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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 June 30, 2022

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 July 29, 2022

Common stock, $1.00 par value

65,079,859

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						14
			Note 1. Management’s Statement						14
			Note 2. Regulatory Matters						15
			Note 3. Commitments, Contingencies and Guarantees						17
			Note 4. Revenue						18
			Note 5. Financing						20
			Note 6. Earnings Per Share						21
			Note 7. Risk Management and Derivatives						21
			Note 8. Fair Value Measurements						25
			Note 9. Other Comprehensive Income						27
			Note 10. Employee Benefit Plans						28
			Note 11. Income Taxes						29
			Note 12. Business Segment Information						29
			Note 13. Selected Balance Sheet Information						31

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									Page
Item 2.			Management’s Discussion and Analysis of Financial Condition and Results of Operations						32
			Executive Summary						32
			Recent Developments						32
			Results of Operations						34
			Consolidated Summary and Overview						34
			Non-GAAP Financial Measure						36
			Electric Utilities						36
			Gas Utilities						40
			Corporate and Other						42
			Consolidated Interest Expense, Other Income and Income Tax Expense						43
			Liquidity and Capital Resources						43
			Cash Flow Activities						43
			Capital Resources						45
			Credit Ratings						45
			Capital Requirements						46
			Critical Accounting Estimates						46
			New Accounting Pronouncements						46
Item 3.			Quantitative and Qualitative Disclosures About Market Risk						46
Item 4.			Controls and Procedures						47
PART II. OTHER INFORMATION
Item 1.			Legal Proceedings						47
Item 1A.			Risk Factors						47
Item 2.			Unregistered Sales of Equity Securities and Use of Proceeds						47
Item 4.			Mine Safety Disclosures						47
Item 6.			Exhibits						48
Signatures									49

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GLOSSARY OF TERMS AND ABBREVIATIONS

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

AFUDC			Allowance for Funds Used During Construction
AOCI			Accumulated Other Comprehensive Income (Loss)
APSC			Arkansas Public Service Commission
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 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
Blockchain Interruptible Service (BCIS) tariff			The BCIS tariff was proposed by Wyoming Electric and approved by the WPSC in 2019. The tariff was developed to attract new large electric loads related to blockchain and other industry growth with high energy demand.
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.
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).
Common Use System			The Common Use System is a jointly operated transmission system we participate in with Basin Electric Power Cooperative and Powder River Energy Corporation. The Common Use System provides transmission service over these utilities' combined 230-kilovolt (kV) and limited 69-kV transmission facilities within areas of southwestern South Dakota and northeastern Wyoming.
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.
CPCN			Certificate of Public Convenience and Necessity

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CP Program			Commercial Paper Program
CPUC			Colorado Public Utilities Commission
Dth			Dekatherm. A unit of energy equal to 10 therms or approximately one million British thermal units (MMBtu)
Fitch			Fitch Ratings Inc.
GAAP			Accounting principles generally accepted in the United States of America
Heating Degree Day (HDD)			A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
Integrated Generation			Non-regulated power generation and mining businesses that are vertically integrated within our Electric Utilities segment.
Iowa Gas			Black Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Iowa (doing business as Black Hills Energy).
IPP			Independent Power Producer
IRS			United States Internal Revenue Service
Kansas Gas			Black Hills Kansas Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Kansas (doing business as Black Hills Energy).
KCC			Kansas Corporation Commission
kV			Kilovolt
LIBOR			London Interbank Offered Rate
MEAN			Municipal Energy Agency of Nebraska
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.
NPSC			Nebraska Public Service Commission
OCI			Other Comprehensive Income
PPA			Power Purchase Agreement
PTC			Production Tax Credit
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 260-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 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.
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.
RNG			Renewable Natural Gas
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.

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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).
SPP			Southwest Power Pool
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
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. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts” and similar expressions, and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are other than statements of historical facts. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. 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 2021 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;

•Our ability to overcome the impacts of supply chain disruptions on availability and cost of materials;

•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 June 30,						Six Months Ended June 30,
			2022			2021			2022			2021
			(in thousands, except per share amounts)
Revenue			$	474,195		$	372,572		$	1,297,765		$	1,006,004
Operating expenses:
Fuel, purchased power and cost of natural gas sold			188,171			108,474			625,097			401,621
Operations and maintenance			132,968			123,245			269,100			252,924
Depreciation, depletion and amortization			64,128			58,443			124,591			115,712
Taxes - property and production			16,539			15,144			33,235			30,166
Total operating expenses			401,806			305,306			1,052,023			800,423
Operating income			72,389			67,266			245,742			205,581
Other income (expense):
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)			(39,053)			(38,669)			(77,874)			(76,494)
Interest income			289			467			565			692
Other income (expense), net			1,563			(191)			2,267			75
Total other income (expense)			(37,201)			(38,393)			(75,042)			(75,727)
Income before income taxes			35,188			28,873			170,700			129,854
Income tax benefit (expense)			658			(586)			(13,830)			(1,080)
Net income			35,846			28,287			156,870			128,774
Net income attributable to non-controlling interest			(2,431)			(3,126)			(5,929)			(7,297)
Net income available for common stock			$	33,415		$	25,161		$	150,941		$	121,477
Earnings per share of common stock:
Earnings per share, Basic			$	0.52		$	0.40		$	2.33		$	1.94
Earnings per share, Diluted			$	0.52		$	0.40		$	2.33		$	1.93
Weighted average common shares outstanding:
Basic			64,721			62,867			64,643			62,751
Diluted			64,883			62,918			64,822			62,817

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 June 30,						Six Months Ended June 30,
			2022			2021			2022			2021
			(in thousands)
Net income			$	35,846		$	28,287		$	156,870		$	128,774
Other comprehensive income (loss), net of tax:
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $8, $6, $14 and $15, respectively)			(14)			(18)			(32)			(34)
Reclassification adjustments of benefit plan liability - net loss (net of tax of $(68), $(157), $(113) and $(374), respectively)			119			440			262			821
Derivative instruments designated as cash flow hedges:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(238), $(150), $(415) and $(340), respectively)			475			563			1,011			1,086
Net unrealized gains (losses) on commodity derivatives (net of tax of $734, $(304), $394 and $(339), respectively)			(2,314)			939			(1,267)			1,046
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $319, $14, $871 and $6, respectively)			(1,004)			(42)			(2,706)			(19)
Other comprehensive income (loss), net of tax			(2,738)			1,882			(2,732)			2,900
Comprehensive income			33,108			30,169			154,138			131,674
Less: comprehensive income attributable to non-controlling interest			(2,431)			(3,126)			(5,929)			(7,297)
Comprehensive income available for common stock			$	30,677		$	27,043		$	148,209		$	124,377

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
			June 30, 2022						December 31, 2021
			(in thousands)
ASSETS
Current assets:
Cash and cash equivalents			$	10,216					$	8,921
Restricted cash and equivalents			5,146						4,889
Accounts receivable, net			267,103						321,652
Materials, supplies and fuel			152,864						150,979
Derivative assets, current			716						4,373
Income tax receivable, net			17,299						18,017
Regulatory assets, current			267,725						270,290
Other current assets			39,358						29,012
Total current assets			760,427						808,133
Property, plant and equipment			8,086,704						7,856,573
Less: accumulated depreciation and depletion			(1,499,552)						(1,407,397)
Total property, plant and equipment, net			6,587,152						6,449,176
Other assets:
Goodwill			1,299,454						1,299,454
Intangible assets, net			10,177						10,770
Regulatory assets, non-current			434,643						526,309
Other assets, non-current			42,709						38,054
Total other assets, non-current			1,786,983						1,874,587
TOTAL ASSETS			$	9,134,562					$	9,131,896

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
			June 30, 2022						December 31, 2021
			(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable			$	185,735					$	217,761
Accrued liabilities			226,320						244,759
Derivative liabilities, current			4,719						1,439
Regulatory liabilities, current			33,356						17,574
Notes payable			335,050						420,180
Total current liabilities			785,180						901,713
Long-term debt, net of current maturities			4,129,662						4,126,923
Deferred credits and other liabilities:
Deferred income tax liabilities, net			490,207						465,388
Regulatory liabilities, non-current			482,642						485,377
Benefit plan liabilities			121,338						123,925
Other deferred credits and other liabilities			142,732						141,447
Total deferred credits and other liabilities			1,236,919						1,216,137
Commitments, contingencies and guarantees (Note 3)
Equity:
Stockholders’ equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 65,105,178 and 64,793,095 shares, respectively			65,105						64,793
Additional paid-in capital			1,808,437						1,783,436
Retained earnings			1,036,263						962,458
Treasury stock, at cost – 23,691 and 54,078 shares, respectively			(1,542)						(3,509)
Accumulated other comprehensive income (loss)			(22,816)						(20,084)
Total stockholders’ equity			2,885,447						2,787,094
Non-controlling interest			97,354						100,029
Total equity			2,982,801						2,887,123
TOTAL LIABILITIES AND TOTAL EQUITY			$	9,134,562					$	9,131,896

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)			Six Months Ended June 30,
			2022			2021
Operating activities:			(in thousands)
Net income			$	156,870		$	128,774
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization			124,591			115,712
Deferred financing cost amortization			4,953			4,381
Stock compensation			3,834			5,044
Deferred income taxes			13,860			692
Employee benefit plans			1,383			4,934
Other adjustments, net			(9,489)			10,495
Changes in certain operating assets and liabilities:
Materials, supplies and fuel			(6,993)			3,974
Accounts receivable and other current assets			55,641			88,513
Accounts payable and other current liabilities			(24,130)			(59,640)
Regulatory assets			128,315			(540,709)
Regulatory liabilities			—			(9,509)
Other operating activities, net			(6,805)			(2,834)
Net cash provided by (used in) operating activities			442,030			(250,173)
Investing activities:
Property, plant and equipment additions			(293,803)			(319,476)
Other investing activities			2,418			9,739
Net cash (used in) investing activities			(291,385)			(309,737)
Financing activities:
Dividends paid on common stock			(77,136)			(71,092)
Common stock issued			20,095			40,037
Term loan - borrowings			—			800,000
Term loan - repayments			—			(200,000)
Net borrowings (payments) of Revolving Credit Facility and CP Program			(85,130)			(4,190)
Long-term debt - repayments			—			(1,436)
Distributions to non-controlling interest			(8,604)			(8,705)
Other financing activities			1,682			291
Net cash provided by (used in) financing activities			(149,093)			554,905
Net change in cash, restricted cash and cash equivalents			1,552			(5,005)
Cash, restricted cash and cash equivalents at beginning of period			13,810			10,739
Cash, restricted cash and cash equivalents at end of period			$	15,362		$	5,734
Supplemental cash flow information:
Cash (paid) refunded during the period:
Interest, net of amounts capitalized			$	(72,791)		$	(71,825)
Income taxes			752			1,486
Non-cash investing and financing activities:
Accrued property, plant and equipment purchases at June 30			49,229			54,448

