financing cost amortization	3,892		5,523
Impairment of investment	—		6,859
Stock compensation	7,245		2,696
Deferred income taxes	5,844		28,502
Employee benefit plans	6,779		9,294
Other adjustments, net	2,708		7,910
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	(29,948)		(10,905)
Accounts receivable and other current assets	97,348		75,960
Accounts payable and other current liabilities	(20,094)		(11,136)
Regulatory assets	(559,389)		1,954
Regulatory liabilities	(9,533)		(17,686)
Contributions to defined benefit pension plans	—		(12,700)
Other operating activities, net	(1,419)		1,508
Net cash provided by (used in) operating activities	(144,760)		419,459

Investing activities:
Property, plant and equipment additions	(497,849)		(535,993)
Other investing activities	13,743		6,269
Net cash (used in) investing activities	(484,106)		(529,724)

Financing activities:
Dividends paid on common stock	(106,957)		(99,999)
Common stock issued	62,977		99,316
Term loan - borrowings	800,000		—
Term loan - repayments	(800,000)		—
Net borrowings (payments) of Revolving Credit Facility and CP Program	98,485		(265,180)
Long-term debt - issuances	600,000		400,000
Long-term debt - repayments	(8,436)		(7,163)
Distributions to non-controlling interest	(10,230)		(12,636)
Other financing activities	(2,778)		(6,519)
Net cash provided by financing activities	633,061		107,819

Net change in cash, restricted cash and cash equivalents	4,195		(2,446)

Cash, restricted cash and cash equivalents at beginning of period	10,739		13,658
Cash, restricted cash and cash equivalents at end of period	$	14,934	$	11,212

Supplemental cash flow information:
Cash (paid) refunded during the period:
Interest, net of amounts capitalized	$	(93,325)	$	(87,453)
Income taxes	1,486		1,256
Non-cash investing and financing activities:
Accrued property, plant and equipment purchases at September 30	55,619		86,474

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY


(unaudited)	Common Stock			Treasury Stock
(in thousands except share amounts)	Shares	Value		Shares	Value		Additional Paid in Capital		Retained Earnings		AOCI		Non-controlling Interest		Total
December 31, 2020	62,827,179	$	62,827	32,492	$	(2,119)	$	1,657,285	$	870,738	$	(27,346)	$	101,262	$	2,662,647
Net income	—	—		—	—		—		96,316		—		4,171		100,487
Other comprehensive income, 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 non-controlling 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
Net income	—	—		—	—		—		25,161		—		3,126		28,287
Other comprehensive income, net of tax	—	—		—	—		—		—		1,882		—		1,882
Dividends on common stock ($0.565 per share)	—	—		—	—		—		(35,578)		—		—		(35,578)
Share-based compensation	20,905	21		6,588	(424)		3,698		—		—		—		3,295

Issuance of common stock	596,035	596		—	—		39,636		—		—		—		40,232
Issuance costs	—	—		—	—		(466)		—		—		—		(466)

Other	—	—		—	—		—		1		—		—		1
Distributions to non-controlling interest	—	—		—	—		—		—		—		(4,061)		(4,061)
June 30, 2021	63,526,913	$	63,527	46,528	$	(2,988)	$	1,701,825	$	921,122	$	(24,446)	$	99,854	$	2,758,894
Net income	—	—		—	—		—		44,112		—		4,050		48,162
Other comprehensive income, net of tax	—	—		—	—		—		—		5,277		—		5,277
Dividends on common stock ($0.565 per share)	—	—		—	—		—		(35,865)		—		—		(35,865)
Share-based compensation	17	—		(2,643)	169		1,849		—		—		—		2,018

Issuance of common stock	338,221	338		—	—		22,834		—		—		—		23,172
Issuance costs	—	—		—	—		(231)		—		—		—		(231)

Distributions to non-controlling interest	—	—		—	—		—		—		—		(1,525)		(1,525)
September 30, 2021	63,865,151	$	63,865	43,885	$	(2,819)	$	1,726,277	$	929,369	$	(19,169)	$	102,379	$	2,799,902

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(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	—	—		—	—		—		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 non-controlling interest	—	—		—	—		—		—		—		(4,741)		(4,741)
March 31, 2020	62,772,978	$	62,773	24,656	$	(1,925)	$	1,652,861	$	838,841	$	(29,382)	$	101,255	$	2,624,423
Net income	—	—		—	—		—		20,966		—		3,728		24,694
Other comprehensive income (loss), net of tax	—	—		—	—		—		—		948		—		948


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


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





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


Issuance costs	—	—		—	—		(119)		—		—		—		(119)

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

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BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

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

(1) Management’s Statement

The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company”, “us”, “we” or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Condensed Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes included in our 2020 Annual Report on Form 10-K.

Segment Reporting

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

Use of Estimates and Basis of Presentation

The information furnished in the accompanying Condensed Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the September 30, 2021, December 31, 2020 and September 30, 2020 financial information. Certain lines of business in which we operate are highly seasonal, and our interim results of operations are not necessarily indicative of the results of operations to be expected for an entire year.

COVID-19 Pandemic

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

The Company’s Condensed Consolidated Financial Statements reflect estimates and assumptions made by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Condensed Consolidated Financial Statements and reported amounts of revenue and expenses during the reporting periods presented. The Company considered the impacts of COVID-19 on the assumptions and estimates used and determined that for the three and nine months ended September 30, 2021, there were no material adverse impacts on the Company’s results of operations.

Recently Issued Accounting Standards

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

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

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Recently Adopted Accounting Standards

Simplifying the Accounting for Income Taxes, ASU 2019-12

In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes as part of its overall simplification initiative to reduce costs and complexity in applying accounting standards while maintaining or improving the usefulness of the information provided to users of the financial statements. Amendments include removal of certain exceptions to the general principles of ASC 740, Income Taxes, and simplification in several other areas such as accounting for a franchise tax (or similar tax) that is partially based on income. We adopted this standard prospectively on January 1, 2021. Adoption of this standard did not have an impact on our financial position, results of operations or cash flows.

(2) Regulatory Matters

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


	As of		As of
	September 30, 2021		December 31, 2020
Regulatory assets
Winter Storm Uri (a)	$	532,766	$	—
Deferred energy and fuel cost adjustments (b)	59,741		39,035
Deferred gas cost adjustments (b)	6,076		3,200
Gas price derivatives (b)	—		2,226
Deferred taxes on AFUDC (c)	7,537		7,491
Employee benefit plans and related deferred taxes (d)	114,234		116,598
Environmental (b)	1,395		1,413

Loss on reacquired debt (b)	21,460		22,864

Deferred taxes on flow through accounting (d)	54,199		47,515
Decommissioning costs (b)	6,583		8,988
Gas supply contract termination (b)	—		2,524
Other regulatory assets (b)	26,064		26,404
Total regulatory assets	830,055		278,258
Less current regulatory assets	(213,031)		(51,676)
Regulatory assets, non-current	$	617,024	$	226,582

Regulatory liabilities
Deferred energy and gas costs (b)	$	9,408	$	13,253
Gas price derivatives (b)	13,234		—
Employee benefit plan costs and related deferred taxes (d)	39,203		40,256
Cost of removal (b)	181,180		172,902

Excess deferred income taxes (d)	266,477		285,259

Other regulatory liabilities (d)	16,915		21,050
Total regulatory liabilities	526,417		532,720
Less current regulatory liabilities	(30,156)		(25,061)
Regulatory liabilities, non-current	$	496,261	$	507,659

__________

(a) Timing of Winter Storm Uri incremental cost recovery and associated carrying costs are subject to pending applications with our utility commissions. See further information below.

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

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

Regulatory Activity

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

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Winter Storm Uri

In February 2021, a prolonged period of historic cold temperatures across the central United States, which covered all of our Utilities’ service territories, caused a substantial increase in heating and energy demand and contributed to unforeseeable and unprecedented market prices for natural gas and electricity. As a result of Winter Storm Uri, we incurred significant incremental fuel, purchased power and natural gas costs.

Our Utilities submitted Winter Storm Uri cost recovery applications in our state jurisdictions seeking to recover $546 million of these incremental costs through separate tracking mechanisms over a weighted-average recovery period of 3.7 years. These incremental cost estimates are subject to adjustments as final decisions are issued by the respective utility commissions. In these applications, we seek approval to recover carrying costs. For the nine months ended September 30, 2021, $1.8 million of carrying costs were accrued and recorded to a regulatory asset. We are also seeking recovery of $13 million of previously disclosed Winter Storm Uri incremental costs through our existing regulatory mechanisms.

To date, Nebraska Gas and South Dakota Electric received commission approval of their Winter Storm Uri cost recovery applications. Additionally, Arkansas Gas, Iowa Gas and Wyoming Gas received approval for interim cost recovery subject to a final decision on carrying costs and recovery periods at a later date. In October 2021, Wyoming Gas filed a settlement agreement for their application with final rates to be implemented January 1, 2022. The settlement is subject to final approval by the commission. For the nine months ended September 30, 2021, our Utilities collected $15 million of Winter Storm Uri incremental costs and carrying costs from customers.

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. The settlement agreement further provided for Colorado Electric to deliver annual bill credits to customers, starting in April 2021, until remaining excess deferred income tax regulatory liabilities associated with the TCJA are fully amortized. In April 2021, Colorado Electric delivered $0.9 million of TCJA-related bill credits to customers.

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, were delivered to customers in June 2021.

