UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended ~~September~~June 30, ~~2022~~

2023

☐ 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 Dakota57702

Registrant’s telephone number ~~(605)~~ (605) 721-1700

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

NONE

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

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

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

~~Large Accelerated Filer~~

~~Accelerated Filer~~

☐

Large Accelerated Filer

Accelerated Filer

☐

Non-accelerated Filer

☐

Smaller Reporting Company

☐

Emerging Growth Company

☐

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

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

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common stock of $1.00 par value

BKH

New York Stock Exchange

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

Class

Outstanding at ~~October~~July 31, ~~2022~~2023

Common stock, $1.00 par value

~~65,078,259~~ 67,110,952

~~Table of Contents~~

TABLE OF CONTENTS


~~TABLE OF CONTENTS~~		Page
					~~Page~~
Glossary of Terms and Abbreviations				43
Forward-Looking Information			76

PART I. FINANCIAL INFORMATION		7

Item 1.	Financial Statements - unaudited		87
	~~Condensed~~ Consolidated Statements of Income		87
	~~Condensed~~ Consolidated Statements of Comprehensive Income		98
	~~Condensed~~ Consolidated Balance Sheets		109
	~~Condensed~~ Consolidated Statements of Cash Flows		1211
	~~Condensed~~ Consolidated Statements of Equity		1312
	Condensed Notes to ~~Condensed~~ Consolidated Financial Statements		1513
	Note 1. Management’s Statement		1513
	Note 2. Regulatory Matters		1613
	Note 3. Commitments, Contingencies and Guarantees		1814
	Note 4. Revenue		1914
	Note 5. Financing		2116
	Note 6. Earnings Per Share		2218
	Note 7. Risk Management and Derivatives		2219
	Note 8. Fair Value Measurements		2622
	Note 9. Other Comprehensive Income		2824
	Note 10. Employee Benefit Plans		2925
	Note 11. Income Taxes		3026
	Note 12. Business Segment Information		3026
	Note 13. Selected Balance Sheet Information		3227
	Note 14. Subsequent Events

~~Table of Contents~~

					27
~~TABLE OF CONTENTS~~
				~~Page~~
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations	3328
	Executive Summary	3328
	Recent Developments	3328
	Results of Operations	3629
	Consolidated Summary and Overview	3629
	Non-GAAP Financial Measure	3730
	Electric Utilities	3831
	Gas Utilities	4234

		Corporate and Other		4436
	Consolidated Interest Expense, Other Income and Income Tax Expense	4536
	Liquidity and Capital Resources	4537
	Cash Flow Activities	4537
	Capital Resources	4738
	Credit Ratings	4739
	Capital Requirements	4839
	Critical Accounting Estimates	4841
	New Accounting Pronouncements	4841

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4941
Item 4.	Controls and Procedures	4941

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	4941
Item 1A.	Risk Factors	4941
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4941

Item 4.		Mine Safety Disclosures	5042
Item 5.	Other Information	42
Item 6.	Exhibits	5042

Signatures		5143

Table of Contents

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).



~~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 Electric Parent Holdings	Black Hills Electric Utility Holdings, LLC., a direct, wholly-owned subsidiary of Black Hills Corporation
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.
Clean Energy Plan	2030 Ready Plan that 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% from 2005 levels 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 will be determined by the results of a competitive solicitation that started in July 2023. Colorado legislation allows electric utilities to own up to 50% of the renewable generation assets added to comply with the Clean Energy Plan.





Colorado Electric		Black Hills Colorado Electric, LLC, a direct, wholly-owned subsidiary of Black Hills ~~Utility~~Electric Parent Holdings, providing electric ~~service~~services 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~~participated 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	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.

Table of Contents



~~CPCN~~			~~Certificate of Public Convenience and Necessity~~
CP Program			Commercial Paper Program

~~Table of Contents~~


CPUC	Colorado Public Utilities Commission
DRSPP	Dividend Reinvestment and Stock Purchase Plan




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


~~EPA~~		~~United States Environmental Protection Agency~~
FASB		Financial Accounting Standards Board

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




Heating Degree Day		A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
HomeServe	We offer HomeServe products to our natural gas residential customers interested in purchasing additional home repair service plans.
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~~kV	~~Kansas Corporation Commission~~Kilovolt
kV	~~Kilovolt~~
LIBOR		London Interbank Offered Rate

MEAN		Municipal Energy Agency of Nebraska
MMBtu	Million British thermal units
Moody's
~~Moody’s~~		~~Moody’s~~Moody's Investors Service, Inc.
MW	Megawatts
MWMWh	~~Megawatts~~Megawatt-hours
~~MWh~~N/A	~~Megawatt-hours~~Not applicable
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~~Northern Iowa Windpower	~~A mine-mouth, coal-fired power plant~~Northern Iowa Windpower, LLC, a 87.1 MW wind farm located near Joice, Iowa, previously owned ~~and operated~~ by ~~South Dakota~~Black Hills Electric ~~with~~Generation. In March 2023, Black Hills Electric Generation completed the sale of Northern Iowa Windpower assets to a ~~total capacity of 90 MW located at our Gillette, Wyoming energy complex.~~third-party.

NOx		~~Nitrogen oxide~~
~~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 on May 9, 2023 and ~~restated on July 19, 2021, and now terminates~~will terminate on July 19, 2026.
RMNG	Rocky Mountain Natural Gas LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas transmission and wholesale services in western Colorado (doing business as Black Hills Energy).

~~Table of Contents~~


~~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.
S&P	S&P Global Ratings, a division of S&P Global Inc.
SOFR	Secured Overnight Financing Rate
South Dakota Electric	Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and Wyoming (doing business as Black Hills Energy).
SSIR	System Safety and Integrity Rider
~~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’~~Hills' Electric and Gas Utilities

Table of Contents


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~~2022 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;

•

The effects of changing interest rates;

•

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.

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BLACK HILLS CORPORATION

~~CONDENSED~~

CONSOLIDATED STATEMENTS OF INCOME

(unaudited) Three Months Ended September 30, Nine Months Ended September 30,
2022 2021 2022 2021
(in thousands, except per share amounts)
Revenue $ 462,612 $ 380,590 $ 1,760,377 $ 1,386,594
Operating expenses:
Fuel, purchased power and cost of natural gas sold 168,535 94,057 793,632 495,678
Operations and maintenance 134,449 122,277 403,549 375,201
Depreciation, depletion and amortization 64,019 59,159 188,610 174,871
Taxes - property and production 16,130 15,224 49,365 45,390
Total operating expenses 383,133 290,717 1,435,156 1,091,140
Operating income 79,479 89,873 325,221 295,454
Other income (expense):
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) (40,580) (38,604) (118,454) (115,098)
Interest income 561 586 1,126 1,278
Other income, net 464 1,560 2,731 1,635
Total other income (expense) (39,555) (36,458) (114,597) (112,185)
Income before income taxes 39,924 53,415 210,624 183,269
Income tax (expense) (2,090) (5,253) (15,920) (6,333)
Net income 37,834 48,162 194,704 176,936
Net income attributable to non-controlling interest (2,861) (4,050) (8,790) (11,347)
Net income available for common stock $ 34,973 $ 44,112 $ 185,914 $ 165,589
Earnings per share of common stock:
Earnings per share, Basic $ 0.54 $ 0.70 $ 2.87 $ 2.63
Earnings per share, Diluted $ 0.54 $ 0.70 $ 2.86 $ 2.63
Weighted average common shares outstanding:
Basic 64,876 63,341 64,722 62,950
Diluted 65,061 63,436 64,910 63,046


(unaudited)	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
	(in thousands, except per share amounts)
Revenue	$	411,283		$	474,195		$	1,332,442		$	1,297,765

Operating expenses:
Fuel, purchased power and cost of natural gas sold		121,245			188,171			647,512			625,097
Operations and maintenance		145,767			132,968			286,755			269,100
Depreciation, depletion and amortization		64,714			64,128			126,357			124,591
Taxes - property and production		16,041			16,539			33,419			33,235
Total operating expenses		347,767			401,806			1,094,043			1,052,023

Operating income		63,516			72,389			238,399			245,742

Other income (expense):
Interest expense incurred net of amounts capitalized		(43,267	)		(39,053	)		(87,332	)		(77,874	)
Interest income		1,746			289			2,307			565
Other income (expense), net		(1,540	)		1,563			(866	)		2,267
Total other income (expense)		(43,061	)		(37,201	)		(85,891	)		(75,042	)

Income before income taxes		20,455			35,188			152,508			170,700
Income tax benefit (expense)		6,089			658			(8,584	)		(13,830	)
Net income		26,544			35,846			143,924			156,870
Net income attributable to non-controlling interest		(3,491	)		(2,431	)		(6,787	)		(5,929	)
Net income available for common stock	$	23,053		$	33,415		$	137,137		$	150,941

Earnings per share of common stock:
Earnings per share, Basic	$	0.35		$	0.52		$	2.07		$	2.33
Earnings per share, Diluted	$	0.35		$	0.52		$	2.06		$	2.33

Weighted average common shares outstanding:
Basic		66,591			64,721			66,315			64,643
Diluted		66,684			64,883			66,419			64,822