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, 2021			64,793,095			$	64,793		54,078			$	(3,509)		$	1,783,436		$	962,458		$	(20,084)		$	100,029		$	2,887,123
Net income			—			—			—			—			—			117,526			—			3,498			121,024
Other comprehensive income, net of tax			—			—			—			—			—			—			6			—			6
Dividends on common stock ($0.595 per share)			—			—			—			—			—			(38,533)			—			—			(38,533)
Share-based compensation			425			—			(34,393)			2,222			(191)			—			—			—			2,031
Issuance of common stock			55,707			56			—			—			3,776			—			—			—			3,832
Issuance costs			—			—			—			—			(41)			—			—			—			(41)
Distributions to non-controlling interest			—			—			—			—			—			—			—			(4,420)			(4,420)
March 31, 2022			64,849,227			$	64,849		19,685			$	(1,287)		$	1,786,980		$	1,041,451		$	(20,078)		$	99,107		$	2,971,022
Net income			—			—			—			—			—			33,415			—			2,431			35,846
Other comprehensive (loss), net of tax			—			—			—			—			—			—			(2,738)			—			(2,738)
Dividends on common stock ($0.595 per share)			—			—			—			—			—			(38,603)			—			—			(38,603)
Share-based compensation			39,066			39			4,006			(255)			5,370			—			—			—			5,154
Issuance of common stock			216,885			217			—			—			16,353			—			—			—			16,570
Issuance costs			—			—			—			—			(266)			—			—			—			(266)
Distributions to non-controlling interest			—			—			—			—			—			—			—			(4,184)			(4,184)
June 30, 2022			65,105,178			$	65,105		23,691			$	(1,542)		$	1,808,437		$	1,036,263		$	(22,816)		$	97,354		$	2,982,801

(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

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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 2021 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 2021 Annual Report on Form 10-K.

Segment Reporting

Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products and services. All of our operations and assets are located within the United States. We conduct our operations through the Electric Utilities and Gas Utilities segments. In the fourth quarter of 2021, we integrated our power generation and mining businesses within the Electric Utilities segment. The alignment is consistent with the current way our CODM evaluates the performance of the business and makes decisions related to the allocation of resources. Comparative periods presented reflect this change.

For further information regarding our segment reporting, see Note 12.

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 June 30, 2022, December 31, 2021 and June 30, 2021 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.

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 but do not expect it to have a material impact on our financial position, results of operations and cash flows.

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(2)    Regulatory Matters

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

			As of			As of
			June 30, 2022			December 31, 2021
Regulatory assets
Winter Storm Uri (a)			$	402,971		$	509,025
Deferred energy and fuel cost adjustments (b)			71,701			59,973
Deferred gas cost adjustments (b)			8,083			9,488
Gas price derivatives (b)			4,845			2,584
Deferred taxes on AFUDC (b)			7,426			7,457
Employee benefit plans and related deferred taxes (c)			87,130			88,923
Environmental (b)			1,360			1,385
Loss on reacquired debt (b)			20,112			21,011
Deferred taxes on flow through accounting (b)			69,811			63,243
Decommissioning costs (b)			4,717			5,961
Other regulatory assets (b)			24,212			27,549
Total regulatory assets			702,368			796,599
Less current regulatory assets			(267,725)			(270,290)
Regulatory assets, non-current			$	434,643		$	526,309
Regulatory liabilities
Deferred energy and gas costs (b)			$	15,899		$	6,113
Employee benefit plan costs and related deferred taxes (c)			31,330			32,241
Cost of removal (b)			184,111			179,976
Excess deferred income taxes (c)			259,674			264,042
Other regulatory liabilities (c)			24,984			20,579
Total regulatory liabilities			515,998			502,951
Less current regulatory liabilities			(33,356)			(17,574)
Regulatory liabilities, non-current			$	482,642		$	485,377

__________

(a)    Timing of Winter Storm Uri incremental cost recovery and associated carrying costs vary by jurisdiction and Wyoming Gas is still subject to pending application with the WPSC. See further information below.

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

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

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 2021 Annual Report on Form 10-K.

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 3.5 years. These incremental cost estimates are subject to adjustments as final decisions are issued by the respective utility commissions. In these applications, we sought approval to recover carrying costs. For three and six months ended June 30, 2022 and three and six months ended June 30, 2021, $12 million, $15 million, $0.1 million and $0.1 million, respectively, of carrying costs were accrued and recorded to a regulatory asset. The carrying costs accrued during the three and six months ended June 30, 2022 included a one-time, $10 million true-up to reflect Commission authorized rates.

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On January 27, 2022, Kansas Gas received approval from the KCC for its Winter Storm Uri cost recovery settlement with final rates implemented in February 2022. In March 2022, Colorado Electric and Colorado Gas received approval from the CPUC for their respective Winter Storm Uri cost recovery settlements with final rates implemented in April 2022. In June 2022, Arkansas Gas received approval from the APSC for its Winter Storm Uri cost recovery application. The APSC had previously approved interim cost recovery effective in June 2021.

To date, Arkansas Gas, Colorado Electric, Colorado Gas, Iowa Gas, Kansas Gas, Nebraska Gas and South Dakota Electric received commission approval of their Winter Storm Uri cost recovery applications. Additionally, Wyoming Gas received approval for interim cost recovery subject to a final decision on carrying costs and recovery period at a later date. For the six months ended June 30, 2022, our Utilities collected $111 million of Winter Storm Uri incremental costs and carrying costs from customers. As of June 30, 2022, we estimate that our remaining Winter Storm Uri regulatory asset has a weighted-average recovery period of 3.0 years.

TCJA

As part of Kansas Gas’s 2021 rate review settlement agreement, Kansas Gas will deliver $3.0 million of TCJA and state tax reform benefits to customers, annually, for three years starting in 2022 (approximately $9.1 million of total benefits expected to be delivered). For the three and six months ended June 30, 2022, Kansas Gas delivered TCJA and state tax reform bill credits to customers of $0.7 million and $1.5 million, respectively.

These bill credits, which resulted in a reduction of revenue, were offset by a reduction in income tax expense and resulted in an immaterial impact to Net income for the three and six months ended June 30, 2022.

Arkansas Gas

On December 10, 2021, Arkansas Gas filed a rate review with the APSC seeking recovery of significant infrastructure investments in its 7,200-mile natural gas pipeline system. The rate review requests $22 million in new annual revenue with a capital structure of 50.9% equity and 49.1% debt and a return on equity of 10.2%. The request seeks to finalize rates in the fourth quarter of 2022.

Wyoming Electric

On June 1, 2022, Wyoming Electric filed a rate review with the WPSC seeking recovery of significant infrastructure investments in its 1,330-mile electric distribution and 59-mile electric transmission systems. The rate review requests $15 million in new annual revenue with a capital structure of 54% equity and 46% debt and a return on equity of 10.3%. The request seeks to finalize rates in the first quarter of 2023.

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(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 2021 Annual Report on Form 10-K except for those described below.

Agreement under Blockchain Interruptible Service Tariff

On June 21, 2022, Wyoming Electric completed its first agreement for service under its Blockchain Interruptible Service tariff. Under the five-year agreement, Wyoming Electric will deliver up to 45 MW of electric service with an option to expand service up to 75 MW to a new customer in Cheyenne, Wyoming. The crypto mining facility is expected to be operational and purchasing energy in the fourth quarter of 2022.

Power Sales Agreements

On May 3, 2022, South Dakota Electric entered into an agreement with MDU to provide MDU capacity and energy up to a maximum of 50 MW in excess of MDU’s 25% ownership in Wygen III. This agreement, which has similar terms and conditions as South Dakota Electric’s existing agreement with MDU expiring on December 31, 2023, is effective on January 1, 2024 and will expire on December 31, 2028.

During periods of reduced production at Wygen III, in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, South Dakota Electric will provide MDU with 23 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU. On June 3, 2022, South Dakota Electric entered into an agreement with similar terms and conditions as its existing agreement with MDU expiring on December 31, 2023, is effective on January 1, 2024 and will expire on December 31, 2028.

GT Resources, LLC v. Black Hills Corporation, Case No. 2020CV30751 (U.S. District Court for the City and County of Denver, Colorado)

On April 13, 2022, a jury awarded $41 million for claims made by GT Resources, LLC (“GTR”) against BHC and two of its subsidiaries (Black Hills Exploration and Production, Inc. and Black Hills Gas Resources, Inc.), which ceased oil and natural gas operations in 2018 as part of BHC’s decision to exit the exploration and production business. The claims involved a dispute over a 2.3 million-acre concession award in Costa Rica which was acquired by a BHC subsidiary in 2003. GTR retained rights to receive a royalty interest on any hydrocarbon production from the concession upon the occurrence of contingent events. GTR contended that BHC and its subsidiaries failed to adequately pursue the opportunity and failed to transfer the concession to GTR. We believe we have meritorious defenses to the verdict and intend to appeal the verdict. At this time, we believe that the liability related to this matter, if any, is not reasonably estimable.

Power Purchase Agreements

On March 21, 2022, Wyoming Electric entered into a PPA with South Cheyenne Solar, LLC (Cheyenne Solar) to purchase up to 150 MW of renewable energy upon construction of a new solar facility, to be owned by Cheyenne Solar, which is expected to be completed by the end of 2023. The agreement will expire 20 years after construction completion. The solar energy from this PPA will be used to serve our expanding partnerships with industrial customers in Cheyenne, Wyoming.