These Colorado Electric and Nebraska Gas 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 and nine months ended September 30, 2021.

As part of the settlement agreement discussed further below, Kansas Gas will deliver $3.0 million of TCJA and state tax reform benefits to customers, annually, for each of the next three years starting in 2022 (approximately $9.1 million of total benefits expected to be delivered).

Colorado Gas

Rate Review

On June 1, 2021, Colorado Gas filed a rate review with the CPUC seeking recovery of significant infrastructure investments in its 7,000-mile natural gas pipeline system. On October 5, 2021, Colorado Gas reached a settlement agreement with the CPUC Staff and various intervenors for a general rate increase. The settlement agreement is subject to review and approval by an ALJ and the CPUC. If approved, the settlement is expected to generate $6.5 million of new annual revenue with new rates effective January 1, 2022. The new revenue is based on a return on equity of 9.2% and a capital structure of 50.3% equity and 49.7% debt.

SSIR

On September 11, 2020, in accordance with the final Order from an earlier rate review filed on 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. On July 6, 2021, Colorado Gas received approval from the CPUC for its SSIR proposal that will recover safety and integrity focused system investments for three years effective January 1, 2022. The return on SSIR investments will be the current weighted-average cost of long-term debt.

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Iowa Gas

Rate Review

On June 1, 2021, Iowa Gas filed a rate review with the IUB seeking recovery of significant infrastructure investments in its 5,000-mile natural gas pipeline system. The rate review requests shifting $2.2 million of rider revenue to base rates and $8.3 million in additional new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 10.15%. Iowa statute allows implementation of interim rates 10 days after filing a rate review and Iowa Gas implemented interim rates effective on June 11, 2021. The request seeks to finalize rates in the first quarter of 2022.

Kansas Gas

Rate Review

On May 7, 2021, Kansas Gas filed a rate review and rider renewal with the KCC seeking recovery of significant infrastructure investments in its 4,600-mile natural gas pipeline system. On October 8, 2021, Kansas Gas reached a Global Settlement agreement with KCC Staff and various intervenors for a general rate increase and renewal of its safety and integrity rider. The settlement agreement is subject to review and approval by the KCC. If approved, the settlement will shift $6.6 million of rider revenue to base rates, which are expected to be effective January 1, 2022, and also allow rider renewal for at least five more years.

Nebraska Gas

Jurisdictional Consolidation and Rate Review

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

(3) Commitments, Contingencies and Guarantees

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

Power Purchase Agreement - Colorado Electric Renewable Advantage

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

(4) Revenue

Our revenue contracts generally provide for performance obligations that are: fulfilled and transfer control to customers over time; represent a series of distinct services that are substantially the same; involve the same pattern of transfer to the customer; and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice. The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reportable segments for the three and nine months ended September 30, 2021 and 2020. Sales tax and other similar taxes are excluded from revenues.

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Three Months Ended September 30, 2021	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues		Total
Customer types:	(in thousands)
Retail	$	179,982	$	115,908	$	—	$	15,814	$	(8,846)	$	302,858
Transportation	—		37,651		—		—		(110)		37,541
Wholesale	3,856		—		26,058		—		(23,725)		6,189
Market - off-system sales	15,149		75		—		—		(1,638)		13,586
Transmission/Other	13,913		9,863		—		—		(5,297)		18,479
Revenue from contracts with customers	$	212,900	$	163,497	$	26,058	$	15,814	$	(39,616)	$	378,653
Other revenues	203		1,186		462		574		(488)		1,937
Total revenues	$	213,103	$	164,683	$	26,520	$	16,388	$	(40,104)	$	380,590

Timing of revenue recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	15,814	$	(8,846)	$	6,968
Services transferred over time	212,900		163,497		26,058		—		(30,770)		371,685
Revenue from contracts with customers	$	212,900	$	163,497	$	26,058	$	15,814	$	(39,616)	$	378,653


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

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

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Nine Months Ended September 30, 2021	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues		Total
Customer types:	(in thousands)
Retail	$	536,952	$	601,358	$	—	$	43,751	$	(23,093)	$	1,158,968
Transportation	—		117,251		—		—		(329)		116,922
Wholesale	12,788		—		79,662		—		(71,656)		20,794
Market - off-system sales	31,746		235		—		—		(6,197)		25,784
Transmission/Other	41,339		29,378		—		—		(15,892)		54,825
Revenue from contracts with customers	$	622,825	$	748,222	$	79,662	$	43,751	$	(117,167)	$	1,377,293
Other revenues	2,619		5,030		1,369		1,738		(1,455)		9,301
Total revenues	$	625,444	$	753,252	$	81,031	$	45,489	$	(118,622)	$	1,386,594

Timing of revenue recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	43,751	$	(23,093)	$	20,658
Services transferred over time	622,825		748,222		79,662		—		(94,074)		1,356,635
Revenue from contracts with customers	$	622,825	$	748,222	$	79,662	$	43,751	$	(117,167)	$	1,377,293


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

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

Contract Balances

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

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(5) Financing

Short-term Debt

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


	September 30, 2021				December 31, 2020
	Balance Outstanding		Letters of Credit (a)		Balance Outstanding		Letters of Credit (a)

Revolving Credit Facility	—		23,255		—		24,730
CP Program	332,525		—		234,040		—
Total Notes payable	$	332,525	$	23,255	$	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.

Revolving Credit Facility and CP Program

On July 19, 2021, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 19, 2026 with two one year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. Based on our current credit ratings, the margins for base rate borrowings, Eurodollar borrowings and letters of credit will be 0.125%, 1.125% and 1.125%, respectively, and a 0.175% commitment fee will be charged on unused amounts.

Our net short-term borrowings related to our Revolving Credit Facility and CP Program during the nine months ended September 30, 2021 were $98.5 million. The weighted average interest rate on short-term borrowings related to our Revolving Credit Facility and CP Program at September 30, 2021 was 0.19%.

Term Loan

On February 24, 2021, we entered into a nine-month, $800 million unsecured term loan to provide additional liquidity and to meet our cash needs related to the incremental fuel, purchased power and natural gas costs from Winter Storm Uri. The term loan, carried no prepayment penalty and was 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. Proceeds from the August 26, 2021 public debt offering (discussed below) were used to repay the remaining balance on this term loan.

Long-term Debt

On August 26, 2021, we completed a public debt offering which consisted of $600 million, 1.037% three year senior unsecured notes due August 23, 2024. The notes include an optional redemption provision and may be redeemed, in whole or in part, without premium, on or after February 23, 2022. The proceeds from the offering, which were net of $3.7 million of deferred financing costs, were used to repay amounts outstanding under our term loan entered into on February 24, 2021.

Debt Covenants

Under our Revolving Credit Facility, 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 non-controlling interest in subsidiaries. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding.

Our Revolving Credit Facility and term loans require compliance with the following financial covenant, which we were in compliance with at September 30, 2021:

As of September 30, 2021

Covenant Requirement

Consolidated Indebtedness to Capitalization Ratio

62.4%

Less than

65%

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Equity

At-the-Market Equity Offering Program

During the three months ended September 30, 2021, we issued a total of 0.3 million shares of common stock under the ATM for proceeds of $23 million, net of $0.2 million in issuance costs. During the nine months ended September 30, 2021, we issued a total of 0.9 million shares of common stock under the ATM for proceeds of $63 million, net of $0.6 million in issuance costs.

(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, except per share amounts):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020

Net income available for common stock	$	44,112	$	36,283	$	165,589	$	150,423

Weighted average shares - basic	63,341		62,575		62,950		62,310
Dilutive effect of:
Equity compensation	95		55		96		52
Weighted average shares - diluted	63,436		62,630		63,046		62,362

Earnings per share of common stock:
Earnings per share, Basic	$	0.70	$	0.58	$	2.63	$	2.41
Earnings per share, Diluted	$	0.70	$	0.58	$	2.63	$	2.41

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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

Equity compensation	9	22	12	22
Restricted stock	—	49	1	40

Anti-dilutive shares	9	71	13	62

(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 weather (Winter Storm Uri), market speculation, pipeline constraints, and other factors that may impact natural gas and electric energy supply and demand; and

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

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Credit Risk

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

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

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

Derivatives and Hedging Activity

Our derivative and hedging activities included in the accompanying Condensed Consolidated Balance Sheets, Condensed Consolidated Statements of Income and Condensed Consolidated Statements of Comprehensive Income are detailed below and in Note 8.

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

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

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

We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risk using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and sales during time frames ranging from October 2021 through August 2024. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price forward contracts to deliver gas to our Choice Gas Program customers. The gain or loss on these designated derivatives is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and reclassified into earnings in the same period that the underlying hedged item is recognized in earnings. Effectiveness of our hedging position is evaluated at least quarterly.

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


		September 30, 2021		December 31, 2020
	Units	Notional Amounts	Maximum Term (months) (a)	Notional Amounts	Maximum Term (months) (a)
Natural gas futures purchased	MMBtus	1,700,000	6	620,000	3
Natural gas options purchased, net	MMBtus	8,420,000	6	3,160,000	3
Natural gas basis swaps purchased	MMBtus	1,500,000	6	900,000	3
Natural gas over-the-counter swaps, net (b)	MMBtus	5,920,000	35	3,850,000	17
Natural gas physical contracts, net (c)	MMBtus	18,758,835	7	17,513,061	22
Electric wholesale contracts (c)	MWh	65,625	3	219,000	12

__________

(a) Term reflects the maximum forward period hedged.