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

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BLACK HILLS CORPORATION

~~CONDENSED~~

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited) Three Months Ended September 30, Nine Months Ended September 30,
2022 2021 2022 2021
(in thousands)
Net income $ 37,834 $ 48,162 $ 194,704 $ 176,936
Other comprehensive income (loss), net of tax:
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $8, $6, $22 and $21, respectively) (16) (19) (48) (53)
Reclassification adjustments of benefit plan liability - net loss (net of tax of $(66), $(139), $(179) and $(513), respectively) 122 459 384 1,280
Derivative instruments designated as cash flow hedges:
Reclassification of net realized losses on settled/amortized interest rate swaps (net of tax of $(134), $(55), $(549) and $(395), respectively) 578 657 1,589 1,743
Net unrealized gains on commodity derivatives (net of tax of $(559), $(1,437), $(165) and $(1,776), respectively) 1,776 4,430 509 5,476
Reclassification of net realized (gains) on settled commodity derivatives (net of tax of $10, $81, $881 and $87, respectively) (33) (250) (2,739) (269)
Other comprehensive income (loss), net of tax 2,427 5,277 (305) 8,177
Comprehensive income 40,261 53,439 194,399 185,113
Less: comprehensive income attributable to non-controlling interest (2,861) (4,050) (8,790) (11,347)
Comprehensive income available for common stock $ 37,400 $ 49,389 $ 185,609 $ 173,766


(unaudited)	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
	(in thousands)
Net income	$	26,544		$	35,846		$	143,924		$	156,870

Other comprehensive income (loss), net of tax;
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $--, $8, $-- and $14, respectively)		-			(14	)		-			(32	)
Reclassification adjustments of benefit plan liability - net loss (net of tax of $(27), $(68), $(43) and $(113), respectively)		16			119			44			262
Derivative instruments designated as cash flow hedges:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(177), $(238), $(327) and $(415), respectively)		536			475			1,099			1,011
Net unrealized gains (losses) on commodity derivatives (net of tax of $(35), $734, $233 and $394, respectively)		112			(2,314	)		(743	)		(1,267	)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $(118), $319, $(584) and $871, respectively)		371			(1,004	)		1,855			(2,706	)
Other comprehensive income, net of tax		1,035			(2,738	)		2,255			(2,732	)

Comprehensive income		27,579			33,108			146,179			154,138
Less: comprehensive income attributable to non-controlling interest		(3,491	)		(2,431	)		(6,787	)		(5,929	)
Comprehensive income available for common stock	$	24,088		$	30,677		$	139,392		$	148,209

See Note 9 for additional disclosures.

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

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BLACK HILLS CORPORATION

~~CONDENSED~~

CONSOLIDATED BALANCE SHEETS

(unaudited) As of
September 30, 2022 December 31, 2021
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 11,693 $ 8,921
Restricted cash and equivalents 5,399 4,889
Accounts receivable, net 249,747 321,652
Materials, supplies and fuel 223,162 150,979
Derivative assets, current 3,868 4,373
Income tax receivable, net 17,112 18,017
Regulatory assets, current 290,087 270,290
Other current assets 48,180 29,012
Total current assets 849,248 808,133
Property, plant and equipment 8,236,053 7,856,573
Less: accumulated depreciation and depletion (1,538,731) (1,407,397)
Total property, plant and equipment, net 6,697,322 6,449,176
Other assets:
Goodwill 1,299,454 1,299,454
Intangible assets, net 9,883 10,770
Regulatory assets, non-current 416,119 526,309
Other assets, non-current 50,268 38,054
Total other assets, non-current 1,775,724 1,874,587
TOTAL ASSETS $ 9,322,294 $ 9,131,896


(unaudited)	As of
	June 30, 2023			December 31, 2022
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	152,581		$	21,430
Restricted cash and equivalents		5,966			5,555
Accounts receivable, net		260,350			508,192
Materials, supplies and fuel		136,534			207,421
Derivative assets, current		303			582
Income tax receivable, net		18,222			17,637
Regulatory assets, current		198,443			260,312
Other current assets		29,929			50,579
Total current assets		802,328			1,071,708

Property, plant and equipment		8,590,796			8,374,790
Less: accumulated depreciation and depletion		(1,671,303	)		(1,576,842	)
Total property, plant and equipment, net		6,919,493			6,797,948

Other assets:
Goodwill		1,299,454			1,299,454
Intangible assets, net		9,002			9,589
Regulatory assets, non-current		325,228			392,669
Other assets, non-current		53,590			46,862
Total other assets, non-current		1,687,274			1,748,574

TOTAL ASSETS	$	9,409,095		$	9,618,230

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

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BLACK HILLS CORPORATION

~~CONDENSED~~

CONSOLIDATED BALANCE SHEETS

(Continued)

(unaudited) As of
September 30, 2022 December 31, 2021
(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 187,046 $ 217,761
Accrued liabilities 250,835 244,759
Derivative liabilities, current 5,569 1,439
Regulatory liabilities, current 24,797 17,574
Notes payable 501,350 420,180
Total current liabilities 969,597 901,713
Long-term debt, net of current maturities 4,131,033 4,126,923
Deferred credits and other liabilities:
Deferred income tax liabilities, net 491,859 465,388
Regulatory liabilities, non-current 469,963 485,377
Benefit plan liabilities 120,629 123,925
Other deferred credits and other liabilities 155,456 141,447
Total deferred credits and other liabilities 1,237,907 1,216,137
Commitments, contingencies and guarantees (Note 3)
Equity:
Stockholders’ equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 65,105,205 and 64,793,095 shares, respectively 65,105 64,793
Additional paid-in capital 1,811,093 1,783,436
Retained earnings 1,032,522 962,458
Treasury stock, at cost – 26,208 and 54,078 shares, respectively (1,715) (3,509)
Accumulated other comprehensive (loss) (20,389) (20,084)
Total stockholders’ equity 2,886,616 2,787,094
Non-controlling interest 97,141 100,029
Total equity 2,983,757 2,887,123
TOTAL LIABILITIES AND TOTAL EQUITY $ 9,322,294 $ 9,131,896


(unaudited)	As of
	June 30, 2023			December 31, 2022
	(in thousands)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	133,300		$	310,020
Accrued liabilities		217,259			243,457
Derivative liabilities, current		322			6,600
Regulatory liabilities, current		101,979			46,013
Notes payable		-			535,600
Current maturities of long-term debt		525,000			525,000
Total current liabilities		977,860			1,666,690

Long-term debt, net of current maturities		3,955,745			3,607,340

Deferred credits and other liabilities:
Deferred income tax liabilities, net		528,627			508,941
Regulatory liabilities, non-current		469,509			472,560
Benefit plan liabilities		118,841			116,742
Other deferred credits and other liabilities		155,746			156,062
Total deferred credits and other liabilities		1,272,723			1,254,305

Commitments, contingencies and guarantees (Note 3)

Equity:
Stockholder's equity -
Common stock $1 par value; 100,000,000 shares authorized; issued 67,115,403 and 66,140,396 shares, respectively		67,115			66,140
Additional paid-in capital		1,941,234			1,882,653
Retained earnings		1,118,145			1,064,122
Treasury stock, at cost - 48,623 and 36,726 shares, respectively		(3,167	)		(2,435	)
Accumulated other comprehensive income (loss)		(13,312	)		(15,567	)
Total stockholders' equity		3,110,015			2,994,913
Non-controlling interest		92,752			94,982
Total equity		3,202,767			3,089,895

TOTAL LIABILITIES AND TOTAL EQUITY	$	9,409,095		$	9,618,230

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

Table of Contents

BLACK HILLS CORPORATION

~~CONDENSED~~

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) Nine Months Ended September 30,
2022 2021
Operating activities: (in thousands)
Net income $ 194,704 $ 176,936
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization 188,610 174,871
Deferred financing cost amortization 7,430 3,892
Stock compensation 6,779 7,245
Deferred income taxes 16,062 5,844
Employee benefit plans 2,677 6,779
Other adjustments, net (10,243) 2,708
Changes in certain operating assets and liabilities:
Materials, supplies and fuel (88,405) (29,948)
Accounts receivable and other current assets 64,280 97,348
Accounts payable and other current liabilities 5,963 (20,094)
Regulatory assets 118,330 (559,389)
Regulatory liabilities — (9,533)
Other operating activities, net (11,900) (1,419)
Net cash provided by (used in) operating activities 494,287 (144,760)
Investing activities:
Property, plant and equipment additions (466,302) (497,849)
Other investing activities (19) 13,743
Net cash (used in) investing activities (466,321) (484,106)
Financing activities:
Dividends paid on common stock (115,850) (106,957)
Common stock issued 20,027 62,977
Term loan - borrowings — 800,000
Term loan - repayments — (800,000)
Net borrowings (payments) of Revolving Credit Facility and CP Program 81,170 98,485
Long-term debt - issuances — 600,000
Long-term debt - repayments — (8,436)
Distributions to non-controlling interest (11,678) (10,230)
Other financing activities 1,647 (2,778)
Net cash provided by (used in) financing activities (24,684) 633,061
Net change in cash, restricted cash and cash equivalents 3,282 4,195
Cash, restricted cash and cash equivalents at beginning of period 13,810 10,739
Cash, restricted cash and cash equivalents at end of period $ 17,092 $ 14,934
Supplemental cash flow information:
Cash (paid) refunded during the period:
Interest, net of amounts capitalized $ (98,227) $ (93,325)
Income taxes 746 1,486
Non-cash investing and financing activities:
Accrued property, plant and equipment purchases at September 30 42,687 55,619