On February 19, 2021, Colorado Electric entered into an agreement with TC Colorado Solar, LLC (TC Solar) to purchase up to 200 MW of renewable energy upon construction of a new solar facility, to be owned by TC Solar. On January 31, 2022, TC Solar provided notice of its intent to terminate the PPA. Colorado Electric will seek new requests for proposals for renewable resources as part of its Clean Energy Plan filing, the “2030 Ready Plan.” On May 27, 2022, Colorado Electric filed its 2030 Ready Plan with the CPUC. A CPUC decision is expected in April 2023, after which time, Colorado Electric’s request for proposals for renewable energy resources is expected to commence.

Transmission Service Agreements

On January 1, 2022, Colorado Electric entered into a firm point-to-point transmission service agreement that provides Tri-State Generation and Transmission Association Inc. with a maximum of 58 MW of transmission capacity. This agreement expires December 31, 2024.

On January 1, 2022, South Dakota Electric entered into a firm point-to-point transmission service agreement that provides MEAN with a maximum of 20 MW of transmission capacity. This agreement expires December 31, 2023.

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(4)    Revenue

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 six months ended June 30, 2022 and 2021. Sales tax and other similar taxes are excluded from revenues.

Three Months Ended June 30, 2022			Electric Utilities			Gas Utilities			Inter-company Revenues			Total
Customer types:			(in thousands)
Retail			$	169,032		$	229,074		$	—		$	398,106
Transportation			—			34,667			(100)			34,567
Wholesale			8,428			—			—			8,428
Market - off-system sales			8,666			178			—			8,844
Transmission/Other			15,183			9,344			(4,148)			20,379
Revenue from contracts with customers			$	201,309		$	273,263		$	(4,248)		$	470,324
Other revenues			3,070			906			(105)			3,871
Total revenues			$	204,379		$	274,169		$	(4,353)		$	474,195
Timing of revenue recognition:
Services transferred at a point in time			$	6,671		$	—		$	—		$	6,671
Services transferred over time			194,638			273,263			(4,248)			463,653
Revenue from contracts with customers			$	201,309		$	273,263		$	(4,248)		$	470,324

Three Months Ended June 30, 2021			Electric Utilities			Gas Utilities			Inter-company Revenues			Total
Customer Types:			(in thousands)
Retail			$	163,971		$	143,845		$	—		$	307,816
Transportation			—			31,649			(109)			31,540
Wholesale			5,655			—			—			5,655
Market - off-system sales			7,266			87			—			7,353
Transmission/Other			11,224			9,125			(4,291)			16,058
Revenue from contracts with customers			$	188,116		$	184,706		$	(4,400)		$	368,422
Other revenues			2,900			1,344			(94)			4,150
Total Revenues			$	191,016		$	186,050		$	(4,494)		$	372,572
Timing of Revenue Recognition:
Services transferred at a point in time			$	6,714		$	—		$	—		$	6,714
Services transferred over time			181,402			184,706			(4,400)			361,708
Revenue from contracts with customers			$	188,116		$	184,706		$	(4,400)		$	368,422

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Six Months Ended June 30, 2022			Electric Utilities			Gas Utilities			Inter-company Revenues			Total
Customer types:			(in thousands)
Retail			$	341,838		$	790,087		$	—		$	1,131,925
Transportation			—			84,190			(199)			83,991
Wholesale			18,703			—			—			18,703
Market - off-system sales			15,820			416			—			16,236
Transmission/Other			30,616			18,919			(8,297)			41,238
Revenue from contracts with customers			$	406,977		$	893,612		$	(8,496)		$	1,292,093
Other revenues			3,940			1,949			(217)			5,672
Total revenues			$	410,917		$	895,561		$	(8,713)		$	1,297,765
Timing of revenue recognition:
Services transferred at a point in time			$	13,784		$	—		$	—		$	13,784
Services transferred over time			393,193			893,612			(8,496)			1,278,309
Revenue from contracts with customers			$	406,977		$	893,612		$	(8,496)		$	1,292,093

Six Months Ended June 30, 2021			Electric Utilities			Gas Utilities			Inter-company Revenues			Total
Customer Types:			(in thousands)
Retail			$	368,251		$	485,450		$	—		$	853,701
Transportation			—			79,600			(219)			79,381
Wholesale			17,014			—			—			17,014
Market - off-system sales			12,038			160			—			12,198
Transmission/Other			25,411			19,515			(8,580)			36,346
Revenue from contracts with customers			$	422,714		$	584,725		$	(8,799)		$	998,640
Other revenues			3,706			3,844			(186)			7,364
Total Revenues			$	426,420		$	588,569		$	(8,985)		$	1,006,004
Timing of Revenue Recognition:
Services transferred at a point in time			$	13,690		$	—		$	—		$	13,690
Services transferred over time			409,024			584,725			(8,799)			984,950
Revenue from contracts with customers			$	422,714		$	584,725		$	(8,799)		$	998,640

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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:

			June 30, 2022						December 31, 2021
			Balance Outstanding			Letters of Credit (a)			Balance Outstanding			Letters of Credit (a)
Revolving Credit Facility			—			14,239			—			27,209
CP Program			335,050			—			420,180			—
Total Notes payable			$	335,050		$	14,239		$	420,180		$	27,209

__________

(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

Our net short-term repayments related to our Revolving Credit Facility and CP Program during the six months ended June 30, 2022 were $85 million. The weighted average interest rate on short-term borrowings related to our Revolving Credit Facility and CP Program at June 30, 2022 was 1.74%.

Debt Covenants

Revolving Credit Facility

Under our Revolving Credit Facility, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding.

We were in compliance with our covenants at June 30, 2022 as shown below:

As of June 30, 2022

Covenant Requirement

Consolidated Indebtedness to Capitalization Ratio

60.8%

Less than

65%

Wyoming Electric

Covenants within Wyoming Electric's financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of June 30, 2022, Wyoming Electric’s debt to capitalization ratio was 50%, which was in compliance with these financial covenants.

Equity

At-the-Market Equity Offering Program

During the three months ended June 30, 2022, we issued a total of 0.2 million shares of common stock under the ATM for proceeds of $16 million, net of $0.2 million in issuance costs. During the six months ended June 30, 2022, we issued a total of 0.3 million shares of common stock under the ATM for proceeds of $20 million, net of $0.2 million in issuance costs. During the three and six months ended June 30, 2021, we issued a total of 0.6 million shares of common stock under the ATM for proceeds of $40 million, net of $0.4 million in issuance costs.

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(6)    Earnings Per Share

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

			Three Months Ended June 30,									Six Months Ended June 30,
			2022			2021						2022			2021
Net income available for common stock			$	33,415		$	25,161					$	150,941		$	121,477
Weighted average shares - basic			64,721			62,867						64,643			62,751
Dilutive effect of:
Equity compensation			162			51						179			66
Weighted average shares - diluted			64,883			62,918						64,822			62,817
Earnings per share of common stock:
Earnings per share, Basic			$	0.52		$	0.40					$	2.33		$	1.94
Earnings per share, Diluted			$	0.52		$	0.40					$	2.33		$	1.93

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

			Three Months Ended June 30,									Six Months Ended June 30,
			2022			2021						2022			2021
Equity compensation			—			13						—			12
Restricted stock			—			—						1			1
Anti-dilutive shares			—			13						1			13

(7)    Risk Management and Derivatives

Market and Credit Risk Disclosures

Our activities in the energy industry 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 but not limited to, the following market risks:

•Commodity price risk associated with our retail natural gas and wholesale electric power marketing activities and our fuel procurement for several of our gas-fired generation assets, which include market fluctuations due to unpredictable factors such as the COVID-19 pandemic, weather (Winter Storm Uri), geopolitical events, market speculation, inflation, pipeline constraints, and other factors that may impact natural gas and electric supply and demand; and

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

Credit Risk

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

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

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We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the 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’ generation plants or those plants 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 utility commissions, we have entered into commission approved hedging programs utilizing natural gas futures, options, over-the-counter swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP.

For our regulated Utilities’ 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 use wholesale power purchase and sale contracts to manage purchased power costs and load requirements associated with serving our electric customers. Periodically, certain wholesale energy contracts are considered derivative instruments due to not qualifying for the normal purchase 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 risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and sales during time frames ranging from July 2022 through December 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.

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:

			June 30, 2022												December 31, 2021
			Notional Amounts (MMBtus)						Maximum Term (months) (a)						Notional Amounts (MMBtus)						Maximum Term (months) (a)
Natural gas futures purchased			100,000						9						590,000						3
Natural gas options purchased, net			430,000						9						3,100,000						3
Natural gas basis swaps purchased			—						0						870,000						3
Natural gas over-the-counter swaps, net (b)			7,090,000						30						4,570,000						34
Natural gas physical contracts, net (c)			12,166,541						18						16,416,677						24

__________

(a)    Term reflects the maximum forward period hedged.

(b)    As of June 30, 2022, 2,416,000 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 June 30, 2022, the Company posted $0.4 million related to such provisions, which is included in Other current assets on the Condensed Consolidated Balance Sheets.