(b) As of September 30, 2021, 2,700,000 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 September 30, 2021, the Company posted $0.9 million related to such provisions, which is included in Other current assets on the Condensed Consolidated Balance Sheets.

Derivatives by Balance Sheet Classification

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

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


	Balance Sheet Location	September 30, 2021		December 31, 2020
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets, current	$	6,989	$	181
Noncurrent commodity derivatives	Other assets, non-current	32		43
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current	—		(108)

Total derivatives designated as hedges		$	7,021	$	116

Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets, current	$	5,327	$	1,667
Noncurrent commodity derivatives	Other assets, non-current	1,580		151
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current	(3,471)		(1,936)

Total derivatives not designated as hedges		$	3,436	$	(118)

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Derivatives Designated as Hedge Instruments

The impacts of cash flow hedges on our Condensed Consolidated Statements of Comprehensive Income and Condensed Consolidated Statements of Income are presented below for the three and nine months ended September 30, 2021 and 2020. Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.


	Three Months Ended September 30,					Three Months Ended September 30,
	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	$	712	$	712	Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	$	(712)	$	(712)
Commodity derivatives	5,536		691		Fuel, purchased power and cost of natural gas sold	331		(178)
Total	$	6,248	$	1,403		$	(381)	$	(890)


	Nine Months Ended September 30,					Nine Months Ended September 30,
	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	$	2,138	$	2,138	Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	$	(2,138)	$	(2,138)
Commodity derivatives	6,896		959		Fuel, purchased power and cost of natural gas sold	356		(734)
Total	$	9,034	$	3,097		$	(1,782)	$	(2,872)

As of September 30, 2021, $4.0 million of net gains related to our interest rate swaps and commodity derivatives are expected to be reclassified from AOCI into earnings as gains within the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

Derivatives Not Designated as Hedge Instruments

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2021 and 2020. Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.


		Three Months Ended September 30,
		2021		2020
Derivatives Not Designated as Hedging Instruments	Location of Gain/(Loss) on Derivatives Recognized in Income	Amount of Gain/(Loss) on Derivatives Recognized in Income
		(in thousands)
Commodity derivatives - Electric	Fuel, purchased power and cost of natural gas sold	$	2,494	$	(1,386)
Commodity derivatives - Natural Gas	Fuel, purchased power and cost of natural gas sold	4,004		1,777
		$	6,498	$	391

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		Nine Months Ended September 30,
		2021		2020
Derivatives Not Designated as Hedging Instruments	Location of Gain/(Loss) on Derivatives Recognized in Income	Amount of Gain/(Loss) on Derivatives Recognized in Income
		(in thousands)
Commodity derivatives - Electric	Fuel, purchased power and cost of natural gas sold	$	(2,628)	$	(228)
Commodity derivatives - Natural Gas	Fuel, purchased power and cost of natural gas sold	6,186		2,992
		$	3,558	$	2,764

As discussed above, financial instruments used in our regulated Gas Utilities are not designated as cash flow hedges. There is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized (losses) or gains included in our Regulatory asset or Regulatory liability related to the hedges in our Gas Utilities were $13.2 million and $(2.2) million as of September 30, 2021 and December 31, 2020, respectively. For our Electric Utilities, the unrealized gains and losses arising from these derivatives are recognized in the Condensed Consolidated Statements of Income.

(8) Fair Value Measurements

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

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

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

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

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

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

Recurring Fair Value Measurements

Derivatives

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

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	As of September 30, 2021
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting (a)		Total
	(in thousands)
Assets:
Commodity derivatives — Gas Utilities	$	—	$	32,298	$	—	$	(18,370)	$	13,928
Commodity derivatives — Electric Utilities	$	—	$	—	$	—	$	—	$	—
Total	$	—	$	32,298	$	—	$	(18,370)	$	13,928

Liabilities:
Commodity derivatives — Gas Utilities	$	—	$	1,128	$	—	$	(141)	$	987
Commodity derivatives — Electric Utilities	$	—	$	2,484	$	—	$	—	$	2,484
Total	$	—	$	3,612	$	—	$	(141)	$	3,471

__________

(a) As of September 30, 2021, $18 million of our commodity derivative assets and $0.1 million of our commodity derivative liabilities, as well as related collateral amounts, were subject to master netting agreements. Collateral amounts are included in Other current assets on the Condensed Consolidated Balance Sheets.


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

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

__________

(a) As of December 31, 2020, $1.5 million of our commodity derivative assets and $1.6 million of our commodity derivative liabilities, as well as related collateral amounts, were subject to master netting agreements. Collateral amounts are included in Other current assets on the Condensed Consolidated Balance Sheets.

Pension and Postretirement Plan Assets

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

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Other fair value measures

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

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


	September 30, 2021				December 31, 2020
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current maturities (a)	$	4,125,571	$	4,614,244	$	3,536,536	$	4,208,167

__________

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

(9) Other Comprehensive Income

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

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


	Location on the Condensed Consolidated Statements of Income	Amount Reclassified from AOCI
		Three Months Ended September 30,				Nine Months Ended September 30,
		2021		2020		2021		2020
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	$	(712)	$	(712)	$	(2,138)	$	(2,138)
Commodity contracts	Fuel, purchased power and cost of natural gas sold	331		(178)		356		(734)
		(381)		(890)		(1,782)		(2,872)
Income tax	Income tax (expense)	(26)		209		308		680
Total reclassification adjustments related to cash flow hedges, net of tax		$	(407)	$	(681)	$	(1,474)	$	(2,192)

Amortization of components of defined benefit plans:
Prior service cost	Operations and maintenance	$	25	$	24	$	74	$	79
Actuarial gain (loss)	Operations and maintenance	(598)		(597)		(1,793)		(1,791)
		(573)		(573)		(1,719)		(1,712)
Income tax	Income tax (expense)	133		143		492		407
Total reclassification adjustments related to defined benefit plans, net of tax		$	(440)	$	(430)	$	(1,227)	$	(1,305)
Total reclassifications		$	(847)	$	(1,111)	$	(2,701)	$	(3,497)

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


	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps		Commodity Derivatives		Employee Benefit Plans		Total
As of December 31, 2020	$	(12,558)	$	2	$	(14,790)	$	(27,346)
Other comprehensive income (loss)
before reclassifications	—		5,476		—		5,476
Amounts reclassified from AOCI	1,743		(269)		1,227		2,701
As of September 30, 2021	$	(10,815)	$	5,209	$	(13,563)	$	(19,169)

	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	—		181		55		236
Amounts reclassified from AOCI	1,630		562		1,305		3,497
As of September 30, 2020	$	(13,492)	$	287	$	(13,717)	$	(26,922)

(10) Employee Benefit Plans

Defined Benefit Pension Plan

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Service cost	$	1,260	$	1,352	$	3,779	$	4,058
Interest cost	2,328		3,356		6,984		10,069
Expected return on plan assets	(5,219)		(5,647)		(15,657)		(16,943)

Net loss	1,828		2,093		5,486		6,279
Net periodic benefit cost	$	197	$	1,154	$	592	$	3,463

Defined Benefit Postretirement Healthcare Plan

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Service cost	$	560	$	514	$	1,678	$	1,542
Interest cost	264		412		793		1,237
Expected return on plan assets	(34)		(46)		(102)		(137)
Prior service cost (benefit)	(108)		(136)		(326)		(410)
Net loss	116		5		350		15
Net periodic benefit cost	$	798	$	749	$	2,393	$	2,247

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Supplemental Non-qualified Defined Benefit and Defined Contribution Plans

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Service cost	$	235	$	1,035	$	1,948	$	1,482
Interest cost	176		274		530		824
Prior service cost	—		1		—		1
Net loss	439		425		1,316		1,277
Net periodic benefit cost	$	850	$	1,735	$	3,794	$	3,584

Contributions

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


	Contributions Made		Additional Contributions		Contributions
	Nine Months Ended September 30, 2021		Anticipated for 2021		Anticipated for 2022
Defined Benefit Pension Plan	$	—	$	—	$	3,900
Non-pension Defined Benefit Postretirement Healthcare Plan	$	4,145	$	1,382	$	5,202
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans	$	1,445	$	482	$	2,149

(11) Income Taxes

Winter Storm Uri

As discussed in Note 2 above, our Utilities submitted cost recovery applications which seek to recover incremental costs from Winter Storm Uri through a regulatory mechanism. 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 $130 million. 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 a NOL in our 2021 federal and state income tax returns. Our federal NOL carryforwards no longer expire due to the TCJA; however, our state NOL carryforwards expire at various dates from 2021 to 2041. We do not anticipate material changes to our valuation allowance against the state NOL carryforwards from Winter Storm Uri. Therefore, we did not record an additional valuation allowance against the state NOL carryforwards as of September 30, 2021.

Income Tax (Expense) and Effective Tax Rates

Three Months Ended September 30, 2021 Compared to the Three Months Ended September 30, 2020

Income tax (expense) and the effective tax rate were comparable to the same period in the prior year.

Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 2020

Income tax (expense) for the nine months ended September 30, 2021 was $(6.3) million compared to $(25) million reported for the same period in 2020. For the nine months ended September 30, 2021, the effective tax rate was 3.5% compared to 13.6% for the same period in 2020. The lower effective tax rate is primarily due to $10 million of increased tax benefits from Colorado Electric and Nebraska Gas TCJA-related bill credits to customers (which is offset by reduced revenue), $3.2 million of increased tax benefits from federal production tax credits associated with new wind assets, $2.2 million of increased tax benefits from amortization of excess deferred income taxes, $1.9 million of tax benefits from various statutory rate changes and $1.1 million of increased flow-through tax benefits related to repairs and certain indirect costs. These current year tax benefits were partially offset by a prior year tax benefit from the reversal of accrued excess deferred income taxes as part of resolving the last of the Company’s open dockets seeking approval of its TCJA plans.

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(12) Business Segment Information

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

Accounting standards for presentation of segments require an approach based on the way we organize the segments for making operating decisions and how the 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:	September 30, 2021		December 31, 2020
Electric Utilities	$	3,267,074	$	3,120,928
Gas Utilities	5,052,898		4,376,204
Power Generation	398,915		404,220
Mining	76,791		77,085
Corporate and Other	114,712		110,349
Total assets	$	8,910,390	$	8,088,786



Three Months Ended September 30, 2021	External Operating Revenue				Inter-company Operating Revenue				Total Revenues
	Contract Customers		Other Revenues		Contract Customers		Other Revenues
Segment:
Electric Utilities	$	207,374	$	203	$	5,526	$	—	$	213,103
Gas Utilities	161,977		1,087		1,520		99		164,683
Power Generation	2,333		412		23,725		50		26,520
Mining	6,969		235		8,845		339		16,388
Inter-company eliminations	—		—		(39,616)		(488)		(40,104)
Total	$	378,653	$	1,937	$	—	$	—	$	380,590



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

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Nine Months Ended September 30, 2021	External Operating Revenue				Inter-company Operating Revenue				Total Revenues
	Contract Customers		Other Revenues		Contract Customers		Other Revenues
Segment:
Electric Utilities	$	604,966	$	2,619	$	17,859	$	—	$	625,444
Gas Utilities	743,663		4,745		4,559		285		753,252
Power Generation	8,006		1,219		71,656		150		81,031
Mining	20,658		718		23,093		1,020		45,489
Inter-company eliminations	—		—		(117,167)		(1,455)		(118,622)
Total	$	1,377,293	$	9,301	$	—	$	—	$	1,386,594



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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Adjusted operating income:
Electric Utilities	$	57,608	$	52,083	$	114,989	$	121,726
Gas Utilities	17,257		18,147		139,336		139,253
Power Generation	10,323		8,738		32,842		31,489
Mining	4,908		3,505		11,813		9,992
Corporate and Other	(223)		(239)		(3,526)		(108)
Operating income	89,873		82,234		295,454		302,352

Interest expense, net	(38,018)		(36,041)		(113,820)		(107,039)
Impairment of investment	—		—		—		(6,859)
Other income (expense), net	1,560		(1,193)		1,635		(703)
Income tax (expense)	(5,253)		(4,651)		(6,333)		(25,484)
Net income	48,162		40,349		176,936		162,267
Net income attributable to non-controlling interest	(4,050)		(4,066)		(11,347)		(11,844)
Net income available for common stock	$	44,112	$	36,283	$	165,589	$	150,423

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(13) Selected Balance Sheet Information

Accounts Receivable and Allowance for Credit Losses

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


	September 30, 2021		December 31, 2020
Accounts receivable, trade	$	120,930	$	146,899
Unbilled revenue	63,338		126,065
Less: Allowance for credit losses	(2,312)		(7,003)
Accounts receivable, net	$	181,956	$	265,961

Changes to allowance for credit losses for the nine months ended September 30, 2021 and 2020, respectively, were as follows (in thousands):


	Balance at Beginning of Year		Additions Charged to Costs and Expenses		Recoveries and Other Additions		Write-offs and Other Deductions		Balance at September 30,
2021	$	7,003	$	1,111	$	2,420	$	(8,222)	$	2,312
2020	$	2,444	$	8,471	$	3,720	$	(6,026)	$	8,609

Materials, Supplies and Fuel

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


	September 30, 2021		December 31, 2020
Materials and supplies	$	85,612	$	85,250
Fuel - Electric Utilities	1,240		1,531
Natural gas in storage	58,891		30,619
Total materials, supplies and fuel	$	145,743	$	117,400

Accrued Liabilities

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


	September 30, 2021		December 31, 2020
Accrued employee compensation, benefits and withholdings	$	72,328	$	77,806
Accrued property taxes	44,231		47,105
Customer deposits and prepayments	53,652		52,185
Accrued interest	46,532		31,520
Other (none of which is individually significant)	33,092		34,996
Total accrued liabilities	$	249,835	$	243,612

(14) 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 Colorado Gas, Kansas Gas and Wyoming Gas regulatory activity disclosed in Note 2.

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

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

Executive Summary

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

Recent Developments

Winter Storm Uri

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. Proceeds from the August 26, 2021 debt transaction were used to repay amounts outstanding under this term loan. See Note 5 of the Notes to Condensed Consolidated Financial Statements for further information.

During the second quarter, our Utilities submitted cost recovery applications with the utility commissions in our state jurisdictions to recover incremental costs associated with Winter Storm Uri. To date, several of our Utilities have received interim or final Commission Orders and have begun recovering costs from customers. See Note 2 of the Notes to Condensed Consolidated Financial Statements for further information on our regulatory activity.

COVID-19 Update

For the nine months ended September 30, 2021, we did not experience significant impacts to our financial results, liquidity or operational activities due to COVID-19. We continue to monitor loads, customers’ ability to pay, the potential for supply chain disruption that may impact our capital and maintenance project plans, the availability of third-party resources to execute our business plans and the capital markets to ensure we have the liquidity necessary to support our financial needs. State Orders lifting temporarily suspended disconnections have been issued in all of our jurisdictions.

On September 9, 2021 the Biden administration announced a mandatory COVID-19 vaccination plan, which directs OSHA to develop a rule requiring employers with 100 or more employees to ensure their workforce is fully vaccinated or require any workers who remain unvaccinated to produce a negative test result on at least a weekly basis. We are closely monitoring updates from OSHA including the effective date of this rule. If an OSHA vaccine rule is implemented, the extent of the regulatory impact is unclear but it could have an adverse impact on the Company's workforce, labor relations and operations.

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

Business Segment Highlights and Corporate Activity

Electric Utilities

•Wyoming Electric announced its Ready Wyoming electric transmission expansion initiative. The 285-mile, multi-phase transmission expansion project will serve the growing needs of customers by enhancing the resiliency of its overall electric system and expanding access to power markets and renewable resources. The project will help Wyoming Electric maintain top-quartile reliability and enable economic growth in the Cheyenne region. Wyoming Electric plans to file an application seeking WPSC approval for the project in the first quarter of 2022. If approved, construction is expected to commence in early 2023.

•On July 28, 2021, Wyoming Electric set a new all-time and summer peak load of 274 MW, exceeding the previous peak of 271 MW set in July 2020.

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•On July 27, 2021, South Dakota Electric set a new all-time and summer peak load of 397 MW, exceeding the previous peak of 378 MW set in August 2020.

•On June 30, 2021, South Dakota Electric and Wyoming Electric submitted an IRP to the SDPUC and WPSC. The IRP outlines a range of options for the two electric utilities to meet long-term forecasted energy needs over a 20-year planning horizon. The analysis focused on the least-cost resource needs to best meet customers’ future peak energy needs while maintaining system flexibility and achieving the Company’s generation emissions reduction goals. The IRP’s preferred options for the near-term planning period through 2026 propose the addition of 100 MW of renewable generation, the conversion of Neil Simpson II to natural gas in 2025 and consideration of up to 20 MW of battery storage.

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

•See Note 2 of the Notes to Condensed Consolidated Financial Statements for recent regulatory activity for our Gas Utilities in Colorado, Iowa, Kansas and Nebraska.

Power Generation

•In September 2021, Wygen I experienced an unplanned outage which had a $2.3 million negative impact to operating income for the three and nine months ended September 30, 2021.

Corporate and Other

•On August 26, 2021, we completed a public debt offering which consisted of $600 million, 1.037% 3-year senior unsecured notes due August 23, 2024. The proceeds from the offering were used to repay amounts outstanding under our term loan entered into on February 24, 2021. See Note 5 of the Notes to Condensed Consolidated Financial Statements for further information.

•On July 19, 2021, we amended and restated our corporate Revolving Credit Facility. See Note 5 of the Notes to Condensed Consolidated Financial Statements for further information.

Results of Operations

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

Certain lines of business in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements. In particular, the normal peak usage season for our Electric Utilities is June through August while the normal peak usage season for our Gas Utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and nine months ended September 30, 2021 and 2020, and our financial condition as of September 30, 2021 and December 31, 2020, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period or for the entire year.