(unaudited)	Six Months Ended June 30,
	2023			2022
Operating activities:	(in thousands)
Net income	$	143,924		$	156,870
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		126,357			124,591
Deferred financing cost amortization		4,853			4,953
Stock compensation		4,311			3,834
Deferred income taxes		9,203			13,860
Employee benefit plans		5,898			1,383
Other adjustments, net		(6,754	)		(9,489	)
Changes in certain operating assets and liabilities:
Materials, supplies and fuel		73,022			(6,993	)
Accounts receivable and other current assets		266,820			55,641
Accounts payable and other current liabilities		(201,389	)		(24,130	)
Regulatory assets		186,699			128,315
Other operating activities, net		(7,873	)		(6,805	)
Net cash provided by operating activities		605,071			442,030

Investing activities:
Property, plant and equipment additions		(261,739	)		(293,803	)
Other investing activities		16,367			2,418
Net cash (used in) investing activities		(245,372	)		(291,385	)

Financing activities:
Dividends paid on common stock		(83,114	)		(77,136	)
Common stock issued		54,689			20,095
Net borrowings (payments) of Revolving Credit Facility and CP Program		(535,600	)		(85,130	)
Long-term debt - issuance		350,000			-
Distributions to non-controlling interests		(9,017	)		(8,604	)
Other financing activities		(5,095	)		1,682
Net cash (used in) financing activities		(228,137	)		(149,093	)

Net change in cash, restricted cash and cash equivalents		131,562			1,552

Cash, restricted cash and cash equivalents beginning of period		26,985			13,810
Cash, restricted cash and cash equivalents end of period	$	158,547		$	15,362

Supplemental cash flow information:
Cash (paid) refunded during the period:
Interest (net of amounts capitalized)	$	(75,507	)	$	(72,791	)
Income taxes		34			752
Non-cash investing and financing activities:
Accrued property, plant and equipment purchases at June 30,		50,081			49,229

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

Table of Contents

BLACK HILLS CORPORATION

~~CONDENSED~~

CONSOLIDATED STATEMENTS OF EQUITY

(unaudited) Common Stock Treasury Stock
(in thousands except share amounts) Shares Value Shares Value Additional Paid in Capital Retained Earnings AOCI Non-controlling Interest Total
December 31, 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
Net income — — — — — 34,973 — 2,861 37,834
Other comprehensive income, net of tax — — — — — — 2,427 — 2,427
Dividends on common stock ($0.595 per share) — — — — — (38,714) — — (38,714)
Share-based compensation 27 — 2,517 (173) 2,724 — — — 2,551
Issuance costs — — — — (68) — — — (68)
Distributions to non-controlling interest — — — — — — — (3,074) (3,074)
September 30, 2022 65,105,205 $ 65,105 26,208 $ (1,715) $ 1,811,093 $ 1,032,522 $ (20,389) $ 97,141 $ 2,983,757


(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, 2022		66,140,396	$	66,140		36,726	$	(2,435	)	$	1,882,653		$	1,064,122		$	(15,567	)	$	94,982		$	3,089,895
Net income		-		-		-		-			-			114,084			-			3,296			117,380
Other comprehensive income, net of tax		-		-		-		-			-			-			1,220			-			1,220
Dividends on common stock ($0.625 per share)		-		-		-		-			-			(41,362	)		-			-			(41,362	)
Share-based compensation		84,735		85		4,388		(262	)		1,886			-			-			-			1,709
Issuance of common stock		445,578		446		-		-			27,273			-			-			-			27,719
Issuance costs		-		-		-		-			(336	)		-			-			-			(336	)
Distributions to non-controlling interest		-		-		-		-			-			-			-			(4,494	)		(4,494	)
March 31, 2023		66,670,709	$	66,671		41,114	$	(2,697	)	$	1,911,476		$	1,136,844		$	(14,347	)	$	93,784		$	3,191,731
Net income		-		-		-		-			-			23,053			-			3,491			26,544
Other comprehensive income, net of tax		-		-		-		-			-			-			1,035			-			1,035
Dividends on common stock ($0.625 per share)		-		-		-		-			-			(41,752	)		-			-			(41,752	)
Share-based compensation		8,492		8		7,509		(470	)		2,888			-			-			-			2,426
Issuance of common stock		436,202		436		-		-			27,274			-			-			-			27,710
Issuance costs		-		-		-		-			(404	)		-			-			-			(404	)
Distributions to non-controlling interest		-		-		-		-			-			-			-			(4,523	)		(4,523	)
June 30, 2023		67,115,403	$	67,115		48,623	$	(3,167	)	$	1,941,234		$	1,118,145		$	(13,312	)	$	92,752		$	3,202,767


(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 income, 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

Table of Contents

(unaudited) Common Stock Treasury Stock
(in thousands except share amounts) Shares Value Shares Value Additional Paid in Capital Retained Earnings AOCI Non-controlling Interest Total
December 31, 2020 62,827,179 $ 62,827 32,492 $ (2,119) $ 1,657,285 $ 870,738 $ (27,346) $ 101,262 $ 2,662,647
Net income — — — — — 96,316 — 4,171 100,487
Other comprehensive income, net of tax — — — — — — 1,018 — 1,018
Dividends on common stock ($0.565 per share) — — — — — (35,514) — — (35,514)
Share-based compensation 82,794 83 7,448 (445) 1,672 — — — 1,310
Other — — — — — (2) — — (2)
Distributions to non-controlling interest — — — — — — — (4,644) (4,644)
March 31, 2021 62,909,973 $ 62,910 39,940 $ (2,564) $ 1,658,957 $ 931,538 $ (26,328) $ 100,789 $ 2,725,302
Net income — — — — — 25,161 — 3,126 28,287
Other comprehensive income, net of tax — — — — — — 1,882 — 1,882
Dividends on common stock ($0.565 per share) — — — — — (35,578) — — (35,578)
Share-based compensation 20,905 21 6,588 (424) 3,698 — — — 3,295
Issuance of common stock 596,035 596 — — 39,636 — — — 40,232
Issuance costs — — — — (466) — — — (466)
Other — — — — — 1 — — 1
Distributions to non-controlling interest — — — — — — — (4,061) (4,061)
June 30, 2021 63,526,913 $ 63,527 46,528 $ (2,988) $ 1,701,825 $ 921,122 $ (24,446) $ 99,854 $ 2,758,894
Net income — — — — — 44,112 — 4,050 48,162
Other comprehensive income (loss), net of tax — — — — — — 5,277 — 5,277
Dividends on common stock ($0.565 per share) — — — — — (35,865) — — (35,865)
Share-based compensation 17 — (2,643) 169 1,849 — — — 2,018
Issuance of common stock 338,221 338 — — 22,834 — — — 23,172
Issuance costs — — — — (231) — — — (231)
Distributions to non-controlling interest — — — — — — — (1,525) (1,525)
September 30, 2021 63,865,151 $ 63,865 43,885 $ (2,819) $ 1,726,277 $ 929,369 $ (19,169) $ 102,379 $ 2,799,902

~~Table of Contents~~

BLACK HILLS CORPORATION

Condensed Notes to ~~Condensed~~ Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s ~~2021~~2022 Annual Report on Form 10-K)

(1)

~~(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 ~~GAAP~~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~~2022 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 ~~September~~June 30, ~~2022,~~2023, December 31, ~~2021~~2022 and ~~September~~June 30, ~~2021~~2022 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.

~~Table of Contents~~(2)

~~(2)~~ Regulatory Matters

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


	As of			As of
	June 30, 2023			December 31, 2022
Regulatory assets
Winter Storm Uri	$	233,299		$	347,980
Deferred energy and fuel cost adjustments		68,708			72,580
Deferred gas cost adjustments		8,777			12,147
Gas price derivatives		-			8,793
Deferred taxes on AFUDC		7,305			7,333
Employee benefit plans and related deferred taxes		88,203			89,259
Environmental		1,346			1,343
Loss on reacquired debt		18,315			19,213
Deferred taxes on flow through accounting		74,165			69,529
Decommissioning costs		2,406			3,472
Other regulatory assets		21,147			21,332
Total regulatory assets		523,671			652,981
Less current regulatory assets		(198,443	)		(260,312	)
Regulatory assets, non-current	$	325,228		$	392,669

Regulatory liabilities
Deferred energy and gas costs	$	99,649		$	41,722
Employee benefit plan costs and related deferred taxes		33,065			34,258
Cost of removal		178,668			175,614
Excess deferred income taxes		250,728			254,833
Other regulatory liabilities		9,378			12,146
Total regulatory liabilities		571,488			518,573
Less current regulatory liabilities		(101,979	)		(46,013	)
Regulatory liabilities, non-current	$	469,509		$	472,560

As of As of
September 30, 2022 December 31, 2021
Regulatory assets
Winter Storm Uri (a)
$ 392,994 $ 509,025
Deferred energy and fuel cost adjustments (b)
74,998 59,973
Deferred gas cost adjustments (b)
18,764 9,488
Gas price derivatives (b)
10,776 2,584
Deferred taxes on AFUDC (b)
7,407 7,457
Employee benefit plans and related deferred taxes (c)
86,335 88,923
Environmental (b)
1,346 1,385
Loss on reacquired debt (b)
19,663 21,011
Deferred taxes on flow through accounting (b)
66,039 63,243
Decommissioning costs (b)
4,094 5,961
Other regulatory assets (b)
23,790 27,549
Total regulatory assets 706,206 796,599
Less current regulatory assets (290,087) (270,290)
Regulatory assets, non-current $ 416,119 $ 526,309
Regulatory liabilities
Deferred energy and gas costs (b)
$ 6,283 $ 6,113
Employee benefit plan costs and related deferred taxes (c)
31,168 32,241
Cost of removal (b)
174,312 179,976
Excess deferred income taxes (c)
257,282 264,042
Other regulatory liabilities (c)
25,715 20,579
Total regulatory liabilities 494,760 502,951
Less current regulatory liabilities (24,797) (17,574)
Regulatory liabilities, non-current $ 469,963 $ 485,377

~~__________~~

~~(a) Timing of Winter Storm Uri incremental cost recovery and associated carrying costs vary by jurisdiction. 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~~2022 Annual Report on Form 10-K.