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Derivatives by Balance Sheet Classification

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

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

			Balance Sheet Location			June 30, 2022			December 31, 2021
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivatives			Derivative assets, current			$	2		$	2,017
Noncurrent commodity derivatives			Other assets, non-current			256			18
Liability derivative instruments:
Current commodity derivatives			Derivative liabilities, current			(3,318)			—
Total derivatives designated as hedges						$	(3,060)		$	2,035
Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivatives			Derivative assets, current			$	714		$	2,356
Noncurrent commodity derivatives			Other assets, non-current			923			804
Liability derivative instruments:
Current commodity derivatives			Derivative liabilities, current			(1,401)			(1,439)
Noncurrent commodity derivatives			Other deferred credits and other liabilities			—			(20)
Total derivatives not designated as hedges						$	236		$	1,701

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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 six months ended June 30, 2022 and 2021. Note that this presentation does not reflect the 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 June 30,									Three Months Ended June 30,
			2022			2021						2022			2021
Derivatives in Cash Flow Hedging Relationships			Amount of Gain/(Loss) Recognized in OCI						Income Statement Location			Amount of Gain/(Loss) Reclassified from AOCI into Income
			(in thousands)									(in thousands)
Interest rate swaps			$	713		$	713		Interest expense			$	(713)		$	(713)
Commodity derivatives			(4,371)			1,187			Fuel, purchased power and cost of natural gas sold			1,323			56
Total			$	(3,658)		$	1,900					$	610		$	(657)

			Six Months Ended June 30,									Six Months Ended June 30,
			2022			2021						2022			2021
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			$	1,426		$	1,426		Interest expense			$	(1,426)		$	(1,426)
Commodity derivatives			(5,238)			1,360			Fuel, purchased power and cost of natural gas sold			3,577			25
Total			$	(3,812)		$	2,786					$	2,151		$	(1,401)

As of June 30, 2022, $6.1 million of net losses related to our interest rate swaps and commodity derivatives are expected to be reclassified from AOCI into earnings within the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

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 six months ended June 30, 2022 and 2021. Note that this presentation does not reflect the expected 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 June 30,
						2022			2021
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			$	—		$	(3,598)
Commodity derivatives - Natural Gas			Fuel, purchased power and cost of natural gas sold			(2,332)			1,816
						$	(2,332)		$	(1,782)

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						Six Months Ended June 30,
						2022			2021
Derivatives Not Designated as Hedging Instruments			Income Statement Location			Amount of Gain/(Loss) on Derivatives Recognized in Income
						(in thousands)
Commodity derivatives - Electric			Fuel, purchased power and cost of natural gas sold			$	—		$	(5,122)
Commodity derivatives - Natural Gas			Fuel, purchased power and cost of natural gas sold			1,162			2,182
						$	1,162		$	(2,940)

As discussed above, financial instruments used in our regulated Gas Utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory asset accounts related to these financial instruments in our Gas Utilities were $4.8 million and $2.6 million as of June 30, 2022 and December 31, 2021, 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 credit valuation adjustment 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 2021 Annual Report on Form 10-K.

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The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting of cash collateral and contractual netting rights as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments.

			As of June 30, 2022
			Level 1			Level 2			Level 3						Cash Collateral and Counterparty Netting (a)			Total
			(in thousands)
Assets:
Commodity derivatives — Gas Utilities			$	—		$	2,700		$	—					$	(806)		$	1,894
Total			$	—		$	2,700		$	—					$	(806)		$	1,894
Liabilities:
Commodity derivatives — Gas Utilities			$	—		$	5,524		$	—					$	(805)		$	4,719
Total			$	—		$	5,524		$	—					$	(805)		$	4,719

__________

(a)    As of June 30, 2022, $0.8 million of our commodity derivative assets and $0.8 million of our commodity liabilities, as well as related gross collateral amounts, were subject to master netting agreements.

			As of December 31, 2021
			Level 1			Level 2			Level 3						Cash Collateral and Counterparty Netting (a)			Total
			(in thousands)
Assets:
Commodity derivatives — Gas Utilities			$	—		$	7,569		$	—					$	(2,374)		$	5,195
Total			$	—		$	7,569		$	—					$	(2,374)		$	5,195
Liabilities:
Commodity derivatives — Gas Utilities			$	—		$	3,273		$	—					$	(1,814)		$	1,459
Total			$	—		$	3,273		$	—					$	(1,814)		$	1,459

__________

(a)    As of December 31, 2021, $2.4 million of our commodity derivative assets and $1.8 million of our commodity derivative liabilities, as well as related gross collateral amounts, were subject to master netting agreements.

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 13 to the Consolidated Financial Statements included in our 2021 Annual Report on Form 10-K.

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 are not traded on an exchange; therefore, they are classified as Level 2 in the fair value hierarchy.

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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:

			June 30, 2022									December 31, 2021
			Carrying Amount			Fair Value						Carrying Amount			Fair Value
Long-term debt, including current maturities (a)			$	4,129,662		$	3,917,015					$	4,126,923		$	4,570,619

__________

(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 in 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, net of tax (in thousands):

			Location on the Condensed Consolidated Statements of Income			Amount Reclassified from AOCI									Amount Reclassified from AOCI
						Three Months Ended June 30,									Six Months Ended June 30,
						2022			2021						2022			2021
Gains and (losses) on cash flow hedges:
Interest rate swaps			Interest expense			$	(713)		$	(713)					$	(1,426)		$	(1,426)
Commodity contracts			Fuel, purchased power and cost of natural gas sold			1,323			56						3,577			25
						610			(657)						2,151			(1,401)
Income tax			Income tax expense			(81)			136						(456)			334
Total reclassification adjustments related to cash flow hedges, net of tax						$	529		$	(521)					$	1,695		$	(1,067)
Amortization of components of defined benefit plans:
Prior service cost			Operations and maintenance			$	22		$	24					$	46		$	49
Actuarial gain (loss)			Operations and maintenance			(187)			(597)						(375)			(1,195)
						(165)			(573)						(329)			(1,146)
Income tax			Income tax expense			60			151						99			359
Total reclassification adjustments related to defined benefit plans, net of tax						$	(105)		$	(422)					$	(230)		$	(787)
Total reclassifications						$	424		$	(943)					$	1,465		$	(1,854)

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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, 2021			$	(10,384)		$	1,476		$	(11,176)		$	(20,084)
Other comprehensive income (loss)
before reclassifications			—			(1,267)			—			(1,267)
Amounts reclassified from AOCI			1,011			(2,706)			230			(1,465)
As of June 30, 2022			$	(9,373)		$	(2,497)		$	(10,946)		$	(22,816)
			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			—			1,046			—			1,046
Amounts reclassified from AOCI			1,086			(19)			787			1,854
As of June 30, 2021			$	(11,472)		$	1,029		$	(14,003)		$	(24,446)

(10)    Employee Benefit Plans

Components of Net Periodic Expense

The components of net periodic expense were as follows (in thousands):

			Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
Three Months Ended June 30,			2022			2021			2022			2021			2022			2021
Net Service cost			$	982		$	1,260		$	(1,355)		$	1,020		$	492		$	559
Interest cost			2,704			2,328			209			177			321			264
Expected return on plan assets			(4,630)			(5,219)			—			—			(31)			(34)
Net amortization of prior service costs			(17)			—			—			—			(73)			(109)
Recognized net actuarial loss			1,523			1,829			69			438			16			117
Net periodic expense (benefit)			$	562		$	198		$	(1,077)		$	1,635		$	725		$	797

			Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
Six Months Ended June 30,			2022			2021			2022			2021			2022			2021
Net Service cost			$	1,964		$	2,519		$	(1,747)		$	1,713		$	984		$	1,118
Interest cost			5,409			4,656			417			354			642			529
Expected return on plan assets			(9,261)			(10,438)			—			—			(62)			(68)
Net amortization of prior service costs			(34)			—			—			—			(145)			(218)
Recognized net actuarial loss			3,046			3,658			138			877			32			234
Net periodic expense (benefit)			$	1,124		$	395		$	(1,192)		$	2,944		$	1,451		$	1,595

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Plan 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 six months of 2022 and anticipated contributions for 2022 and 2023 are as follows (in thousands):

						Contributions Made			Additional Contributions			Contributions
						Six Months Ended June 30, 2022			Anticipated for 2022			Anticipated for 2023
Defined Benefit Pension Plan						$	—		$	—		$	—
Non-pension Defined Benefit Postretirement Healthcare Plan						$	2,552		$	2,552		$	4,761
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans						$	1,078		$	1,078		$	2,215

Funding Status of Employee Benefit Plans

Based on the fair value of assets and estimated discount rate used to value benefit obligations as of June 30, 2022, we estimate the unfunded status of our employee benefit plans to be approximately $29 million compared to $20 million at December 31, 2021. In 2012, we froze our pension plan and closed it to new participants. Since then, we have implemented various de-risking strategies including lump sum buyouts, the purchase of annuities and the reduction of return-seeking assets over time to a more liability-hedged portfolio. As a result, recent capital markets volatility has not materially affected our unfunded status and does not require interim re-measurement of our pension plan assets or defined benefit obligations.

(11)    Income Taxes

Income Tax Expense (Benefit) and Effective Tax Rates

Three Months Ended June 30, 2022 Compared to the Three Months Ended June 30, 2021

Income tax expense (benefit) for the three months ended June 30, 2022 was $(0.7) million compared to $0.6 million reported for the same period in 2021. For the three months ended June 30, 2022 the effective tax rate was (1.9)% compared to 2.0% for the same period in 2021. The lower effective tax rate was primarily due to $3.8 million of tax benefits from state rate changes, $1.5 million of increased tax benefits from federal PTCs associated with increased wind production and a current year PTC rate increase (inflation adjustment). These current year tax benefits were greater than prior year tax benefits from Nebraska Gas TCJA-related bill credits to customers (which were offset by reduced revenue) and prior year flow-through tax benefits related to repairs and certain indirect costs.

Six Months Ended June 30, 2022 Compared to the Six Months Ended June 30, 2021

Income tax expense for the six months ended June 30, 2022 was $14 million compared to $1.1 million reported for the same period in 2021. For the six months ended June 30, 2022, the effective tax rate was 8.1% compared to 0.8% for the same period in 2021. The higher effective tax rate was primarily due to $10 million of prior year tax benefits from Colorado Electric and Nebraska Gas TCJA-related bill credits to customers (which were offset by reduced revenue) partially offset by $3.8 million of current year tax benefits from state rate changes and $2.4 million of increased tax benefits from federal PTCs associated with increased wind production and a current year PTC rate increase (inflation adjustment).

(12)    Business Segment Information

Our CODM reviews financial information presented on an operating segment basis for purposes of making decisions and assessing financial performance. Our CODM assesses the performance of our operating segments based on operating income.

For the first nine months of 2021, we had reported four operating segments: Electric Utilities, Gas Utilities, Power Generation and Mining. In the fourth quarter of 2021, we integrated our power generation and mining businesses within the Electric Utilities segment. The alignment is consistent with the current way our CODM evaluates the performance of the business and makes decisions related to the allocation of resources. Comparative periods presented reflect this change.

Our operating segments are equivalent to our reportable segments.