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Consolidated Summary and Overview


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020			2021		2020
	(in thousands, except per share amounts)




Adjusted operating income (a):
Electric Utilities	$	57,608	$	52,083		$	114,989	$	121,726
Gas Utilities	17,257		18,147			139,336		139,253
Power Generation	10,323		8,738			32,842		31,489
Mining	4,908		3,505			11,813		9,992
Corporate and Other	(223)		(239)			(3,526)		(108)
Operating income	89,873		82,234			295,454		302,352

Interest expense, net	(38,018)		(36,041)			(113,820)		(107,039)
Impairment of investment	—		—			—		(6,859)
Other income (expense), net	1,560		(1,193)			1,635		(703)
Income tax (expense)	(5,253)		(4,651)			(6,333)		(25,484)
Net income	48,162		40,349			176,936		162,267
Net income attributable to non-controlling interest	(4,050)		(4,066)			(11,347)		(11,844)
Net income available for common stock	$	44,112	$	36,283		165,589		150,423

Total earnings per share of common stock, Diluted	$	0.70	$	0.58		$	2.63	$	2.41

__________

(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 September 30, 2021 Compared to Three Months Ended September 30, 2020

The variance to the prior year included the following:

•Electric Utilities’ adjusted operating income increased $5.5 million primarily due to favorable mark-to-market adjustments on wholesale energy contacts, residential customer growth and increased usage, and increased power marketing and wholesale revenues which were partially offset by higher operating expenses;

•Gas Utilities’ adjusted operating income decreased $0.9 million primarily due to higher operating expenses and unfavorable weather which led to decreased irrigation loads and lower heating demand mostly offset by favorable market-to-market adjustments on wholesale commodity contracts, new rates and prior year COVID-19 impacts;

•Power Generation’s adjusted operating income increased $1.6 million primarily driven by lower operating expenses due to early retirement of certain assets in the prior year partially offset by negative impacts of an unplanned outage at Wygen I;

•Mining’s adjusted operating income increased $1.4 million primarily due to higher prices per ton sold under our cost based supply agreements;

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

•Other income increased $2.8 million primarily due to lower non-service pension costs driven by a lower discount rate, lower costs for our non-qualified benefit plans which were driven by market performance and recognition of death benefits from Company-owned life insurance.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

The variance to the prior year included the following:

•Electric Utilities’ adjusted operating income decreased $6.7 million primarily due to Colorado Electric’s TCJA-related bill credits to customers, impacts from Winter Storm Uri and unfavorable mark-to-market adjustments on wholesale energy contracts partially offset by increased rider revenues, increased power marketing and wholesale revenues, residential customer growth and increased usage, and prior year COVID-19 impacts;

•Gas Utilities’ adjusted operating income increased $0.1 million primarily due to new rates, higher heating demand from colder weather and favorable market-to-market adjustments on wholesale commodity contracts mostly offset by Winter Storm Uri costs incurred by Black Hills Energy Services, Nebraska Gas TCJA-related bill credits to customers, and higher operating expenses;

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•Power Generation’s adjusted operating income increased $1.4 million primarily due to lower operating expenses driven by early retirement of certain assets in the prior year and favorable impacts from Winter Storm Uri partially offset by unfavorable impacts from current year outages;

•Mining’s adjusted operating income increased $1.8 million primarily due to lower operating expenses driven by lower tons sold and overburden removed;

•Corporate and Other expenses increased $3.4 million primarily due to a prior year favorable true-up of employee costs allocated to our subsidiaries in the current year, which is offset in our business segments;

•Interest expense increased $6.8 million 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;

•Other income increased $2.3 million due to lower non-service pension costs driven by a lower discount rate and recognition of death benefits from Company-owned life insurance; and

•Income tax expense decreased $19.2 million due to lower pre-tax income and a lower effective tax rate driven primarily by tax benefits from Colorado Electric and Nebraska Gas TCJA-related bill credits.

Segment Operating Results

A discussion of operating results from our business segments follows.

Non-GAAP Financial Measure

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

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

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

Electric Utilities

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2021		2020		Variance		2021		2020		Variance

Revenue	$	213,103	$	200,842	$	12,261	$	625,444	$	538,181	$	87,263

Total fuel and purchased power	82,794		77,885		4,909		290,101		201,398		88,703

Gross margin (non-GAAP)	130,309		122,957		7,352		335,343		336,783		(1,440)

Operations and maintenance	47,293		47,426		(133)		144,832		144,956		(124)
Depreciation and amortization	25,408		23,448		1,960		75,522		70,101		5,421
Total operating expenses	72,701		70,874		1,827		220,354		215,057		5,297

Adjusted operating income	$	57,608	$	52,083	$	5,525	$	114,989	$	121,726	$	(6,737)

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Three Months Ended September 30, 2021 Compared to the Three Months Ended September 30, 2020:

Gross margin for the three months ended September 30, 2021 increased as a result of the following:


	(in millions)
Mark-to-market on wholesale energy contracts	$	3.9
Residential customer growth and increased usage per customer	2.5
Increased commercial and industrial demand	1.2
Power marketing and wholesale	1.1
Prior year COVID-19 impacts	0.2
Prior year release of TCJA revenue reserves	(1.5)
Weather	(0.5)
Other	0.5
Total change in Gross margin (non-GAAP)	$	7.4

Operations and maintenance expense was comparable to the same period in the prior year.

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

Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 2020:

Gross margin for the nine months ended September 30, 2021 decreased as a result of the following:



	(in millions)
TCJA-related bill credits (a)	$	(10.2)
Winter Storm Uri impacts (b)	(2.9)
Mark-to-market on wholesale energy contracts	(2.4)
Prior year release of TCJA revenue reserves	(2.2)
Weather	(0.1)
Power marketing and wholesale	6.6
Residential customer growth and increased usage per customer	3.2
Rider recovery	2.9
Increased commercial and industrial demand	1.7
Prior year COVID-19 impacts	1.7
Other	0.2
Total change in Gross margin (non-GAAP)	$	(1.5)

________________

(a) In February and April 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 $0.8 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 remained constant primarily due to higher maintenance costs related to planned and unplanned outages at the Gillette, Wyoming energy complex and higher operating expenses associated with Corriedale which was placed in service November 30, 2020, offset by prior year expenses related to the municipalization efforts in Pueblo, Colorado.

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

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Operating Statistics


	Revenue (in thousands)								Quantities Sold (MWh)
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,		Nine Months Ended September 30,
	2021		2020		2021		2020		2021	2020	2021	2020

Residential	$	66,138	$	62,395	$	192,349	$	167,048	419,001	405,989	1,150,150	1,113,821
Commercial	70,696		64,756		214,512		178,979		576,037	538,299	1,570,455	1,492,239
Industrial	37,323		35,660		115,518		99,725		459,076	462,545	1,316,060	1,382,710
Municipal	5,069		4,834		14,471		12,732		47,515	46,256	123,620	121,027
Subtotal Retail Revenue - Electric	179,226		167,645		536,850		458,484		1,501,629	1,453,089	4,160,285	4,109,797
Contract Wholesale	7,939		5,924		22,155		14,947		129,221	129,960	415,979	348,991
Off-system/Power Marketing Wholesale	11,065		9,535		22,378		17,939		151,250	167,494	467,440	469,590
Other	14,873		17,738		44,061		46,811		—	—	—	—
Total Revenue and Energy Sold	213,103		200,842		625,444		538,181		1,782,100	1,750,543	5,043,704	4,928,378
Other Uses, Losses or Generation, net	—		—		—		—		139,093	118,410	363,815	294,466
Total Revenue and Energy	213,103		200,842		625,444		538,181		1,921,193	1,868,953	5,407,519	5,222,844
Less cost of fuel and purchased power	82,794		77,885		290,101		201,398
Gross Margin (non-GAAP)	$	130,309	$	122,957	$	335,343	$	336,783



Three Months Ended September 30,	Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)				Quantities Sold (MWh)(a)
	2021		2020		2021		2020		2021	2020
Colorado Electric	$	83,274	$	74,742	$	45,482	$	42,236	720,592	666,916
South Dakota Electric	81,787		78,861		62,081		58,062		709,862	699,150
Wyoming Electric	48,042		47,239		22,746		22,659		490,739	502,887
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold	$	213,103	$	200,842	$	130,309	$	122,957	1,921,193	1,868,953



Nine Months Ended September 30,	Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)				Quantities Sold (MWh)(a)
	2021		2020		2021		2020		2021	2020
Colorado Electric	$	227,328	$	191,197	$	103,982	$	106,961	1,945,741	1,765,501
South Dakota Electric	250,617		213,059		163,523		163,659		1,997,696	1,954,902
Wyoming Electric	147,499		133,925		67,838		66,163		1,464,082	1,502,441
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold	$	625,444	$	538,181	$	335,343	$	336,783	5,407,519	5,222,844

________________

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

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	Three Months Ended September 30,		Nine Months Ended September 30,
Quantities Generated and Purchased (MWh)	2021	2020	2021	2020

Generated:
Coal	589,194	592,681	1,569,410	1,712,540
Natural Gas and Oil	231,433	199,408	535,148	453,950
Wind	90,496	54,518	315,654	191,696
Total Generated	911,123	846,607	2,420,212	2,358,186
Purchased	1,010,070	1,022,346	2,987,307	2,864,658
Total Generated and Purchased	1,921,193	1,868,953	5,407,519	5,222,844


	Three Months Ended September 30,		Nine Months Ended September 30,
Quantities Generated and Purchased (MWh)	2021	2020	2021	2020
Generated:
Colorado Electric	150,646	97,450	351,723	271,957
South Dakota Electric	538,632	518,821	1,450,114	1,434,353
Wyoming Electric	221,845	230,336	618,375	651,876
Total Generated	911,123	846,607	2,420,212	2,358,186

Purchased:
Colorado Electric	569,946	569,466	1,594,018	1,493,544
South Dakota Electric	171,229	180,329	547,582	520,549
Wyoming Electric	268,895	272,551	845,707	850,565
Total Purchased	1,010,070	1,022,346	2,987,307	2,864,658