~~Arkansas~~

Table of Contents

Colorado Gas

RMNG Rate Review

On ~~December 10, 2021, Arkansas Gas filed~~July 12, 2023, the CPUC approved a settlement agreement for RMNG's rate review ~~with the APSC seeking recovery~~filed on October 7, 2022. The agreement is expected to generate $8.2 million in new annual revenue and establishes a weighted average cost of ~~significant infrastructure investments in its 7,200-mile natural gas pipeline system. On October 10, 2022, the APSC approved a partial settlement agreement~~capital of 6.93% with ~~all intervening parties for a general rate increase and authorized~~ a capital structure that reflects an equity range of ~~45% equity and 55%~~50% to 52%, a debt range of 50% to 48% and a return on equity range of ~~9.6%~~9.5% to 9.7%. The ~~APSC’s decision~~settlement also shifts ~~approximately $10~~$8.3 million of ~~rider revenue~~SSIR revenues to base rates and ~~is expected to generate $8.8 million of new annual revenue. The APSC also approved a new comprehensive safety and integrity rider which replaces three former riders.~~terminates the SSIR. New rates were effective ~~on October 21, 2022.~~

July 15, 2023.

Colorado Gas Rate Review

~~Table of Contents~~

~~RMNG~~

On ~~October 7, 2022, RMNG~~May 9, 2023, Colorado Gas filed a rate review with the CPUC seeking recovery of significant infrastructure investments in its ~~600-mile~~10,000-mile natural gas pipeline system. The rate review requests ~~$12.3~~$27 million in new annual revenue ~~based on a future test year~~ with a capital structure of ~~52%~~51% equity and ~~48%~~49% debt and a return on equity of ~~12.3%~~10.49%. ~~The rate review also requests a $7.7 million shift of SSIR revenues to base rates.~~ The request seeks to finalize rates in the ~~third~~first quarter of ~~2023.~~

2024.

~~Winter Storm Uri~~

~~In February 2021, Winter Storm Uri caused~~

Wyoming Gas

On May 18, 2023, Wyoming Gas filed a ~~substantial increase~~rate review with the WPSC seeking recovery of significant infrastructure investments in ~~heating and energy demand and contributed to unforeseeable and unprecedented market prices for~~its 6,400-mile natural gas pipeline system. The rate review requests $19 million in new annual revenue with a capital structure of 52% equity and ~~electricity. As~~48% debt and a ~~result, 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~~return on equity of these incremental costs through separate tracking mechanisms over a weighted-average recovery period of 3.5 years. In these applications, we sought approval to recover carrying costs. We have received final commission approval for all of our Winter Storm Uri cost recovery applications, which will allow full recovery of our incremental fuel, purchased power and natural gas costs.

10.49

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. On October 20, 2022,%. Additionally, Wyoming Gas ~~received approval from~~is seeking renewal of the ~~WPSC for its Winter Storm Uri cost recovery application.~~Wyoming Integrity Rider. The ~~WPSC had previously approved interim cost recovery effective in September 2021.~~

~~For three and nine months ended September 30, 2022 and 2021, $3.7 million, $18 million, $1.8 million and $1.8 million, respectively, of carrying costs were accrued and recorded~~request seeks to ~~a regulatory asset. The carrying costs accrued during the nine months ended September 30, 2022 included a one-time, $10 million true-up recorded~~finalize rates in the ~~second~~first quarter ~~to reflect Commission authorized rates.~~

~~For the nine months ended September 30, 2022, our Utilities collected $125 million~~ of Winter Storm Uri incremental costs and carrying costs from customers. As of September 30, 2022, we estimate that our remaining Winter Storm Uri regulatory asset has a weighted-average recovery period of 2.8 years.

2024.

~~TCJA~~

As part of Kansas Gas’ 2021 rate review settlement agreement, Kansas Gas will annually deliver $3.0 million of TCJA and state tax reform benefits to customers for three years starting in 2022 (approximately $9.1 million of total benefits expected to be delivered). For the three and nine months ended September 30, 2022, Kansas Gas delivered TCJA and state tax reform bill credits to customers of $0.6 million and $2.1 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 nine months ended September 30, 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~~1,330-mile electric distribution and ~~59-mile~~59-mile electric transmission systems. On January 26, 2023, the WPSC approved a settlement agreement with intervening parties for a general rate increase. The ~~rate review requests $15~~settlement is expected to generate $8.7 million in new annual revenue with a capital structure of ~~54%~~52% equity and ~~46%~~48% debt and a return on equity of ~~10.3%~~9.75%. New rates were effective March 1, 2023. The ~~request seeks~~agreement also includes approval of a new rider that will be filed annually to ~~finalize rates in the first quarter of 2023.~~recover transmission investments and expenses.

~~Table of Contents~~(3)

~~(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~~2022 Annual Report on Form ~~10-K except for those described below.~~10-K.

~~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. The new agreement 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. The new agreement 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 have appealed the verdict. At this time, we believe that the liability related to this matter, if any, is not reasonably estimable.

~~Power Purchase Agreements~~

On June 23, 2022, Wyoming Electric entered into a PPA with Roundhouse Renewable Energy II, LLC (Roundhouse Renewable Energy) to purchase up to 106 MW of renewable energy upon construction of a new wind facility, to be owned by Roundhouse Renewable Energy, which is expected to be completed by the end of 2023. The agreement will expire 20 years after construction completion. The wind energy from this PPA will be used to serve our expanding partnerships with industrial customers in Cheyenne, Wyoming.

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. On May 27, 2022, Colorado Electric filed its 2030 Ready Plan with the CPUC. A CPUC decision is expected in March 2023, after which time, Colorado Electric will seek new requests for proposals for renewable energy resources.

~~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.

~~Table of Contents~~(4)

Revenue

~~(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 ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 and ~~2021.~~2022. Sales tax and other similar taxes are excluded from revenues.

Three Months Ended September 30, 2022 Electric Utilities Gas Utilities Inter-company Revenues Total
Customer types: (in thousands)
Retail $ 211,489 $ 157,203 $ — $ 368,692
Transportation — 41,006 (99) 40,907
Wholesale 13,667 — — 13,667
Market - off-system sales 16,770 186 — 16,956
Transmission/Other 15,919 8,875 (4,148) 20,646
Revenue from contracts with customers $ 257,845 $ 207,270 $ (4,247) $ 460,868
Other revenues 824 1,018 (98) 1,744
Total revenues $ 258,669 $ 208,288 $ (4,345) $ 462,612
Timing of revenue recognition:
Services transferred at a point in time $ 7,928 $ — $ — $ 7,928
Services transferred over time 249,917 207,270 (4,247) 452,940
Revenue from contracts with customers $ 257,845 $ 207,270 $ (4,247) $ 460,868


Three Months Ended June 30, 2023	Electric Utilities		Gas Utilities		Inter-segment Revenues			Total
Customer types:
Retail	$	156,372	$	174,781	$	-		$	331,153
Transportation		-		35,913		(115	)		35,798
Wholesale		5,739		-		-			5,739
Market - off-system sales		8,364		43		-			8,407
Transmission/Other		19,231		9,203		(4,395	)		24,039
Revenue from contracts with customers	$	189,706	$	219,940	$	(4,510	)	$	405,136
Other revenues		3,367		2,780		-			6,147
Total revenues	$	193,073	$	222,720	$	(4,510	)	$	411,283

Timing of revenue recognition:
Services transferred at a point in time	$	7,844	$	-	$	-		$	7,844
Services transferred over time		181,862		219,940		(4,510	)		397,292
Revenue from contracts with customers	$	189,706	$	219,940	$	(4,510	)	$	405,136