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Segment information was as follows (in thousands):

Total assets (net of intercompany eliminations) as of:			June 30, 2022						December 31, 2021
Electric Utilities			$	3,834,826					$	3,796,662
Gas Utilities			5,197,194						5,246,370
Corporate and Other			102,542						88,864
Total assets			$	9,134,562					$	9,131,896

Three Months Ended June 30, 2022			External Operating Revenue									Inter-company Operating Revenue									Total Revenues
			Contract Customers			Other Revenues						Contract Customers			Other Revenues
Segment:
Electric Utilities			$	198,380		$	3,070					$	2,929		$	—					$	204,379
Gas Utilities			271,944			801						1,319			105						274,169
Inter-company eliminations			—			—						(4,248)			(105)						(4,353)
Total			$	470,324		$	3,871					$	—		$	—					$	474,195

Three Months Ended June 30, 2021			External Operating Revenue									Inter-company Operating Revenue									Total Revenues
			Contract Customers			Other Revenues						Contract Customers			Other Revenues
Segment:
Electric Utilities			$	185,235		$	2,900					$	2,881		$	—					$	191,016
Gas Utilities			183,187			1,250						1,519			94						186,050
Inter-company eliminations			—			—						(4,400)			(94)						(4,494)
Total			$	368,422		$	4,150					$	—		$	—					$	372,572

Six Months Ended June 30, 2022			External Operating Revenue									Inter-company Operating Revenue									Total Revenues
			Contract Customers			Other Revenues						Contract Customers			Other Revenues
Segment:
Electric Utilities			$	401,119		$	3,940					$	5,858		$	—					$	410,917
Gas Utilities			890,974			1,732						2,638			217						895,561
Inter-company eliminations			—			—						(8,496)			(217)						(8,713)
Total			$	1,292,093		$	5,672					$	—		$	—					$	1,297,765

Six Months Ended June 30, 2021			External Operating Revenue									Inter-company Operating Revenue									Total Revenues
			Contract Customers			Other Revenues						Contract Customers			Other Revenues
Segment:
Electric Utilities			$	416,954		$	3,706					$	5,760		$	—					$	426,420
Gas Utilities			581,686			3,658						3,039			186						588,569
Inter-company eliminations			—			—						(8,799)			(186)						(8,985)
Total			$	998,640		$	7,364					$	—		$	—					$	1,006,004

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			Three Months Ended June 30,						Six Months Ended June 30,
			2022			2021			2022			2021
Operating income (loss):
Electric Utilities			$	45,226		$	47,462		$	95,972		$	86,805
Gas Utilities			28,195			19,985			151,735			122,079
Corporate and Other			(1,032)			(181)			(1,965)			(3,303)
Operating income			72,389			67,266			245,742			205,581
Interest expense, net			(38,764)			(38,202)			(77,309)			(75,802)
Other income (expense), net			1,563			(191)			2,267			75
Income tax benefit (expense)			658			(586)			(13,830)			(1,080)
Net income			35,846			28,287			156,870			128,774
Net income attributable to non-controlling interest			(2,431)			(3,126)			(5,929)			(7,297)
Net income available for common stock			$	33,415		$	25,161		$	150,941		$	121,477

(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:

			June 30, 2022						December 31, 2021
Billed Accounts Receivable			$	188,649					$	181,027
Unbilled Revenue			81,647						142,738
Less: Allowance for Credit Losses			(3,193)						(2,113)
Accounts Receivable, net			$	267,103					$	321,652

Changes to allowance for credit losses for the six months ended June 30, 2022 and 2021, 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 June 30,
2022						$	2,113											$	4,239					$	1,266					$	(4,425)					$	3,193
2021						$	7,003											$	1,510					$	1,786					$	(4,270)					$	6,029

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:

			June 30, 2022						December 31, 2021
Materials and supplies			$	91,736					$	86,400
Fuel - Electric Utilities			2,169						1,267
Natural gas in storage			58,959						63,312
Total materials, supplies and fuel			$	152,864					$	150,979

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Accrued Liabilities

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

			June 30, 2022						December 31, 2021
Accrued employee compensation, benefits and withholdings			$	64,417					$	74,387
Accrued property taxes			42,944						50,874
Customer deposits and prepayments			43,151						48,814
Accrued interest			33,764						33,680
Other (none of which is individually significant)			42,044						37,004
Total accrued liabilities			$	226,320					$	244,759

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 our 2021 Form 10-K.

Executive Summary

We are a customer-focused energy solutions provider that invests in our communities’ safety, sustainability and growth with a mission of Improving Life with Energy and a vision to be the Energy Partner of Choice. The Company’s core mission— and our primary focus — is to provide safe, reliable and cost-effective electric and natural gas service to 1.3 million utility customers in 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.

In 2021, 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, we have received final commission approval for all of our Winter Storm Uri cost recovery applications with the exception of Wyoming Gas (which is approved for interim cost recovery). See Note 2 of the Notes to Condensed Consolidated Financial Statements for further information.

Macroeconomic Trends

We are monitoring macroeconomic trends including inflationary pressures on the prices of commodities, materials, outside services and employee costs; supply chain constraints; rising interest rates and a competitive and tight labor market. To date, we have experienced moderate net impacts from these trends.

We have seen an increase in commodity energy costs that had an effect on customer bills. Our utilities have regulatory mechanisms that allow them to pass prudently incurred costs of energy through to the customer, which mitigates our exposure. Customer billing rates are adjusted periodically to reflect changes in our cost of energy.

We are proactively managing increased costs of materials and supply chain disruptions to achieve our forecasted capital investment targets. We have already contracted a significant majority of the materials needed for our 2022 capital program. We have also evaluated each of our forecasted projects and will prioritize depending on future constraints. Project delays may occur if costs rise significantly or if materials are not available.

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Rising interest rates have increased interest expense on our variable rate borrowings, which include our Revolving Credit Facility and CP Program. However, the increased interest expense was limited since 92% of our debt at June 30, 2022 is fixed rate debt. Additionally, rising discount rates and recent capital markets volatility did not materially change the unfunded status of the BHC Pension Plan from the prior year.

We are faced with increased competition for employee and contractor talent in the current labor market. To date, we have seen increased employee and contractor costs related to attraction and retention of talent partially offset by decreases in headcount compared to the prior year.

More detailed discussion of the future uncertainties can be found in “Risk Factors” section in Part I, Item 1A of our 2021 Annual Report on Form 10-K.

Business Segment Recent Developments

Electric Utilities

•See Note 2 of the Notes to Condensed Consolidated Financial Statements for recent rate review activity for Wyoming Electric.

•On July 21, 2022, Wyoming Electric set a new all-time and summer peak load of 294 MW, surpassing the previous peaks of 288 MW set on July 18, 2022, 282 MW set on June 13, 2022 and 274 MW set on July 28, 2021.

•On July 18, 2022, South Dakota Electric set a new all-time and summer peak load of 403 MW, surpassing the previous summer peak of 397 MW set in July 2021.

•On June 21, 2022, Wyoming Electric completed its first agreement for service under its Blockchain Interruptible Service tariff. Under the five-year agreement, Wyoming Electric will deliver to a new customer in Cheyenne, Wyoming up to 45 MW with an option to expand service up to 75 MW. Energy will be sourced through the electric energy market and delivered through our Electric Utilities’ infrastructure. Under the agreement, the customer will be responsible for costs of service, and the load will be interruptible to prioritize the needs of Wyoming Electric’s existing retail customers. Wyoming Electric expects to begin delivering energy to this customer in the fourth quarter of 2022.

•On May 27, 2022, Colorado Electric filed its Clean Energy Plan, “2030 Ready Plan”, with the CPUC. The 2030 Ready Plan establishes a roadmap and preferred resource portfolio for Colorado Electric to cost-effectively achieve the state of Colorado’s requirement calling upon electric utilities to reduce GHG emissions by a minimum of 80% by 2030. The preferred resource portfolio calls for the addition of 149 MW of wind, 258 MW of solar and 50 MW of battery storage to Colorado Electric's system. The final mix of resources would be determined by the results of a competitive solicitation starting in 2023. Colorado legislation provides up to 50% utility ownership of these additions. As proposed, the plan will achieve a 90% reduction in emissions and result in 79% of Colorado Electric’s customers' electricity being generated by carbon-free sources by 2030. A CPUC decision on Phase 1 of the 2030 Ready Plan is expected by April 2023, which would be followed by a request for proposals for renewable energy resources.

•On February 23, 2022, Wyoming Electric set a new winter peak load of 262 MW, surpassing the previous winter peak of 252 MW set on January 5, 2022.

•On February 15, 2022, Wyoming Electric submitted a request to the WPSC seeking approval for a CPCN to construct an estimated 260-mile transmission expansion project. As proposed, the approximately $260 million transmission expansion project, known as Ready Wyoming, would provide customers long-term price stability and greater flexibility as power markets develop in the Western States. If approved, construction of the project would take place in multiple phases or segments spanning 2023 through 2025 and would interconnect South Dakota Electric’s and Wyoming Electric’s transmission systems.

•On January 26, 2022, Colorado Electric agreed to join SPP’s Western Energy Imbalance Service Market. Colorado Electric will join the market in April 2023 and will continue to study long-term solutions for joining or developing an organized wholesale market. The expansion allows the utilities to participate in a real-time market.

•In January 2022, South Dakota Electric placed in service a $19 million, 54-mile, 230 kV electric transmission line from Rapid City to Spearfish, South Dakota. The second leg of this transmission line rebuild project, an 85-mile segment from Spearfish to Gillette, Wyoming, is expected to be in service by the end of 2023.

•On January 5, 2022, South Dakota Electric and Wyoming Electric set new winter peak loads. Wyoming Electric’s new winter peak load of 252 MW surpasses the previous peak of 247 MW set in December 2019. South Dakota Electric’s new winter peak of 327 MW surpasses the previous winter peak of 326 MW set in February 2021.

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Gas Utilities

•See Note 2 of the Notes to Condensed Consolidated Financial Statements for recent rate review activity for Arkansas Gas.

•On June 6, 2022, Colorado Gas submitted a proposal to the CPUC seeking approval to offer a voluntary RNG and carbon offset program for residential and business customers. The program would allow participants to offset 100% or more of the emissions associated with their own natural gas usage. The offset would be achieved through a combination of carbon offset credits and RNG attributes. Colorado Gas has designed its voluntary RNG and carbon offset program as a comprehensive four-year pilot program starting in 2023 and running through 2026. On July 15, 2022, Kansas Gas submitted a similar RNG and carbon offset program proposal with the KCC. Nebraska Gas expects to submit a voluntary RNG and carbon offset program proposal to the NPSC later in 2022 with similar filings for Arkansas Gas, Iowa Gas and Wyoming Gas expected by 2023.