Total Generated and Purchased	1,921,193	1,868,953	5,407,519	5,222,844


	Three Months Ended September 30,
	2021			2020
Degree Days	Actual	Variance from Normal		Actual	Variance from Normal
Heating Degree Days:
Colorado Electric	22	(78)	%	99	1	%
South Dakota Electric	90	(60)	%	202	(10)	%
Wyoming Electric	112	(62)	%	208	(29)	%
Combined (a)	63	(65)	%	156	(14)	%

Cooling Degree Days:
Colorado Electric	942	38	%	987	44	%
South Dakota Electric	649	22	%	561	5	%
Wyoming Electric	487	63	%	492	65	%
Combined (a)	751	35	%	742	34	%

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	Nine Months Ended September 30,
	2021			2020
Degree Days	Actual	Variance from Normal		Actual	Variance from Normal
Heating Degree Days
Colorado Electric	3,348	(1)	%	3,073	(9)	%
South Dakota Electric	4,462	—	%	4,440	—	%
Wyoming Electric	4,594	2	%	4,356	(3)	%
Combined (a)	3,979	—	%	3,799	(4)	%

Cooling Degree Days:
Colorado Electric	1,242	39	%	1,369	53	%
South Dakota Electric	816	29	%	681	8	%
Wyoming Electric	604	74	%	593	70	%
Combined (a)	968	39	%	977	41	%

____________________

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


	Three Months Ended September 30,				Nine Months Ended September 30,
Contracted generating facilities Availability by fuel type (a)	2021		2020		2021		2020
Coal (b)	96.3	%	97.4	%	88.5	%	94.1	%
Natural Gas and diesel oil (b) (c)	96.5	%	79.7	%	93.8	%	80.5	%
Wind	97.0	%	97.7	%	95.6	%	98.3	%
Total Availability	96.5	%	86.8	%	92.4	%	86.3	%

Wind capacity factor	34.1	%	33.2	%	38.0	%	39.3	%

____________________

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

(b) 2021 included planned outages at Neil Simpson II, Wygen II, Wygen III and Pueblo Airport Generation and unplanned outages at Neil Simpson II and Wyodak Plant.

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Gas Utilities

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2021		2020		Variance		2021		2020		Variance
Revenue:
Natural gas - regulated	$	150,075	$	128,468	$	21,607	$	700,617	$	612,797	$	87,820
Other - non-regulated services	14,608		15,461		(853)		52,635		53,015		(380)
Total revenue	164,683		143,929		20,754		753,252		665,812		87,440

Cost of sales:
Natural gas - regulated	43,883		25,235		18,648		289,167		222,144		67,023
Other - non-regulated services	(749)		1,800		(2,549)		10,132		4,874		5,258
Total cost of sales	43,134		27,035		16,099		299,299		227,018		72,281

Gross margin (non-GAAP)	121,549		116,894		4,655		453,953		438,794		15,159

Operations and maintenance	78,161		73,642		4,519		237,624		223,351		14,273
Depreciation and amortization	26,131		25,105		1,026		76,993		76,190		803
Total operating expenses	104,292		98,747		5,545		314,617		299,541		15,076

Adjusted operating income	$	17,257	$	18,147	$	(890)	$	139,336	$	139,253	$	83

Three Months Ended September 30, 2021 Compared to the Three Months Ended September 30, 2020:

Gross margin for the three months ended September 30, 2021 increased as a result of:


	(in millions)
Mark-to-market on non-utility natural gas commodity contracts	$	2.3
New rates	2.0
Winter Storm Uri carrying costs (a)	1.7
Prior year COVID-19 impacts	0.8
Weather (b)	(3.4)
Other	1.3
Total increase in Gross margin (non-GAAP)	$	4.7

__________

(a) In certain jurisdictions, we have accrued Winter Storm Uri carrying costs and began recovering from customers. See Note 2 of the Notes to Condensed Consolidated Financial Statements for additional information.

(b) Weather impacts for the three months ended September 30, 2021 compared to the same period in the prior year include decreased irrigation loads to agriculture customers and decreased heating demand due to warmer temperatures.

Operations and maintenance expense increased primarily due to $3.4 million of higher employee costs, $1.2 million of higher outside services related expenses, $1.1 million of increased property taxes due to a higher asset base and $0.7 million of prior year COVID-19 savings due to lower travel and training expenses partially offset by $2.2 million of decreased bad debt expense associated with lower expected credit losses.

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

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Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 2020:

Gross margin for the nine months ended September 30, 2021 increased as a result of the following:



	(in millions)
New rates	$	16.7
Weather	4.2
Mark-to-market on non-utility natural gas commodity contracts	3.5
Winter Storm Uri carrying costs (a)	1.7
Prior year COVID-19 impacts	1.7
Black Hills Energy Services Winter Storm Uri costs (b)	(8.2)
TCJA-related bill credits (c)	(2.9)
Non-utility - Service Guard Comfort Plan and Gas Supply Services	(2.9)
Other	1.4
Total increase in Gross margin (non-GAAP)	$	15.2

__________

(b) 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.

(c) In June 2021, Nebraska Gas 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.

Operations and maintenance expense increased primarily due to $10.3 million of higher employee costs, $4.0 million of higher outside services related expenses, $3.4 million of higher facilities and office related expenses driven by prior year COVID-19 savings, and $2.7 million of increased property taxes due to a higher asset base partially offset by $5.6 million of decreased bad debt expense associated with lower expected credit losses.

Operating Statistics


	Revenue (in thousands)					Gross Margin (non-GAAP) (in thousands)					Gas Utilities Quantities Sold & Transported (Dth)
	Three Months Ended September 30,				Three Months Ended September 30,					Three Months Ended September 30,
	2021		2020			2021		2020			2021	2020

Residential	$	68,646	$	61,515		$	49,349	$	48,165		3,564,722	4,058,040
Commercial	27,038		19,940			13,999		12,821			2,426,019	2,354,719
Industrial	13,863		7,280			2,316		2,514			2,873,540	2,674,127
Other	2,706		1,271			2,706		1,271			—	—
Total Distribution	112,253		90,006			68,370		64,771			8,864,281	9,086,886

Transportation and Transmission	37,822		38,462			37,822		38,462			34,735,601	33,668,174

Total Regulated	150,075		128,468			106,192		103,233			43,599,882	42,755,060

Non-regulated Services	14,608		15,461			15,357		13,661

Total Gas Revenue & Gross Margin (non-GAAP)	$	164,683	$	143,929		$	121,549	$	116,894

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	Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)				Gas Utilities Quantities Sold & Transported (Dth)
	Nine Months Ended September 30,				Nine Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020		2021	2020

Residential	$	401,413	$	351,986	$	219,885	$	207,654	42,708,511	40,790,670
Commercial	155,015		127,617		66,447		61,676		20,732,271	19,155,051
Industrial	24,576		18,539		5,505		6,697		5,109,501	5,771,732
Other	1,816		856		1,816		856		—	—
Total Distribution	582,820		498,998		293,653		276,883		68,550,283	65,717,453

Transportation and Transmission	117,797		113,799		117,797		113,770		114,124,253	108,967,182

Total Regulated	700,617		612,797		411,450		390,653		182,674,536	174,684,635

Non-regulated Services	52,635		53,015		42,503		48,141

Total Gas Revenue & Gross Margin (non-GAAP)	$	753,252	$	665,812	$	453,953	$	438,794



	Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)						Gas Utilities Quantities Sold & Transported (Dth)
	Three Months Ended September 30,					Three Months Ended September 30,					Three Months Ended September 30,
	2021		2020				2021		2020			2021	2020

Arkansas Gas	$	25,188	$	21,043			$	18,468	$	17,400		4,319,944	3,925,893
Colorado Gas	22,452		22,724				17,097		16,972			3,798,587	3,702,666
Iowa Gas	22,015		18,155				14,442		14,672			5,810,932	5,628,110
Kansas Gas	25,972		18,591				13,600		13,099			9,075,960	8,564,408
Nebraska Gas	51,538		46,315				42,896		39,755			16,174,821	16,525,547
Wyoming Gas	17,518		17,101				15,046		14,996			4,419,638	4,408,436
Total Gas Revenue & Gross Margin (non-GAAP)	$	164,683	$	143,929			$	121,549	$	116,894		43,599,882	42,755,060



	Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)				Gas Utilities Quantities Sold & Transported (Dth)
	Nine Months Ended September 30,				Nine Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020		2021	2020

Arkansas Gas	$	145,176	$	124,621	$	93,319	$	88,161	23,345,095	19,795,077
Colorado Gas	135,764		123,943		75,919		73,785		23,121,887	21,845,915
Iowa Gas	108,600		94,386		53,082		50,355		27,141,518	25,429,502
Kansas Gas	87,198		70,571		45,110		44,162		26,694,184	25,202,180
Nebraska Gas	187,673		170,447		124,923		122,140		59,281,802	56,857,061
Wyoming Gas	88,841		81,844		61,600		60,191		23,090,050	25,554,900
Total Gas Revenue & Gross Margin (non-GAAP)	$	753,252	$	665,812	$	453,953	$	438,794	182,674,536	174,684,635

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	Three Months Ended September 30,
	2021		2020
Heating Degree Days	Actual	Variance from Normal	Actual	Variance from Normal
Arkansas Gas (a)	11	(74)%	24	(44)%
Colorado Gas	92	(51)%	159	(26)%
Iowa Gas	42	(70)%	140	1%
Kansas Gas (a)	10	(82)%	70	27%
Nebraska Gas	33	(70)%	109	(1)%
Wyoming Gas	153	(50)%	245	(20)%
Combined Gas (b)	53	(61)%	125	(13)%



	Nine Months Ended September 30,
	2021		2020
Heating Degree Days:	Actual	Variance from Normal	Actual	Variance from Normal
Arkansas Gas (a)	2,515	1%	2,036	(18)%
Colorado Gas	3,922	(4)%	3,797	(7)%
Iowa Gas	4,155	(1)%	4,104	(2)%
Kansas Gas (a)	3,079	4%	2,851	(4)%
Nebraska Gas	3,754	(1)%	3,636	(4)%
Wyoming Gas	4,778	1%	4,678	(1)%
Combined Gas (b)	3,978	—%	3,731	(4)%

__________

(a) Arkansas Gas and Kansas Gas 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 Gas due to its weather normalization mechanism. Arkansas Gas is partially excluded based on the weather normalization mechanism in effect from November through April.