Three Months Ended September 30, 2021 Electric Utilities Gas Utilities Inter-company Revenues Total
Customer Types: (in thousands)
Retail $ 185,892 $ 115,908 $ — $ 301,800
Transportation — 37,651 (110) 37,541
Wholesale 7,247 — — 7,247
Market - off-system sales 13,511 75 — 13,586
Transmission/Other 12,904 9,863 (4,288) 18,479
Revenue from contracts with customers $ 219,554 $ 163,497 $ (4,398) $ 378,653
Other revenues 850 1,186 (99) 1,937
Total Revenues $ 220,404 $ 164,683 $ (4,497) $ 380,590
Timing of Revenue Recognition:
Services transferred at a point in time $ 6,968 $ — $ — $ 6,968
Services transferred over time 212,586 163,497 (4,398) 371,685
Revenue from contracts with customers $ 219,554 $ 163,497 $ (4,398) $ 378,653

Table of Contents


Three Months Ended June 30, 2022	Electric Utilities		Gas Utilities		Inter-segment Revenues			Total
Customer types:
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


Six Months Ended June 30, 2023	Electric Utilities		Gas Utilities		Inter-segment Revenues			Total
Customer types:	(in thousands)
Retail	$	331,275	$	810,326	$	-		$	1,141,601
Transportation		-		88,756		(230	)		88,526
Wholesale		15,137		-		-			15,137
Market - off-system sales		24,488		324		-			24,812
Transmission/Other		36,635		19,226		(8,746	)		47,115
Revenue from contracts with customers	$	407,535	$	918,632	$	(8,976	)	$	1,317,191
Other revenues		4,247		11,004		-			15,251
Total revenues	$	411,782	$	929,636	$	(8,976	)	$	1,332,442

Timing of revenue recognition:
Services transferred at a point in time	$	16,501	$	-	$	-		$	16,501
Services transferred over time		391,034		918,632		(8,976	)		1,300,690
Revenue from contracts with customers	$	407,535	$	918,632	$	(8,976	)	$	1,317,191


Six Months Ended June 30, 2022	Electric Utilities		Gas Utilities		Inter-segment 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

Nine Months Ended September 30, 2022 Electric Utilities Gas Utilities Inter-company Revenues Total
Customer types: (in thousands)
Retail $ 553,327 $ 947,290 $ — $ 1,500,617
Transportation — 125,196 (298) 124,898
Wholesale 32,370 — — 32,370
Market - off-system sales 32,590 602 — 33,192
Transmission/Other 46,535 27,794 (12,445) 61,884
Revenue from contracts with customers $ 664,822 $ 1,100,882 $ (12,743) $ 1,752,961
Other revenues 4,764 2,967 (315) 7,416
Total revenues $ 669,586 $ 1,103,849 $ (13,058) $ 1,760,377
Timing of revenue recognition:
Services transferred at a point in time $ 21,712 $ — $ — $ 21,712
Services transferred over time 643,110 1,100,882 (12,743) 1,731,249
Revenue from contracts with customers $ 664,822 $ 1,100,882 $ (12,743) $ 1,752,961

Nine Months Ended September 30, 2021 Electric Utilities Gas Utilities Inter-company Revenues Total
Customer Types: (in thousands)
Retail $ 554,143 $ 601,358 $ — $ 1,155,501
Transportation — 117,251 (329) 116,922
Wholesale 24,261 — — 24,261
Market - off-system sales 25,549 235 — 25,784
Transmission/Other 38,315 29,378 (12,868) 54,825
Revenue from contracts with customers $ 642,268 $ 748,222 $ (13,197) $ 1,377,293
Other revenues 4,556 5,030 (285) 9,301
Total Revenues $ 646,824 $ 753,252 $ (13,482) $ 1,386,594
Timing of Revenue Recognition:
Services transferred at a point in time $ 20,658 $ — $ — $ 20,658
Services transferred over time 621,610 748,222 (13,197) 1,356,635
Revenue from contracts with customers $ 642,268 $ 748,222 $ (13,197) $ 1,377,293

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(5)

Financing

~~(5) Financing~~

Shelf Registration Statement

We maintain an effective shelf registration statement with the SEC under which we may issue, from time to time, an unspecified amount of senior debt securities, subordinated debt securities, common stock, preferred stock, warrants and other securities. In anticipation of the approaching expiration of our previous shelf registration statement on Form S-3 originally filed on August 4, 2020 (Registration No. 333-240320), we filed a new shelf registration statement on Form S-3 on June 16, 2023 (Registration No. 333-272739).

Short-term Debt

Revolving Credit Facility and CP Program

On May 9, 2023, we amended and restated our corporate Revolving Credit Facility, which replaced LIBOR as a benchmark interest rate with the SOFR. The adoption of SOFR as a benchmark interest rate was in advance of the scheduled elimination of LIBOR as a benchmark interest rate on June 30, 2023. No other significant terms or conditions, including borrowing capacity, credit spreads or financial covenants were modified under these amendments and restatements.

WeOur Revolving Credit Facility and CP Program, which are classified as Notes payable on the Consolidated Balance Sheets, had the following ~~Notes payable~~borrowings, outstanding letters of credit, and available capacity (dollars in ~~the accompanying Condensed Consolidated Balance Sheets (in~~ thousands) as of:


	June 30, 2023		December 31, 2022
Amount outstanding	$	—	$	535,600
Letters of credit (a)	$	2,751	$	24,626
Available capacity	$	747,249	$	189,774
Weighted average interest rates	N/A			4.88	%

(a)

September 30, 2022 December 31, 2021
Balance Outstanding
Letters of Credit (a)
Balance Outstanding
Letters of Credit (a)
Revolving Credit Facility $ — $ 20,193 $ — $ 27,209
CP Program 501,350 — 420,180 —
Total Notes payable $ 501,350 $ 20,193 $ 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.~~

Facility
.

~~Revolving Credit Facility and CP Program~~

~~Our net short-term borrowings related to our~~

Revolving Credit Facility and CP Program ~~during~~borrowing activity was as follows (dollars in thousands):


	Six Months Ended June 30,
	2023			2022
Maximum amount outstanding (based on daily outstanding balances)	$	548,700		$	429,000
Average amount outstanding (based on daily outstanding balances)	$	164,719		$	326,172
Weighted average interest rates		4.91	%		0.82	%

Long-term Debt

On March 7, 2023, we completed a public debt offering of $350 million, 5.95% five year senior unsecured notes due March 15, 2028. The proceeds from the ~~nine months ended September 30, 2022~~offering, which were ~~$81 million. The weighted average interest rate on short-term borrowings related~~net of $4.2 million of deferred financing costs, were used to repay notes outstanding under our CP Program and for other general corporate purposes.

Debt Covenants

Revolving Credit Facility

We were in compliance with all of our Revolving Credit Facility ~~and CP Program at September~~covenants as of June 30, ~~2022 was 3.35%.~~

~~Debt Covenants~~

~~Revolving Credit Facility~~

~~Under our Revolving Credit Facility, we~~2023. 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~~this covenant would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding.

As of June 30, 2023, our Consolidated Indebtedness to Capitalization Ratio was
0.59

~~We were~~ to 1.00.

Wyoming Electric

Wyoming Electric was in compliance with ~~our~~all covenants ~~at September 30, 2022 as shown below:~~

As of September 30, 2022 Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio 61.7% Less than 65%

~~Wyoming Electric~~

~~Covenants~~ within ~~Wyoming Electric's~~its financing agreements ~~require~~as of June 30, 2023. Wyoming Electric is required to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of ~~September~~June 30, ~~2022,~~2023, Wyoming ~~Electric’s~~Electric's debt to capitalization ratio was ~~49%, which was in compliance with these financial covenants.~~

0.52

to 1.00.

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Equity

At-the-Market Equity Offering Program

~~During the three months ended September 30, 2022,~~

As previously disclosed, on August 4, 2020, we ~~did not issue any~~entered into an Amended and Restated Equity Distribution Sales Agreement ("Previous Sales Agreement") to sell shares of common stock ~~under~~up to an aggregate of $400 million, from time to time, through our ATM program utilizing our shelf registration statement. In conjunction with the ~~ATM. During~~new shelf registration statement filing discussed above, we entered into a new Equity Distribution Sales Agreement ("Sales Agreement") on June 16, 2023. We also terminated the ~~nine months ended September 30, 2022, we issued a total of 0.3 million~~Previous Sales Agreement on June 16, 2023. The Sales Agreement is similar to the Previous Sales Agreement and allows us to sell shares of common stock up to an aggregate of $400 million through our ATM program.

ATM activity was as follows (net proceeds and issuance costs in millions):


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
August 4, 2020 ATM Program
Proceeds, (net of issuance costs of $(0.2), $(0.2), $(0.5) and $(0.2), respectively)	$	21.0	$	16.4	$	48.5	$	20.2
Number of shares issued		329,647		216,885		775,225		272,592

June 16, 2023 ATM Program
Proceeds, (net of issuance costs of $(0.1), $0, $(0.1) and $0, respectively)	$	6.4	$	-	$	6.4	$	-
Number of shares issued		106,555		-		106,555		-

Total activity under both ATM Programs
Proceeds, (net of issuance costs of $(0.3), $(0.2), $(0.6) and $(0.2), respectively)	$	27.4	$	16.4	$	54.9	$	20.2
Number of shares issued		436,202		216,885		881,780		272,592
Average price per share	$	63.53	$	76.39	$	62.86	$	74.84

As of June 30, 2023, there were 46,696 shares issued under the June 16, 2023 ATM ~~for proceeds~~Program, but not settled.