Corporate and Other

•On April 13, 2022, a jury awarded $41 million for claims made by GT Resources, LLC (“GTR”) against BHC and two of its subsidiaries (Black Hills Exploration and Production, Inc. and Black Hills Gas Resources, Inc.), which ceased oil and natural gas operations in 2018 as part of BHC’s decision to exit the exploration and production business. The claims involved a dispute over a 2.3-million-acre concession award in Costa Rica which was acquired by a BHC subsidiary in 2003. We believe we have meritorious defenses to the verdict and intend to appeal the verdict. See additional information in Note 3 of the Notes to Condensed Consolidated Financial Statements.

Results of Operations

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 six months ended June 30, 2022 and 2021, and our financial condition as of June 30, 2022 and December 31, 2021, 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.

In the fourth quarter of 2021, we integrated our power generation and mining businesses within the Electric Utilities segment. The alignment is consistent with the current way our CODM evaluates the performance of the business and makes decisions related to the allocation of resources. Comparative periods presented reflect this change. See further segment information in Note 12 of the Notes to Condensed Consolidated Financial Statements.

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

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Consolidated Summary and Overview

			Three Months Ended June 30,						Six Months Ended June 30,
			2022			2021						2022			2021
			(in thousands, except per share amounts)
Operating income (loss):
Electric Utilities			$	45,226		$	47,462					$	95,972		$	86,805
Gas Utilities			28,195			19,985						151,735			122,079
Corporate and Other			(1,032)			(181)						(1,965)			(3,303)
Operating income			72,389			67,266						245,742			205,581
Interest expense, net			(38,764)			(38,202)						(77,309)			(75,802)
Other income (expense), net			1,563			(191)						2,267			75
Income tax benefit (expense)			658			(586)						(13,830)			(1,080)
Net income			35,846			28,287						156,870			128,774
Net income attributable to non-controlling interest			(2,431)			(3,126)						(5,929)			(7,297)
Net income available for common stock			$	33,415		$	25,161					$	150,941		$	121,477
Total earnings per share of common stock, Diluted			$	0.52		$	0.40					$	2.33		$	1.93

Three Months Ended June 30, 2022 Compared to Three Months Ended June 30, 2021:

The variance to the prior year included the following:

•Electric Utilities’ operating income decreased $2.2 million primarily due to higher operating expenses, lower pricing on the new Wygen I PPA and prior year regulatory actions reducing certain Winter Storm Uri impacts partially offset by increased rider revenues and prior year mark-to-market adjustments on wholesale energy contacts;

•Gas Utilities’ operating income increased $8.2 million primarily due to carrying costs on our Winter Storm Uri regulatory asset and new rates and rider recovery partially offset by higher operating expenses and unfavorable mark-to-market adjustments on wholesale commodity contracts;

•Other income increased $1.8 million primarily due to lower costs for our non-qualified benefit plans which were driven by market performance; and

•Income tax benefit increased $1.2 million driven by a lower effective tax rate due to tax benefits from state tax rate changes partially offset by higher pre-tax income.

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021:

The variance to the prior year included the following:

•Electric Utilities’ operating income increased $9.2 million primarily due to prior year impacts related to Colorado Electric’s TCJA-related bill credits to customers (which were offset by reduced income tax expense), increased rider revenues, prior year mark-to-market adjustments on wholesale energy contacts and increased transmission and off-system energy sales partially offset by higher operating expenses and lower pricing on the new Wygen I PPA;

•Gas Utilities’ operating income increased $30 million primarily due to new rates and rider recovery, carrying costs on our Winter Storm Uri regulatory asset, prior year Black Hills Energy Services Winter Storm Uri costs, customer growth and increased usage per customer partially offset by higher operating expenses;

•Corporate and Other expenses decreased $1.3 million primarily due to an allocation of a 2020 employee cost true-up in the first quarter of 2021, which was offset in our business segments;

•Interest expense increased $1.5 million due to higher interest rates and higher debt balances primarily driven by Winter Storm Uri;

•Other income increased $2.2 million primarily due to lower costs for our non-qualified benefit plans which were driven by market performance;

•Income tax expense increased $13 million driven by higher pre-tax income and a higher effective tax rate primarily due to prior year tax benefits from Colorado Electric and Nebraska Gas TCJA-related bill credits partially offset by tax benefits from state tax rate changes; and

•Net income attributable to non-controlling interest decreased $1.4 million due to lower net income from Black Hills Colorado IPP primarily driven by a planned outage.

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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, Electric and Gas Utility 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. Electric and Gas Utility margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of operation and maintenance expenses, depreciation and amortization expenses, and property and production taxes from the measure.

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

Our Electric and Gas Utility margin measure may not be comparable to other companies’ Electric and Gas Utility margin measures. 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 June 30,									Six Months Ended June 30,
			2022			2021			Variance			2022			2021			Variance
Revenue:
Electric - regulated			$	194,197		$	181,503		$	12,694		$	389,921		$	404,599		$	(14,678)
Other - non-regulated			10,182			9,513			669			20,995			21,821			(826)
Total revenue			204,379			191,016			13,363			410,917			426,420			(15,503)
Cost of fuel and purchased power:
Electric - regulated			55,723			44,607			11,116			107,202			144,076			(36,874)
Other - non-regulated			909			956			(47)			1,840			1,786			54
Total cost of fuel and purchased power			56,632			45,563			11,069			109,042			145,862			(36,820)
Electric Utility margin (non-GAAP)			147,747			145,453			2,294			301,875			280,558			21,317
Operations and maintenance			69,000			65,301			3,699			138,669			129,035			9,634
Depreciation and amortization			33,521			32,690			831			67,234			64,718			2,516
Total operating expenses			102,521			97,991			4,530			205,903			193,753			12,150
Operating income			$	45,226		$	47,462		$	(2,236)		$	95,972		$	86,805		$	9,167

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Three Months Ended June 30, 2022 Compared to the Three Months Ended June 30, 2021:

Electric Utility margin increased as a result of the following:

			(in millions)
New rates and rider recovery			$	4.2
Prior year mark-to-market on wholesale energy contracts			3.6
Lower pricing on new Wygen I PPA			(2.6)
Prior year Winter Storm Uri impacts (a)			(2.4)
Other			(0.5)
Total increase in Electric Utility margin			$	2.3

__________

(a)    In the first quarter 2021, our Electric Utilities accrued $3.2 million of negative impacts to our regulated wholesale power margins due to the higher fuel costs associated with Winter Storm Uri. Through regulatory actions in the second quarter of 2021, our Electric Utilities were able to reduce $2.4 million of that negative impact.

Operations and maintenance expense increased primarily due to higher outside services expenses, higher cloud computing licensing costs and increased property taxes due to a higher asset base.

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

Six Months Ended June 30, 2022 Compared to the Six Months Ended June 30, 2021:

Electric Utility margin increased as a result of the following:

			(in millions)
Prior year TCJA-related bill credits (a)			$	9.3
New rates and rider recovery			6.3
Prior year mark-to-market on wholesale energy contracts			5.1
Transmission services and off-system energy sales			2.6
Customer load growth			1.8
Prior year Winter Storm Uri impacts (b)			1.2
Lower pricing on new Wygen I PPA			(5.1)
Weather			(0.2)
Other			0.3
Total increase in Electric Utility margin			$	21.3

__________

(a)    In February 2021, Colorado Electric delivered $9.3 million of TCJA-related bill credits to its customers. These bill credits were offset by a reduction in income tax expense and resulted in an immaterial 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 partially offset by $1.7 million of increased Electric Utility margin realized under Black Hills Wyoming’s Economy Energy PSA.

Operations and maintenance expense increased primarily due to higher cloud computing licensing costs, higher maintenance expenses driven by planned generation outages, higher fuel costs, higher outside services expenses and increased property taxes due to a higher asset base.

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

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Operating Statistics

			Revenue (in thousands)															Quantities Sold (MWh)
			Three Months Ended June 30,						Six Months Ended June 30,									Three Months Ended June 30,						Six Months Ended June 30,
			2022			2021			2022			2021						2022			2021			2022			2021
Residential			$	52,853		$	53,451		$	115,102		$	126,211					323,775			335,063			715,357			731,149
Commercial			68,756			66,809			133,109			143,816						509,830			501,463			1,000,248			994,418
Industrial			38,190			35,186			73,598			78,195						464,928			441,793			928,696			856,984
Municipal			4,992			4,382			9,567			9,402						40,240			39,863			75,545			76,105
Subtotal Retail Revenue - Electric			164,791			159,828			331,377			357,624						1,338,773			1,318,182			2,719,846			2,658,656
Contract Wholesale			4,339			3,010			10,262			8,932						150,645			129,763			332,852			286,758
Off-system/Power Marketing Wholesale			8,666			7,266			15,820			12,038						144,425			148,981			304,866			209,202
Other (a)			16,400			11,399			32,463			26,005						—			—			—			—
Total Regulated			194,197			181,503			389,921			404,599						1,633,843			1,596,926			3,357,564			3,154,616
Non-Regulated (b)			10,182			9,513			20,995			21,821						72,770			61,408			161,864			140,923
Total Revenue and Quantities Sold			$	204,379		$	191,016		$	410,917		$	426,420					1,706,613			1,658,334			3,519,428			3,295,539
Other Uses, Losses or Generation, net (c)																		98,323			94,932			211,609			227,680
Total Energy																		1,804,936			1,753,266			3,731,037			3,523,219

__________

(a)    Primarily related to transmission revenues from the Common Use System.

(b)    Includes Integrated Generation and non-regulated services to our retail customers under the Service Guard Comfort Plan and Tech Services.

(c)    Includes company uses and line losses.