Regulatory Matters

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

Power Generation

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2021		2020		Variance		2021		2020		Variance

Revenue	$	26,520	$	26,518	$	2	$	81,031	$	78,606	$	2,425

Fuel expense	2,547		2,320		227		7,839		6,692		1,147
Operations and maintenance	8,233		10,539		(2,306)		24,913		24,886		27
Depreciation and amortization	5,417		4,921		496		15,437		15,539		(102)
Total operating expense	16,197		17,780		(1,583)		48,189		47,117		1,072

Adjusted operating income	$	10,323	$	8,738	$	1,585	$	32,842	$	31,489	$	1,353

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Three Months Ended September 30, 2021 Compared to the Three Months Ended September 30, 2020:

The increase in current year adjusted operating income was primarily driven by a prior year $3.1 million expense related to the early retirement of certain assets partially offset by $2.3 million of negative impacts from a current year unplanned outage at Wygen I.

Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 2020:

Adjusted operating income increased compared to the same period in the prior year primarily due to a prior year $3.1 million expense related to the early retirement of certain assets and $1.7 million of favorable Winter Storm Uri impacts realized under Black Hills Wyoming’s Economy Energy PSA partially offset by negative impacts of current year planned and unplanned outages.

Operating Statistics


	Revenue (in thousands)				Quantities Sold (MWh) (a)		Revenue (in thousands)				Quantities Sold (MWh) (a)
	Three Months Ended September 30,						Nine Months Ended September 30,
	2021		2020		2021	2020	2021		2020		2021	2020
Black Hills Colorado IPP	$	14,627	$	14,527	275,237	301,934	$	42,862	$	42,917	718,496	830,860
Black Hills Wyoming (b)	10,634		10,757		146,525	157,855	34,208		31,403		453,291	471,073
Black Hills Electric Generation	1,259		1,234		72,493	65,697	3,961		4,286		257,511	255,605
Total Power Generation Revenue and Quantities Sold	$	26,520	$	26,518	494,255	525,486	$	81,031	$	78,606	1,429,298	1,557,538


		Three Months Ended September 30,		Nine Months Ended September 30,
Quantities Generated and Purchased (MWh) (a)	Fuel Type	2021	2020	2021	2020
Generated
Black Hills Colorado IPP	Natural Gas	275,237	301,934	718,496	830,860
Black Hills Wyoming (b)	Coal	123,705	139,313	388,059	408,545
Black Hills Electric Generation	Wind	72,493	65,697	257,511	255,605
Total Generated		471,435	506,944	1,364,066	1,495,010

Purchased
Black Hills Wyoming (b)	Various	23,575	18,004	68,184	62,097
Total Purchased		23,575	18,004	68,184	62,097

____________

(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.


	Three Months Ended September 30,				Nine Months Ended September 30,
Contracted generating facilities Availability by fuel type (a)	2021		2020		2021		2020

Coal (b)	84.9	%	96.1	%	90.4	%	94.5	%
Natural gas (b)	99.7	%	99.8	%	95.3	%	99.6	%
Wind	96.2	%	90.6	%	95.9	%	92.8	%
Total Availability	96.0	%	95.8	%	94.7	%	96.3	%

Wind capacity factor	21.5	%	19.4	%	25.6	%	25.7	%

____________________

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

(b) 2021 included planned and unplanned outages at Wygen I and planned outages at Pueblo Airport Generation.

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Mining

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2021		2020		Variance		2021		2020		Variance

Revenue	$	16,388	$	15,236	$	1,152	$	45,489	$	45,857	$	(368)

Operations and maintenance	9,344		8,923		421		26,956		28,481		(1,525)
Depreciation, depletion and amortization	2,136		2,808		(672)		6,720		7,384		(664)
Total operating expenses	11,480		11,731		(251)		33,676		35,865		(2,189)

Adjusted operating income	$	4,908	$	3,505	$	1,403	$	11,813	$	9,992	$	1,821

Three Months Ended September 30, 2021 Compared to the Three Months Ended September 30, 2020:

Revenue increased reflecting a 6% increase in price per ton sold driven by contract price adjustments based on actual mining costs.

Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 2020:

Current year revenue was comparable due to fewer tons sold driven primarily by planned and unplanned outages at the Gillette, Wyoming energy complex mostly offset by a 4% increase in price per ton sold driven by contract price adjustments based on actual mining costs. Operating expenses decreased primarily due to lower overburden and processing costs.

Operating Statistics

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Tons of coal sold	960		940		2,691		2,808
Cubic yards of overburden moved	1,757		1,595		5,188		6,073

Revenue per ton	$	16.47	$	15.60	$	16.26	$	15.64

Corporate and Other

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2021		2020		Variance		2021		2020		Variance

Adjusted operating income (loss)	$	(223)	$	(239)	$	16	$	(3,526)	$	(108)	$	(3,418)

Three Months Ended September 30, 2021 Compared to the Three Months Ended September 30, 2020:

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

Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 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 business segments and had no impact to consolidated results.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2021		2020		Variance		2021		2020		Variance
	(in thousands)
Interest expense, net	$	(38,018)	$	(36,041)	$	(1,977)	$	(113,820)	$	(107,039)	$	(6,781)
Impairment of investment	—		—		$	—	$	—	$	(6,859)	$	6,859
Other income (expense), net	1,560		(1,193)		$	2,753	$	1,635	$	(703)	$	2,338
Income tax (expense)	(5,253)		(4,651)		$	(602)	$	(6,333)	$	(25,484)	$	19,151

Three Months Ended September 30, 2021 Compared to the Three Months Ended September 30, 2020:

Interest Expense

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

Other Income (Expense)

The increase in Other income was primarily due to lower non-service pension costs driven by a lower discount rate, lower costs for our non-qualified benefit plans which were driven by market performance and recognition of death benefits from Company-owned life insurance.

Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 2020:

Interest Expense

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

Impairment of Investment

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

Other Income (Expense)

The increase in Other income was primarily due to lower non-service pension costs driven by a lower discount rate and recognition of death benefits from Company-owned life insurance.

Income Tax (Expense)

For the nine months ended September 30, 2021, the effective tax rate was 3.5% compared to 13.6% for the same period in 2020. See Note 11 of the Notes to Condensed Consolidated Financial Statements for discussion of effective tax rate variances.

Liquidity and Capital Resources

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

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.

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Cash Flow Activities

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


Cash provided by (used in):	2021		2020		Variance
Operating activities	$	(144,760)	$	419,459	$	(564,219)
Investing activities	$	(484,106)	$	(529,724)	$	45,618
Financing activities	$	633,061	$	107,819	$	525,242

Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 2020

Operating Activities:

Net cash provided by operating activities was $564 million lower than the same period in 2020. The variance to the prior year was primarily attributable to:

•Cash earnings (net income plus non-cash adjustments) were $14 million lower for the nine months ended September 30, 2021 compared to the same period in the prior year primarily driven by higher operating expenses and higher interest expenses;

•Net inflows from changes in certain operating assets and liabilities were $560 million lower, primarily attributable to:

◦Cash outflows increased by $553 million as a result of changes in our regulatory assets and liabilities primarily driven by incremental costs from Winter Storm Uri;

◦Cash outflows increased by $9.0 million as a result of decreases in accounts payable and accrued liabilities primarily driven by payment timing related to payroll taxes;

◦Cash inflows decreased by $2.3 million as a result of changes in accounts receivable and other current assets primarily driven by increased collections of accounts receivable mostly offset by increased purchases of natural gas in storage;

•Cash outflows decreased by $13 million due to pension contributions made in the prior year; and

•Cash outflows increased by $2.9 million for other operating activities.

Investing Activities:

Net cash used in investing activities was $46 million lower than the same period in 2020. The variance to the prior year was primarily attributable to:

•Capital expenditures of $498 million for the nine months ended September 30, 2021 compared to $536 million for the same period in the prior year. Lower current year expenditures are driven by lower programmatic safety, reliability and integrity spending at our Gas Utilities segments and the prior year Corriedale wind project at our Electric Utilities segment; and

•Cash inflows increased by $7.5 million for other investing activities which was primarily driven by the sales of transmission assets and facilities, none of which were individually significant.