Shareholder Dividend Reinvestment and Stock Purchase Plan

Effective as of ~~$20 million, net~~July 7, 2023, we terminated our DRSPP. On July 10, 2023, we filed a post-effective amendment to amend the Registration Statement on Form S-3 (File No. 333-240319) filed with the SEC on August 4, 2020. The filing of ~~$0.2 million in issuance costs. During the three months ended September 30, 2021, we issued a total of 0.3 million~~this post-effective amendment de-registered all shares of common stock that were issuable under the ~~ATM for proceeds~~DRSPP but not sold as of ~~$23 million, net~~July 7, 2023. With the termination of ~~$0.2 million in issuance costs. During~~ the ~~nine months ended September 30, 2021, we issued~~DRSPP, a ~~total of 0.9 million shares of common~~direct stock ~~under the ATM for proceeds of $63 million, net of $0.6 million in issuance costs.~~purchase plan is being offered which will allow shareholders to continue making share transactions. This plan is sponsored and administered solely by EQ Shareowner Services, our transfer agent.

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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,
	2023		2022		2023		2022
Net income available for common stock	$	23,053	$	33,415	$	137,137	$	150,941

Weighted average shares - basic		66,591		64,721		66,315		64,643
Dilutive effect of:
Equity compensation		93		162		104		179
Weighted average shares - diluted		66,684		64,883		66,419		64,822

Earnings per share of common stock:
Earnings per share, Basic	$	0.35	$	0.52	$	2.07	$	2.33
Earnings per share, Diluted	$	0.35	$	0.52	$	2.06	$	2.33

Three Months Ended September 30, Nine Months Ended September 30,
2022 2021 2022 2021
Net income available for common stock $ 34,973 $ 44,112 $ 185,914 $ 165,589
Weighted average shares - basic 64,876 63,341 64,722 62,950
Dilutive effect of:
Equity compensation 185 95 188 96
Weighted average shares - diluted 65,061 63,436 64,910 63,046
Earnings per share of common stock:
Earnings per share, Basic $ 0.54 $ 0.70 $ 2.87 $ 2.63
Earnings per share, Diluted $ 0.54 $ 0.70 $ 2.86 $ 2.63

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,
	2023		2022		2023		2022
Equity compensation		76		-		47		-
Restricted stock		1		-		-		1
Anti-dilutive shares		77		-		47		1

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(7)

Three Months Ended September 30, Nine Months Ended September 30,
2022 2021 2022 2021
Equity compensation — 9 — 12
Restricted stock — — — 1
Anti-dilutive shares — 9 — 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.

Valuation methodologies for our derivatives are detailed within Note 1 of the Notes to the Consolidated Financial Statements in our 2022 Annual Report on Form 10-K.

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, pandemics, market speculation, recession, 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.~~

volatility.

~~Table of Contents~~

Credit Risk

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

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

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

Derivatives and Hedging Activity

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

The operations of our Utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ 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~~enter 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.

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To support our Choice Gas Program customers, 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 2023 through October ~~2022 through December 2024.~~2025. 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.

~~Table of Contents~~

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, 2023				December 31, 2022
	Notional Amounts (MMBtus)		Maximum Term (months) (a)		Notional Amounts (MMBtus)		Maximum Term (months) (a)
Natural gas futures purchased		80,000		8		630,000		3
Natural gas options purchased, net		120,000		9		1,790,000		3
Natural gas basis swaps purchased		80,000		8		900,000		3
Natural gas over-the-counter swaps, net (b)		6,580,000		27		4,460,000		24
Natural gas physical contracts, net (c)		1,813,165		9		17,864,412		12

(a)

September 30, 2022 December 31, 2021
Notional
Amounts (MMBtus)
Maximum
Term
(months) (a)
Notional
Amounts (MMBtus)
Maximum
Term
(months) (a)
Natural gas futures purchased 1,780,000 6 590,000 3
Natural gas options purchased, net 5,500,000 6 3,100,000 3
Natural gas basis swaps purchased 1,530,000 6 870,000 3
Natural gas over-the-counter swaps, net (b)
6,050,000 27 4,570,000 34
Natural gas physical contracts, net (c)
29,017,775 15 16,416,677 24

~~__________~~

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

(b)

As of ~~September~~June 30, ~~2022, 2,292,300~~2023, 3,151,300 MMBtus of natural gas over-the-counter swaps purchases were designated as cash flow hedges.

(c)

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

We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At ~~September~~June 30, ~~2022,~~2023, the Company posted ~~$4.6~~$0.6 million related to such provisions, which is included in Other current assets on the ~~Condensed~~ Consolidated Balance Sheets.

Derivatives by Balance Sheet Classification

As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis aside from the netting of asset and liability positions. Netting of positions is permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements 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 September 30, 2022 December 31, 2021
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivatives Derivative assets, current $ 21 $ 2,017
Noncurrent commodity derivatives Other assets, non-current 383 18
Liability derivative instruments:
Current commodity derivatives Derivative liabilities, current (1,211) —
Total derivatives designated as hedges $ (807) $ 2,035
Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivatives Derivative assets, current $ 3,847 $ 2,356
Noncurrent commodity derivatives Other assets, non-current 986 804
Liability derivative instruments:
Current commodity derivatives Derivative liabilities, current (4,358) (1,439)
Noncurrent commodity derivatives Other deferred credits and other liabilities (23) (20)
Total derivatives not designated as hedges $ 452 $ 1,701


	Balance Sheet Location	June 30, 2023			December 31, 2022
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets, current	$	408		$	118
Noncurrent commodity derivatives	Other assets, non-current		-			198
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current		-			(1,703	)
Noncurrent commodity derivatives	Other assets, non-current		(64	)		-
Total derivatives designated as hedges		$	344		$	(1,387	)

Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets, current	$	(105	)	$	464
Noncurrent commodity derivatives	Other assets, non-current		-			337
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current		(322	)		(4,897	)
Noncurrent commodity derivatives	Other deferred credits and other liabilities		(84	)		(18	)
Total derivatives not designated as hedges		$	(511	)	$	(4,114	)

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Derivatives Designated as Hedge Instruments

The impacts of cash flow hedges on our ~~Condensed~~ Consolidated Statements of Comprehensive Income and ~~Condensed~~ Consolidated Statements of Income are presented below for the three and ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 and ~~2021.~~2022. 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,
	2023		2022				2023			2022
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		636		(4,371	)	Fuel, purchased power and cost of natural gas sold		(489	)		1,323
Total	$	1,349	$	(3,658	)		$	(1,202	)	$	610


	Six Months Ended June 30,						Six Months Ended June 30,
	2023		2022				2023			2022
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		1,463		(5,238	)	Fuel, purchased power and cost of natural gas sold		(2,439	)		3,577
Total	$	2,889	$	(3,812	)		$	(3,865	)	$	2,151

Three Months Ended September 30, Three Months Ended September 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 $ 712 $ 712 Interest expense $ (712) $ (712)
Commodity derivatives 2,292 5,536 Fuel, purchased power and cost of natural gas sold 43 331
Total $ 3,004 $ 6,248 $ (669) $ (381)

Nine Months Ended September 30, Nine Months Ended September 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 $ 2,138 $ 2,138 Interest expense $ (2,138) $ (2,138)
Commodity derivatives (2,946) 6,896 Fuel, purchased power and cost of natural gas sold 3,620 356
Total $ (808) $ 9,034 $ 1,482 $ (1,782)

As of ~~September~~June 30, ~~2022, $4.0~~2023, $2.9 million of net losses related to our interest rate swaps and commodity derivatives are expected to be reclassified from AOCI into earnings within the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

Derivatives Not Designated as Hedge Instruments

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our ~~Condensed~~ Consolidated Statements of Income for the three and ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 and ~~2021.~~2022. 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 September 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 $ — $ 2,494
Commodity derivatives - Natural Gas Fuel, purchased power and cost of natural gas sold 1,617 4,004
$ 1,617 $ 6,498


		Three Months Ended June 30,
		2023		2022
Derivatives Not Designated as Hedging Instruments	Location of Gain/(Loss) on Derivatives Recognized in Income	Amount of Gain/(Loss) on Derivatives Recognized in Income
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	$	394	$	(2,332	)
		$	394	$	(2,332	)


		Six Months Ended June 30,
		2023			2022
Derivatives Not Designated as Hedging Instruments	Location of Gain/(Loss) on Derivatives Recognized in Income	Amount of Gain/(Loss) on Derivatives Recognized in Income
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	$	(2,700	)	$	1,162
		$	(2,700	)	$	1,162

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Nine Months Ended September 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 $ — $ (2,628)
Commodity derivatives - Natural Gas Fuel, purchased power and cost of natural gas sold 2,779 6,186
$ 2,779 $ 3,558

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 gains included in our Regulatory liability accounts related to these financial instruments in our Gas Utilities were $0.1 million as of June 30, 2023. The net unrealized losses included in our Regulatory asset accounts related to these financial instruments ~~in our Gas Utilities~~ were ~~$11 million and $2.6~~$8.8 million as of ~~September 30, 2022 and~~ December 31, ~~2021, respectively.~~2022. For our Electric Utilities, the unrealized gains and losses arising from these derivatives are recognized in the ~~Condensed~~ Consolidated Statements of Income.