			Revenue (in thousands)															Quantities Sold (MWh)
			Three Months Ended June 30,															Six Months Ended June 30,									Three Months Ended June 30,						Six Months Ended June 30,
			2022			2021												2022			2021						2022			2021			2022			2021
Colorado Electric			$	71,197		$	64,009											$	146,642		$	143,446					568,890			596,364			1,188,478			1,150,344
South Dakota Electric			76,195			72,640												154,792			166,769						600,172			581,628			1,244,395			1,163,476
Wyoming Electric			47,146			45,601												89,235			95,551						464,781			418,934			924,691			840,796
Integrated Generation			9,841			8,766												20,248			20,654						72,770			61,408			161,864			140,923
Total Revenue and Quantities Sold			$	204,379		$	191,016											$	410,917		$	426,420					1,706,613			1,658,334			3,519,428			3,295,539

			Three Months Ended June 30,						Six Months Ended June 30,
Quantities Generated and Purchased by Fuel Type (MWh)			2022			2021			2022			2021
Generated:
Coal			589,438			623,822			1,252,876			1,241,956
Natural Gas and Oil			262,157			377,155			558,579			750,941
Wind			244,456			195,736			498,024			409,583
Total Generated			1,096,051			1,196,713			2,309,479			2,402,480
Purchased:
Coal, Natural Gas, Oil and Other Market Purchases			608,045			481,346			1,196,205			945,887
Wind			100,840			75,207			225,353			174,852
Total Purchased			708,885			556,553			1,421,558			1,120,739
Total Generated and Purchased			1,804,936			1,753,266			3,731,037			3,523,219

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			Three Months Ended June 30,						Six Months Ended June 30,
Quantities Generated and Purchased (MWh)			2022			2021			2022			2021
Generated:
Colorado Electric			112,117			110,821			197,548			201,077
South Dakota Electric			367,936			442,665			823,541			911,481
Wyoming Electric			225,720			222,540			430,318			396,530
Integrated Generation			390,278			420,687			858,072			893,392
Total Generated			1,096,051			1,196,713			2,309,479			2,402,480
Purchased:
Colorado Electric			255,969			251,648			556,366			471,893
South Dakota Electric			248,625			154,633			445,688			296,635
Wyoming Electric			185,932			135,177			376,737			307,602
Integrated Generation			18,359			15,095			42,767			44,609
Total Purchased			708,885			556,553			1,421,558			1,120,739
Total Generated and Purchased			1,804,936			1,753,266			3,731,037			3,523,219

			Three Months Ended June 30,															Six Months Ended June 30,
			2022						2021									2022						2021
Degree Days			Actual			Variance from Normal			Actual			Variance from Normal						Actual			Variance from Normal			Actual			Variance from Normal
Heating Degree Days:
Colorado Electric			556			(5)		%	595			(6)		%				3,271			5		%	3,326			2		%
South Dakota Electric			1,221			13		%	1,048			2		%				4,469			3		%	4,372			3		%
Wyoming Electric			1,159			(3)		%	1,221			2		%				4,291			2		%	4,482			6		%
Combined (a)			904			3		%	875			—		%				3,885			4		%	3,915			3		%
Cooling Degree Days:
Colorado Electric			333			24		%	300			44		%				333			24		%	300			44		%
South Dakota Electric			107			15		%	167			69		%				107			15		%	167			69		%
Wyoming Electric			121			102		%	117			134		%				121			102		%	117			134		%
Combined (a)			213			28		%	218			56		%				213			28		%	218			56		%

__________

(a)    Degree days are calculated based on a weighted average of total customers by state.

			Three Months Ended June 30,						Six Months Ended June 30,
Contracted generating facilities Availability by fuel type (a)			2022			2021			2022			2021
Coal (b) (c)			82.1		%	86.1		%	86.3		%	86.2		%
Natural gas and diesel oil			95.1		%	97.6		%	95.2		%	93.8		%
Wind			93.8		%	96.8		%	94.7		%	95.3		%
Total Availability			91.4		%	94.4		%	92.7		%	92.1		%
Wind Capacity Factor			39.8		%	31.0		%	40.9		%	34.1		%

__________

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

(b) 2022 included planned outages at Neil Simpson II and Wyodak Plant.

(c)     2021 included planned outages at Neil Simpson II, Wygen, Wygen II, and Wygen III and unplanned outages at Neil Simpson II and Wyodak Plant.

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Gas Utilities

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

			Three Months Ended June 30,									Six Months Ended June 30,
			2022			2021			Variance			2022			2021			Variance
Revenue:
Natural gas - regulated			$	258,349		$	172,465		$	85,884		$	854,807		$	550,542		$	304,265
Other - non-regulated			15,821			13,585			2,236			40,755			38,027			2,728
Total revenue			274,169			186,050			88,119			895,561			588,569			306,992
Cost of natural gas sold:
Natural gas - regulated			126,704			62,317			64,387			510,416			245,284			265,132
Other - non-regulated			5,040			798			4,242			6,055			10,881			(4,826)
Total cost of natural gas sold			131,744			63,115			68,629			516,471			256,165			260,306
Gas Utility margin (non-GAAP)			142,425			122,935			19,490			379,090			332,404			46,686
Operations and maintenance			83,689			77,263			6,426			170,130			159,463			10,667
Depreciation and amortization			30,541			25,687			4,854			57,225			50,862			6,363
Total operating expenses			114,230			102,950			11,280			227,355			210,325			17,030
Operating income			$	28,195		$	19,985		$	8,210		$	151,735		$	122,079		$	29,656

Three Months Ended June 30, 2022 Compared to the Three Months Ended June 30, 2021:

Gas Utility margin increased as a result of the following:

			(in millions)
Carrying costs on Winter Storm Uri regulatory asset (a)			$	12.3
New rates and rider recovery			4.6
Current and prior year TCJA-related bill credits (b)			2.2
Increased transportation and transmission volumes			1.9
Residential customer growth and increased usage per customer			1.5
Mark-to-market on non-utility natural gas commodity contracts			(4.3)
Weather			(0.2)
Other			1.5
Total increase in Gas Utility margin			$	19.5

__________

(a)    In certain jurisdictions, we have Commission approval to recover carrying costs on Winter Storm Uri regulatory assets which offset increased interest expense. Additionally, the carrying costs accrued during the three months ended June 30, 2022 included a one-time, $10.3 million true-up to reflect Commission authorized rates. See Note 2 of the Notes to Condensed Consolidated Financial Statements for additional information.

(b) In June 2021, Nebraska Gas provided $2.9 million TCJA-related bill credits to its customers. For the three months ended June 30, 2022, Kansas Gas provided $0.7 million of TCJA and state tax reform bill credits to customers. These bill credits were offset by a reduction in income tax expense and resulted in an immateriall impact to Net income.

Operations and maintenance expense increased primarily due to higher outside services and materials expenses, increased bad debt expense primarily attributable to higher billings, higher cloud computing licensing costs and higher vehicle expenses due to higher fuel costs.

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

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Six Months Ended June 30, 2022 Compared to the Six Months Ended June 30, 2021:

Gas Utility margin increased as a result of the following:

			(in millions)
New rates and rider recovery			$	17.4
Carrying costs on Winter Storm Uri regulatory asset (a)			14.6
Prior year Black Hills Energy Services Winter Storm Uri costs (b)			8.2
Residential customer growth and increased usage per customer			4.5
Increased transportation and transmission volumes			1.5
Current and prior year TCJA-related bill credits (c)			1.4
Weather			(1.0)
Mark-to-market on non-utility natural gas commodity contracts			(0.9)
Other			1.0
Total increase in Gas Utility margin			$	46.7

__________

(a)    In certain jurisdictions, we have Commission approval to recover carrying costs on Winter Storm Uri regulatory assets which offset increased interest expense. Additionally, the carrying costs accrued during the six months ended June 30, 2022 included a one-time, $10.3 million true-up to reflect Commission authorized rates. 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 was not recoverable through a regulatory mechanism.

(c) In June 2021, Nebraska Gas provided $2.9 million TCJA-related bill credits to its customers. For the three months ended June 30, 2022, Kansas Gas provided $1.5 million of TCJA and state tax reform bill credits to 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 higher cloud computing licensing costs, higher outside services and materials expenses, increased bad debt expense primarily attributable to higher billings, higher vehicle expenses due to higher fuel costs and increased property taxes due to a higher asset base.

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

Operating Statistics

			Revenue (in thousands)															Quantities Sold and Transported (Dth)
			Three Months Ended June 30,						Six Months Ended June 30,									Three Months Ended June 30,						Six Months Ended June 30,
			2022			2021			2022			2021						2022			2021			2022			2021
Residential			$	143,127		$	98,370		$	519,171		$	332,767					8,523,755			8,575,051			40,338,005			39,143,789
Commercial			61,182			36,888			219,824			127,977						4,499,245			4,493,931			19,130,948			18,306,252
Industrial			16,875			5,811			26,113			10,713						2,150,532			1,337,672			3,315,115			2,235,961
Other			2,300			(418)			5,072			(890)						—			—			—			—
Total Distribution			223,483			140,651			770,179			470,567						15,173,532			14,406,654			62,784,068			59,686,002
Transportation and Transmission			34,865			31,814			84,627			79,975						37,623,610			34,074,214			82,668,813			79,388,652
Total Regulated			258,349			172,465			854,807			550,542						52,797,142			48,480,868			145,452,881			139,074,654
Non-regulated Services			15,821			13,585			40,755			38,027						—			—			—			—
Total Revenue and Quantities Sold			$	274,169		$	186,050		$	895,561		$	588,569					52,797,142			48,480,868			145,452,881			139,074,654

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			Revenue (in thousands)															Quantities Sold & Transported (Dth)
			Three Months Ended June 30,						Six Months Ended June 30,									Three Months Ended June 30,						Six Months Ended June 30,
			2022			2021			2022			2021						2022			2021			2022			2021
Arkansas Gas			$	51,815		$	32,994		$	179,624		$	119,988					5,445,450			5,718,417			18,373,186			19,025,151
Colorado Gas			50,328			34,190			170,381			113,312						6,365,777			5,957,285			19,784,461			19,323,300
Iowa Gas			42,050			29,831			162,629			86,585						8,178,613			7,016,613			23,554,795			21,330,586
Kansas Gas			35,482			21,163			94,333			61,226						8,762,807			7,155,427			19,751,874			17,618,224
Nebraska Gas			62,337			43,037			196,571			136,135						16,714,480			15,822,880			44,050,254			43,106,981
Wyoming Gas			32,157			24,835			92,023			71,323						7,330,015			6,810,246			19,938,311			18,670,412
Total Revenue and Quantities Sold			$	274,169		$	186,050		$	895,561		$	588,569					52,797,142			48,480,868			145,452,881			139,074,654

			Three Months Ended June 30,															Six Months Ended June 30,
			2022						2021									2022						2021
Heating Degree Days			Actual			Variance from Normal			Actual			Variance from Normal						Actual			Variance from Normal			Actual			Variance from Normal
Arkansas Gas (a)			271			(18)%			383			16%						2,370			(3)%			2,504			3%
Colorado Gas			817			(14)%			865			(9)%						3,763			(3)%			3,830			(1)%
Iowa Gas			803			17%			691			1%						4,382			8%			4,113			1%
Kansas Gas (a)			436			(2)%			493			10%						3,020			4%			3,069			5%
Nebraska Gas			679			7%			624			(1)%						3,720			1%			3,721			1%
Wyoming Gas			1,326			9%			1,200			(1)%						4,598			4%			4,625			5%
Combined (b)			768			2%			739			1%						3,933			2%			3,925			2%

__________

(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.

