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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2021

OR

☐ 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

x

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

shares

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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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									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.

(c)    In addition to recovery of costs, we are 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

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 natural gas and fuel costs.

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.

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

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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

__________

(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)    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.

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.

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.

(c)    On September 17, 2021, Fitch reported BBB+ 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.

(c)    On September 17, 2021, Fitch reported A 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

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