(8)

~~(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~~2022 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, 2023
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting (a)			Total
	(in thousands)
Assets:
Commodity derivatives - Gas Utilities	$	-	$	1,054	$	-	$	(751	)	$	303
Total	$	-	$	1,054	$	-	$	(751	)	$	303

Liabilities:
Commodity derivatives - Gas Utilities	$	-	$	495	$	-	$	(25	)	$	470
Total	$	-	$	495	$	-	$	(25	)	$	470

(a)

As of September 30, 2022
Level 1 Level 2 Level 3
Cash Collateral and Counterparty
Netting (a)
Total
(in thousands)
Assets:
Commodity derivatives — Gas Utilities $ — $ 11,832 $ — $ (6,594) $ 5,238
Total $ — $ 11,832 $ — $ (6,594) $ 5,238
Liabilities:
Commodity derivatives — Gas Utilities $ — $ 12,212 $ — $ (6,619) $ 5,593
Total $ — $ 12,212 $ — $ (6,619) $ 5,593
~~__________~~

~~(a)~~ As of ~~September~~June 30, ~~2022, $6.6~~2023, $0.8 million of our commodity derivative assets and ~~$6.6 million~~none of our commodity derivative liabilities, as well as related gross collateral amounts, were subject to master netting agreements.


	As of December 31, 2022
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting (a)			Total
	(in thousands)
Assets:
Commodity derivatives - Gas Utilities	$	-	$	5,407	$	-	$	(4,290	)	$	1,117
Total	$	-	$	5,407	$	-	$	(4,290	)	$	1,117

Liabilities:
Commodity derivatives - Gas Utilities	$	-	$	11,455	$	-	$	(4,837	)	$	6,618
Total	$	-	$	11,455	$	-	$	(4,837	)	$	6,618

(a)

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~~2022, $4.3 million of our commodity derivative assets and ~~$1.8~~$4.8 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~~2022 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.

~~Table of Contents~~

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, 2023				December 31, 2022
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current maturities (a)	$	4,480,745	$	4,152,130	$	4,132,340	$	3,760,848

September 30, 2022 December 31, 2021
Carrying
Amount Fair Value Carrying
Amount Fair Value
Long-term debt, including current maturities (a)
$ 4,131,033 $ 3,736,930 $ 4,126,923 $ 4,570,619

(a)

~~__________~~

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

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(9)

~~(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):


		Amount Reclassified from AOCI						Amount Reclassified from AOCI
	Location on the Consolidated Statements of Income	Three Months Ended June 30,						Six Months Ended June 30,
		2023			2022			2023			2022
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		(489	)		1,323			(2,439	)		3,577
		$	(1,202	)	$	610		$	(3,865	)	$	2,151
Income tax	Income tax expense		295			(81	)		911			(456	)
Total reclassification adjustments related to cash flow hedges, net of tax		$	(907	)	$	529		$	(2,954	)	$	1,695

Amortization of components of defined benefit plans:
Prior service cost	Operations and maintenance	$	-		$	22		$	-		$	46
Actuarial gain (loss)	Operations and maintenance		(43	)		(187	)		(87	)		(375	)
		$	(43	)	$	(165	)	$	(87	)	$	(329	)
Income tax	Income tax expense		27			60			43			99
Total reclassification adjustments related to defined benefit plans, net of tax		$	(16	)	$	(105	)	$	(44	)	$	(230	)
Total reclassifications		$	(923	)	$	424		$	(2,998	)	$	1,465

Location on the Condensed Consolidated Statements of Income Amount Reclassified from AOCI Amount Reclassified from AOCI
Three Months Ended September 30, Nine Months Ended September 30,
2022 2021 2022 2021
Gains and (losses) on cash flow hedges:
Interest rate swaps Interest expense $ (712) $ (712) $ (2,138) $ (2,138)
Commodity contracts Fuel, purchased power and cost of natural gas sold 43 331 3,620 356
(669) (381) 1,482 (1,782)
Income tax Income tax expense 124 (26) (332) 308
Total reclassification adjustments related to cash flow hedges, net of tax $ (545) $ (407) $ 1,150 $ (1,474)
Amortization of components of defined benefit plans:
Prior service cost Operations and maintenance $ 24 $ 25 $ 70 $ 74
Actuarial gain (loss) Operations and maintenance (188) (598) (563) (1,793)
(164) (573) (493) (1,719)
Income tax Income tax expense 58 133 157 492
Total reclassification adjustments related to defined benefit plans, net of tax $ (106) $ (440) $ (336) $ (1,227)
Total reclassifications $ (651) $ (847) $ 814 $ (2,701)

~~Table of Contents~~

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


	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
As of December 31, 2022	$	(8,255	)	$	(1,200	)	$	(6,112	)	$	(15,567	)
Other comprehensive income (loss)
before reclassifications		-			(743	)		-			(743	)
Amounts reclassified from AOCI		1,099			1,855			44			2,998
As of June 30, 2023	$	(7,156	)	$	(88	)	$	(6,068	)	$	(13,312	)


	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	)

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(10)

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 — 509 — 509
Amounts reclassified from AOCI 1,589 (2,739) 336 (814)
As of September 30, 2022 $ (8,795) $ (754) $ (10,840) $ (20,389)
Derivatives Designated as Cash Flow Hedges
Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total
As of December 31, 2020 $ (12,558) $ 2 $ (14,790) $ (27,346)
Other comprehensive income (loss)
before reclassifications — 5,476 — 5,476
Amounts reclassified from AOCI 1,743 (269) 1,227 2,701
As of September 30, 2021 $ (10,815) $ 5,209 $ (13,563) $ (19,169)

~~(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,	2023			2022			2023		2022			2023			2022
Service cost	$	614		$	982		$	770	$	(1,355	)	$	381		$	492
Interest cost		4,381			2,704			369		209			594			321
Expected return on plan assets		(4,672	)		(4,630	)		-		-			(55	)		(31	)
Net amortization of prior service costs		(17	)		(17	)		-		-			10			(73	)
Recognized net actuarial loss		498			1,523			8		69			(3	)		16
Net periodic expense (benefit)	$	804		$	562		$	1,147	$	(1,077	)	$	927		$	725


	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans					Non-pension Defined Benefit Postretirement Healthcare Plan
Six Months Ended June 30,	2023			2022			2023		2022			2023			2022
Service cost	$	1,228		$	1,964		$	1,684	$	(1,747	)	$	762		$	984
Interest cost		8,761			5,409			738		417			1,188			642
Expected return on plan assets		(9,344	)		(9,261	)		-		-			(111	)		(62	)
Net amortization of prior service costs		(34	)		(34	)		-		-			20			(145	)
Recognized net actuarial loss (gain)		996			3,046			16		138			(6	)		32
Net periodic expense (benefit)	$	1,607		$	1,124		$	2,438	$	(1,192	)	$	1,853		$	1,451

Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan
Three Months Ended September 30, 2022 2021 2022 2021 2022 2021
Net Service cost $ 982 $ 1,260 $ (271) $ 235 $ 492 $ 560
Interest cost 2,705 2,328 209 176 321 264
Expected return on plan assets (4,631) (5,219) — — (31) (34)
Net amortization of prior service costs (17) — — — (72) (108)
Recognized net actuarial loss 1,522 1,828 69 439 16 116
Net periodic expense (benefit) $ 561 $ 197 $ 7 $ 850 $ 726 $ 798

Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan
Nine Months Ended September 30, 2022 2021 2022 2021 2022 2021
Net Service cost $ 2,946 $ 3,779 $ (2,018) $ 1,948 $ 1,476 $ 1,678
Interest cost 8,114 6,984 626 530 963 793
Expected return on plan assets (13,892) (15,657) — — (93) (102)
Net amortization of prior service costs (51) — — — (217) (326)
Recognized net actuarial loss 4,568 5,486 207 1,316 48 350
Net periodic expense (benefit) $ 1,685 $ 592 $ (1,185) $ 3,794 $ 2,177 $ 2,393

~~Table of Contents~~

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 ~~nine~~six months of ~~2022~~2023 and anticipated contributions for ~~2022~~2023 and ~~2023~~2024 are as follows (in thousands):


	Contributions Made		Additional Contributions		Contributions
	Six Months Ended June 30, 2023		Anticipated for 2023		Anticipated for 2024
Defined Benefit Pension Plan	$	-	$	-	$	-
Non-pension Defined Benefit Postretirement Healthcare Plan	$	2,460	$	2,460	$	4,808
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans	$	1,116	$	1,116	$	2,417

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Contributions Made Additional Contributions Contributions
Nine Months Ended September 30, 2022 Anticipated for 2022 Anticipated for 2023
Defined Benefit Pension Plan $ — $ — $ —
Non-pension Defined Benefit Postretirement Healthcare Plan $ 3,828 $ 1,276 $ 5,062
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans $ 1,617 $ 539 $ 2,224

~~Funding Status of Employee Benefit Plans~~

Based on the fair value of assets and estimated discount rate used to value benefit obligations as of September 30, 2022, we estimate the unfunded status of our employee benefit plans to be approximately $32 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 had a limited impact to our unfunded status and does not require interim re-measurement of our pension plan assets or defined benefit obligations.