Financing Activities:

Net cash provided by financing activities was $525 million higher than the same period in 2020. The variance to the prior year was primarily attributable to:

•Cash inflows increased $562 million due to short-term and long-term borrowings in excess of repayments;

•Cash inflows decreased $36 million due to lower issuances of common stock;

•Cash outflows increased $7.0 million due to increased dividends paid on common stock;

•Cash outflows decreased $2.4 million due to decreased distributions to non-controlling interests; and

•Cash outflows decreased by $3.7 million for other financing activities.

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Capital Sources

Short-term Debt

Revolving Credit Facility and CP Program

On July 19, 2021, we amended and restated our corporate Revolving Credit Facility under similar terms and conditions, See Note 5 of the Notes to Condensed Consolidated Financial Statements for more information.

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		September 30, 2021		September 30, 2021		September 30, 2021
Revolving Credit Facility and CP Program	July 19, 2026	$	750	$	333	$	23	$	394

__________

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

The weighted average interest rate on short-term borrowings related to our Revolving Credit Facility and CP Program at September 30, 2021 was 0.19%. Short-term borrowing activity related to our Revolving Credit Facility and CP Program for the nine months ended September 30, 2021 was:


	(dollars in millions)
Maximum amount outstanding (based on daily outstanding balances)	$	333
Average amount outstanding (based on daily outstanding balances)	$	224
Weighted average interest rates	0.21		%

Term Loan

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

Long-term Debt

See Note 5 of the Notes to Condensed Consolidated Financial Statements for information related to our long-term debt.

Covenant Requirements

The Revolving Credit Facility and Wyoming Electric’s financing agreements contain covenant requirements. We were in compliance with these covenants as of September 30, 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 strategic objectives. In the fourth quarter of 2021, we plan to fund our capital plan and strategic objectives by using cash generated from operating activities, our Revolving Credit Facility and CP Program and issuing an additional $40 million to $60 million of common stock under the ATM.

Credit Ratings

After assessing the current operating performance, liquidity and 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.

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The following table represents the credit ratings and outlook and risk profile of BHC at September 30, 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 September 30, 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 (c)
Capital Expenditures by Segment	Nine Months Ended September 30, 2021 (a)		2021 (b)		2022		2023		2024		2025
(in millions)
Electric Utilities	$	172	$	251	$	227	$	192	$	271	$	216
Gas Utilities	294		393		363		383		386		349
Power Generation	11		14		7		6		4		7
Mining	6		9		5		6		10		8
Corporate and Other	3		11		9		13		13		13
Incremental Projects (d)	—		—		—		—		—		60
	$	486	$	678	$	611	$	600	$	684	$	653

__________

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

(b) Includes actual capital expenditures for the nine months ended September 30, 2021.

(c) The increase in forecasted capital expenditures is primarily driven by the Ready Wyoming transmission project at our Electric Utilities. Additionally, we have identified various other projects at our Electric and Gas Utilities that were previously disclosed as Incremental.

(d) These represent projects that are being evaluated by our segments for timing, cost and other factors.

Dividends

Dividends paid on our common stock totaled $107 million for the nine months ended September 30, 2021, or $0.565 per share per quarter. On October 26, 2021, our board of directors declared a quarterly dividend of $0.595 per share payable December 1, 2021, equivalent to an annual dividend of $2.38 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.

Unconditional Purchase Obligations

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

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Critical Accounting Policies Involving Significant Estimates

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

New Accounting Pronouncements

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4. CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of September 30, 2021. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at September 30, 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 September 30, 2021, there have been no changes in our internal controls over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS

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

ITEM 1A.RISK FACTORS

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

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

The following table contains monthly information about our acquisitions of equity securities for the three months ended September 30, 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



July 1, 2021 - July 31, 2021	2	$	66.21	—	—
August 1, 2021 - August 31, 2021	260	$	70.24	—	—
September 1, 2021 - September 30, 2021	1	$	71.52	—	—






Total	263	$	70.21	—	—

_____________

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

ITEM 4. MINE SAFETY DISCLOSURES

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

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ITEM 6. EXHIBITS

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


Exhibit Number			Description













4.1			Tenth Supplemental Indenture dated as of August 26, 2021 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on August 26, 2021).








10.1			Fourth Amended and Restated Credit Agreement dated as of July 19, 2021 (relating to $750 million Revolving Credit Facility), 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 July 19, 2021).
31.1*			Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
31.2*			Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
32.1*			Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
32.2*			Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
95*			Mine Safety and Health Administration Safety Data.
101.INS*			XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*			XBRL Taxonomy Extension Schema Document
101.CAL*			XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*			XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*			XBRL Taxonomy Extension Label Linkbase Document
101.PRE*			XBRL Taxonomy Extension Presentation Linkbase Document
104*			Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)

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SIGNATURES

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

BLACK HILLS CORPORATION


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

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

Dated:	November 3, 2021

Document

Exhibit 31.1

CERTIFICATION

I, Linden R. Evans, certify that:


1.	I have reviewed this Quarterly Report on Form 10-Q of Black Hills Corporation;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

	a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

	c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

	a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


Date:	November 3, 2021
		/S/ LINDEN R. EVANS
		Linden R. Evans
		President and Chief Executive Officer

Document

Exhibit 31.2

CERTIFICATION

I, Richard W. Kinzley, certify that:


1.	I have reviewed this Quarterly Report on Form 10-Q of Black Hills Corporation;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

	a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

	c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

	a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


Date:	November 3, 2021
		/S/ RICHARD W. KINZLEY
		Richard W. Kinzley
		Senior Vice President and Chief Financial Officer

Document

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Black Hills Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2021 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Linden R. Evans, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:


			(1)			The Report fully complies with the requirements of Section 13 (a) or 15 (d) of the Securities Exchange Act of 1934; and

			(2)			The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


Date:	November 3, 2021

		/S/ LINDEN R. EVANS
		Linden R. Evans
		President and Chief Executive Officer

Document

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Black Hills Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2021 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Richard W. Kinzley, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:


			(1)			The Report fully complies with the requirements of Section 13 (a) or 15 (d) of the Securities Exchange Act of 1934; and

			(2)			The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


Date:	November 3, 2021

		/S/ RICHARD W. KINZLEY
		Richard W. Kinzley
		Senior Vice President and Chief Financial Officer

Document

Exhibit 95

Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of Dodd-Frank is included below.

Mine Safety and Health Administration Safety Data

Safety is a core value at Black Hills Corporation and at each of its subsidiary operations. We have in place a comprehensive safety program that includes extensive health and safety training for all employees, site inspections, emergency response preparedness, crisis communications training, incident investigation, regulatory compliance training and process auditing, as well as an open dialogue between all levels of employees. The goals of our processes are to eliminate exposure to hazards in the workplace, ensure that we comply with all mine safety regulations, and support regulatory and industry efforts to improve the health and safety of our employees along with the industry as a whole.

Under the Dodd-Frank Act, each operator of a coal or other mine is required to include certain mine safety results in its periodic reports filed with the SEC. Our mining operation, consisting of Wyodak Coal Mine, is subject to regulation by the federal Mine Safety and Health Administration ("MSHA") under the Federal Mine Safety and Health Act of 1977 (the “Mine Act”). Below we present the following information regarding certain mining safety and health matters for the three month period ended September 30, 2021. In evaluating this information, consideration should be given to factors such as: (i) the number of citations and orders will vary depending on the size of the coal mine, (ii) the number of citations issued will vary from inspector to inspector and mine to mine, and (iii) citations and orders can be contested and appealed, and in that process, are often reduced in severity and amount, and are sometimes dismissed. The information presented includes:

•Total number of violations of mandatory health and safety standards that could significantly and substantially contribute to the cause and effect of a coal or other mine safety or health hazard under section 104 of the Mine Act for which we have received a citation from MSHA;

•Total number of orders issued under section 104(b) of the Mine Act;

•Total number of citations and orders for unwarrantable failure of the mine operator to comply with mandatory health and safety standards under section 104(d) of the Mine Act;

•Total number of imminent danger orders issued under section 107(a) of the Mine Act; and

•Total dollar value of proposed assessments from MSHA under the Mine Act.

The table below sets forth the total number of citations and/or orders issued by MSHA to WRDC under the indicated provisions of the Mine Act, together with the total dollar value of proposed MSHA assessments received during the three months ended September 30, 2021 and legal actions pending before the Federal Mine Safety and Health Review Commission, together with the Administrative Law Judges thereof, for WRDC, our only mining complex. All citations were abated within 24 hours of issue.

Mine/ MSHA

Mine Act Section 104 S&S Citations issued during three months ended

Mine Act Section 104(b)

Mine Act Section 104(d) Citations and

Mine Act Section 110(b)(2)

Mine Act Section 107(a) Imminent Danger

Total Dollar Value of Proposed MSHA

Total Number of Mining Related

Received Notice of Potential to Have Pattern Under

Legal Actions Pending as of Last Day of

Legal Actions Initiated During

Legal Actions Resolved During

Identification Number

September 30, 2021

Orders (#)

Violations (#)

Orders (#)

Assessments

Fatalities (#)

Section 104(e) (yes/no)

Period (#) (a)

Period (#)

Wyodak Coal Mine - 4800083

—

________________________

(a) The types of proceedings by class: (1) contests of citations and orders - none; (2) contests of proposed penalties - none; (3) complaints for compensation - none; (4) complaints of discharge, discrimination or interference under Section 105 of the Mine Act - none; (5) applications for temporary relief - none; and (6) appeals of judges' decisions or orders to the FMSHRC - none.