Corporate and Other

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

			Three Months Ended June 30,									Six Months Ended June 30,
			2022			2021			Variance			2022			2021			Variance
Operating (loss)			$	(1,032)		$	(181)		$	(851)		$	(1,965)		$	(3,303)		$	1,338

Three Months Ended June 30, 2022 Compared to the Three Months Ended June 30, 2021:

Operating (loss) was comparable to the same period in the prior year.

Six Months Ended June 30, 2022 Compared to the Six Months Ended June 30, 2021:

The decrease in Operating (loss) was primarily due to an allocation of a 2020 employee cost true-up in the first quarter of 2021, which was offset in our business segments.

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Consolidated Interest Expense, Other Income and Income Tax Expense

			Three Months Ended June 30,									Six Months Ended June 30,
			2022			2021			Variance			2022			2021			Variance
			(in thousands)
Interest expense, net			$	(38,764)		$	(38,202)		$	(562)		$	(77,309)		$	(75,802)		$	(1,507)
Other income, net			1,563			(191)			$	1,754		$	2,267		$	75		$	2,192
Income tax benefit (expense)			658			(586)			$	1,244		$	(13,830)		$	(1,080)		$	(12,750)

Three Months Ended June 30, 2022 Compared to the Three Months Ended June 30, 2021:

Interest Expense, net

Interest expense, net was comparable to the same period in the prior year.

Other Income, net

The increase in Other income, net was due to lower costs for our non-qualified benefit plans which were driven by market performance partially offset by higher non-service pension costs primarily driven by a higher discount rate.

Income Tax Benefit (Expense)

Income tax benefit increased due to a lower effective tax rate partially offset by higher pre-tax income. For the three months ended June 30, 2022, the effective tax rate was (1.9)% compared to 2.0% for the same period in 2021. See Note 11 of the Notes to Condensed Consolidated Financial Statements for discussion of effective tax rate variances.

Six Months Ended June 30, 2022 Compared to the Six Months Ended June 30, 2021:

Interest Expense, net

The increase in Interest expense, net was due to higher interest rates and higher debt balances primarily driven by Winter Storm Uri.

Other Income, net

The increase in Other income, net was due to lower costs for our non-qualified benefit plans which were driven by market performance partially offset by higher non-service pension costs primarily driven by a higher discount rate.

Income Tax Benefit (Expense)

Income tax expense increased due to higher pre-tax income and a higher effective tax rate. For the six months ended June 30, 2022, the effective tax rate was 8.1% compared to 0.8% for the same period in 2021. 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 2021 Annual Report on Form 10-K except as described below.

Cash Flow Activities

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

Cash provided by (used in):			2022			2021			Variance
Operating activities			$	442,030		$	(250,173)		$	692,203
Investing activities			$	(291,385)		$	(309,737)		$	18,352
Financing activities			$	(149,093)		$	554,905		$	(703,998)

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Six Months Ended June 30, 2022 Compared to the Six Months Ended June 30, 2021

Operating Activities:

Net cash provided by (used in) operating activities was $692 million higher than the same period in 2021. The variance to the prior year was primarily attributable to:

•Cash earnings (net income plus non-cash adjustments) were $26 million higher for the six months ended June 30, 2022 compared to the same period in the prior year primarily due to increased Electric and Gas Utility margins driven by new rates and increased rider revenues and prior year impacts from Winter Storm Uri.

•Net inflows from changes in certain operating assets and liabilities were $670 million higher, primarily attributable to:

◦Cash inflows increased by $679 million as a result of changes in our regulatory assets and liabilities primarily driven by prior year incremental fuel, purchased power and natural gas costs due to Winter Storm Uri and current year recovery of a portion of Winter Storm Uri incremental and carrying costs from customers;

◦Cash inflows decreased by $44 million as a result of changes in accounts receivable and other current assets primarily driven by higher pass-through revenues reflecting higher commodity prices; and

◦Cash outflows decreased by $36 million as a result of changes in accounts payable and accrued liabilities primarily driven by payment timing of natural gas and power purchases and other working capital requirements.

•Cash outflows increased by $4.0 million for other operating activities which was primarily driven by changes in contractor retainage balances.

Investing Activities:

Net cash used in investing activities was $18 million lower than the same period in 2021. The variance to the prior year was primarily attributable to:

•Capital expenditures of $294 million for the six months ended June 30, 2022 compared to $319 million for the same period in the prior year. Lower current year expenditures were driven by lower programmatic safety, reliability and integrity spending at our Gas and Electric Utilities; and

•Cash inflows decreased by $7.3 million for other investing activities which was primarily driven by prior year sales of transmission assets and facilities, none of which were individually material.

Financing Activities:

Net cash used in financing activities was $704 million higher than the same period in 2021. The variance to the prior year was primarily attributable to:

•Cash inflows decreased $680 million due to short-term and long-term repayments in excess of borrowings which was primarily driven by prior year term loan borrowings related to Winter Storm Uri;

•Cash inflows decreased $20 million due to decreased issuances of common stock;

•Cash outflows increased $6.0 million due to increased dividends paid on common stock; and

•Cash inflows increased by $1.4 million for other financing activities.

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Capital Resources

Short-term Debt

Revolving Credit Facility and CP Program

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

						Current			Short-term borrowings at			Letters of Credit (a) at			Available Capacity at
Credit Facility			Expiration			Capacity			June 30, 2022			June 30, 2022			June 30, 2022
Revolving Credit Facility and CP Program			July 19, 2026			$	750		$	335		$	14		$	401

__________

(a)    Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility. For more information on these letters of credit, see Note 5 of the Notes to Condensed Consolidated Financial Statements.

The weighted average interest rate on short-term borrowings at June 30, 2022 was 1.74%. Short-term borrowing activity for the six months ended June 30, 2022 was:

			(dollars in millions)
Maximum amount outstanding (based on daily outstanding balances)			$	429
Average amount outstanding (based on daily outstanding balances)			$	326
Weighted average interest rates			0.82		%

Covenant Requirements

The Revolving Credit Facility and Wyoming Electric’s financing agreements contain covenant requirements. We were in compliance with these covenants as of June 30, 2022. See Note 5 of the Notes to Condensed Consolidated Financial Statements for more information.

Equity

See Note 5 of the Notes to Condensed Consolidated Financial Statements for information related to common stock issuances under the ATM.

Future Financing Plans

We will continue to assess debt and equity needs to support our capital investment plans and other strategic objectives. 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 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.

The following table represents the credit ratings, outlook and risk profile of BHC at June 30, 2022:

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

__________

(a)    On October 20, 2021, S&P reported BBB+ rating and maintained a Stable outlook.

(b)    On December 20, 2021, Moody’s reported Baa2 rating and maintained a Stable outlook.

(c)    On September 17, 2021, Fitch reported BBB+ rating and maintained a Stable outlook.

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The following table represents the credit ratings of South Dakota Electric at June 30, 2022:

Rating Agency			Senior Secured Rating
S&P (a)			A
Fitch (b)			A

__________

(a)    On March 31, 2022, S&P reported A rating.

(b)    On September 17, 2021, Fitch reported A rating.

Capital Requirements

Capital Expenditures

			Actual						Forecasted
Capital Expenditures by Segment			Six Months Ended June 30, 2022 (a)						2022 (b)			2023			2024			2025			2026
(in millions)
Electric Utilities			$	120					$	239		$	205		$	285		$	231		$	155
Gas Utilities			150						363			383			386			349			346
Corporate and Other			4						9			12			13			13			13
Incremental Projects (c)			—						—			—			—			60			140
			$	274					$	611		$	600		$	684		$	653		$	654

__________

(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 six months ended June 30, 2022.

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

Dividends

Dividends paid on our common stock totaled $77 million for the six months ended June 30, 2022, or $0.595 per share per quarter. On July 25, 2022, our board of directors declared a quarterly dividend of $0.595 per share payable September 1, 2022, 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.

Critical Accounting Estimates

There have been no material changes in our critical accounting estimates from those reported in our 2021 Annual Report on Form 10-K. We are closely monitoring the impacts of recent macroeconomic trends 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 2021 Annual Report on Form 10-K.

New Accounting Pronouncements

Other than the pronouncements reported in our 2021 Annual Report on Form 10-K and those discussed in Note 1 of the Notes to Condensed Consolidated Financial Statements, 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.

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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 June 30, 2022. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at June 30, 2022.

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 June 30, 2022, 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.

PART II.    OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS

For information regarding legal proceedings, see Note 3 in Item 8 of our 2021 Annual Report on Form 10-K and Note 3 of the Notes to Condensed Consolidated Financial Statements.

ITEM 1A.RISK FACTORS

There are no material changes to the risk factors previously disclosed in Item 1A of Part I in our 2021 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 June 30, 2022:

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
April 1, 2022 - April 30, 2022			2			$	78.44		—			—
May 1, 2022 - May 31, 2022			741			$	75.60		—			—
June 1, 2022 - June 30, 2022			3			$	76.38		—			—
Total			746			$	75.61		—			—

__________

(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.

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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
10.1			Black Hills Corporation Amended and Restated 2015 Omnibus Incentive Plan (filed as Appendix A to the Registrant’s definitive proxy statement for the 2022 Annual Meeting of Shareholders filed on March 17, 2022).
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:			August 4, 2022

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