~~(11)~~ Income Taxes

IRS Revenue Procedure 2023-15

On April 14, 2023, the IRS released Revenue Procedure 2023-15 “Amounts paid to improve tangible property.” The Revenue Procedure provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized. We are currently assessing the Revenue Procedure to determine its impact on our tax repairs deduction.

Income Tax ~~Expense (Benefit)~~Benefit (Expense) and Effective Tax Rates

Three Months Ended ~~September~~June 30, ~~2022~~2023 Compared to the Three Months Ended ~~September~~June 30, ~~2021~~

2022

Income tax ~~expense~~benefit for the three months ended ~~September~~June 30, ~~2022~~2023 was ~~$2.1~~$6.1 million compared to ~~$5.3~~$0.7 million reported for the same period in ~~2021.~~2022. For the three months ended ~~September~~June 30, ~~2022~~2023, the effective tax rate was ~~5.2%~~(29.8)% compared to ~~9.8%~~(1.9)% for the same period in ~~2021.~~2022. The lower effective tax rate was primarily due to a $8.2 million tax ~~benefits~~benefit from ~~state~~a Nebraska income tax rate ~~changes.~~

decrease compared to a $
3.8

~~Nine~~ million benefit from a similar Nebraska tax rate decrease in 2022 and $2.3 million of lower wind PTCs driven by the March 2023 sale of Northern Iowa Windpower assets.

Six Months Ended ~~September~~June 30, ~~2022~~2023 Compared to the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2021~~

2022

Income tax ~~expense~~(expense) for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 was ~~$16~~$(8.6) million compared to ~~$6.3~~$(13.8) million reported for the same period in ~~2021.~~2022. For the ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, the effective tax rate was ~~7.6%~~5.6% compared to ~~3.5%~~8.1% for the same period in ~~2021.~~2022. The ~~higher~~lower effective tax rate was primarily due to ~~$10~~a $8.2 million tax benefit from a Nebraska income tax rate decrease compared to a $3.8 million benefit from a similar Nebraska tax rate decrease in 2022 and $3.0 million of ~~prior year tax benefits from Colorado Electric and Nebraska Gas TCJA-related bill credits to customers (which were offset~~lower wind PTCs driven by ~~reduced revenue) partially offset by $3.4 million~~the March 2023 sale of tax benefits from state rate changes and $2.0 million of increased tax benefits from federal PTCs associated with increased wind production and a current year PTC rate increase (inflation adjustment).Northern Iowa Windpower assets.

(12)

~~(12)~~ Business Segment Information

Our Chief Executive Officer, who is considered to be our CODM, reviews financial information presented on an operating segment basis for purposes of making decisions, allocating resources 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~~

We conduct our business operations through two operating segments: Electric Utilities and Gas ~~Utilities, Power Generation~~Utilities. Certain unallocated corporate expenses that support our operating segments are presented as Corporate 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.

Other. Our operating segments are equivalent to our reportable segments.

~~Table of Contents~~

Segment information was as follows (in thousands):

Total assets (net of intercompany eliminations) as of: September 30, 2022 December 31, 2021
Electric Utilities $ 3,889,596 $ 3,796,662
Gas Utilities 5,330,209 5,246,370
Corporate and Other 102,489 88,864
Total assets $ 9,322,294 $ 9,131,896


	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
Revenues:
Electric Utilities
External Customers	$	190,212		$	201,450		$	406,105		$	405,059
Inter-segment		2,861			2,929			5,677			5,858
Total Electric Utilities Revenue		193,073			204,379			411,782			410,917

Gas Utilities
External Customers		221,071			272,745			926,337			892,706
Inter-segment		1,649			1,424			3,299			2,855
Total Gas Utilities Revenue		222,720			274,169			929,636			895,561

Inter-segment eliminations		(4,510	)		(4,353	)		(8,976	)		(8,713	)

Total Revenues	$	411,283		$	474,195		$	1,332,442		$	1,297,765

Operating income (loss):
Electric Utilities	$	46,619		$	45,226		$	107,679		$	95,972
Gas Utilities		17,725			28,195			132,350			151,735
Corporate and Other		(828	)		(1,032	)		(1,630	)		(1,965	)
Total Operating Income	$	63,516		$	72,389		$	238,399		$	245,742

Three Months Ended September 30, 2022 External Operating Revenue Inter-company Operating Revenue Total Revenues
Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities $ 254,917 $ 824 $ 2,928 $ — $ 258,669
Gas Utilities 205,951 920 1,319 98 208,288
Inter-company eliminations — — (4,247) (98) (4,345)
Total $ 460,868 $ 1,744 $ — $ — $ 462,612

Three Months Ended September 30, 2021 External Operating Revenue Inter-company Operating Revenue Total Revenues
Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities $ 216,676 $ 850 $ 2,878 $ — $ 220,404
Gas Utilities 161,977 1,087 1,520 99 164,683
Inter-company eliminations — — (4,398) (99) (4,497)
Total $ 378,653 $ 1,937 $ — $ — $ 380,590

Nine Months Ended September 30, 2022 External Operating Revenue Inter-company Operating Revenue Total Revenues
Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities $ 656,036 $ 4,764 $ 8,786 $ — $ 669,586
Gas Utilities 1,096,925 2,652 3,957 315 1,103,849
Inter-company eliminations — — (12,743) (315) (13,058)
Total $ 1,752,961 $ 7,416 $ — $ — $ 1,760,377

Nine Months Ended September 30, 2021 External Operating Revenue Inter-company Operating Revenue Total Revenues
Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities $ 633,630 $ 4,556 $ 8,638 $ — $ 646,824
Gas Utilities 743,663 4,745 4,559 285 753,252
Inter-company eliminations — — (13,197) (285) (13,482)
Total $ 1,377,293 $ 9,301 $ — $ — $ 1,386,594

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Total assets (net of inter-segment eliminations) as of:	June 30, 2023		December 31, 2022
Electric Utilities	$	3,914,037	$	3,929,721
Gas Utilities		5,252,521		5,578,282
Corporate and Other		242,537		110,227
Total assets	$	9,409,095	$	9,618,230

Three Months Ended September 30, Nine Months Ended September 30,
2022 2021 2022 2021
Operating income (loss):
Electric Utilities $ 69,483 $ 72,840 $ 165,455 $ 159,645
Gas Utilities 10,583 17,257 162,318 139,336
Corporate and Other (587) (224) (2,552) (3,527)
Operating income 79,479 89,873 325,221 295,454
Interest expense, net (40,019) (38,018) (117,328) (113,820)
Other income, net 464 1,560 2,731 1,635
Income tax (expense) (2,090) (5,253) (15,920) (6,333)
Net income 37,834 48,162 194,704 176,936
Net income attributable to non-controlling interest (2,861) (4,050) (8,790) (11,347)
Net income available for common stock $ 34,973 $ 44,112 $ 185,914 $ 165,589

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~~(13)~~ Selected Balance Sheet Information

Accounts Receivable and Allowance for Credit Losses

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


	June 30, 2023			December 31, 2022
Billed Accounts Receivable	$	192,444		$	267,571
Unbilled Revenue		71,097			243,574
Less: Allowance for Credit Losses		(3,191	)		(2,953	)
Account Receivable, net	$	260,350		$	508,192

September 30, 2022 December 31, 2021
Billed Accounts Receivable $ 168,757 $ 181,027
Unbilled Revenue 82,925 142,738
Less: Allowance for Credit Losses (1,935) (2,113)
Accounts Receivable, net $ 249,747 $ 321,652

Changes to allowance for credit losses for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 and ~~2021,~~2022, 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,
2023	$	2,953	$	4,278	$	1,444	$	(5,484	)	$	3,191
2022	$	2,113	$	4,239	$	1,266	$	(4,425	)	$	3,193

Balance at Beginning of Year Additions Charged to Costs and Expenses Recoveries and Other Additions Write-offs and Other Deductions Balance at September 30,
2022 $ 2,113 $ 6,473 $ 2,117 $ (8,768) $ 1,935
2021 $ 7,003 $ 1,111 $ 2,420 $ (8,222) $ 2,312

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, 2023		December 31, 2022
Materials and supplies	$	101,854	$	99,734
Fuel - Electric Utilities		7,757		3,115
Natural gas in storage		26,923		104,572
Total materials, supplies and fuel	$	136,534	$	207,421

September 30, 2022 December 31, 2021
Materials and supplies $ 95,390 $ 86,400
Fuel - Electric Utilities 1,362 1,267
Natural gas in storage 126,410 63,312
Total materials, supplies and fuel $ 223,162 $ 150,979

~~Table of Contents~~

Accrued Liabilities

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


	June 30, 2023		December 31, 2022
Accrued employee compensation, benefits and withholdings	$	62,031	$	62,890
Accrued property taxes		40,298		52,430
Customer deposits and prepayments		42,730		47,655
Accrued interest		40,715		33,798
Other (none of which is individually significant)		31,485		46,684
Total accrued liabilities	$	217,259	$	243,457

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September 30, 2022 December 31, 2021
Accrued employee compensation, benefits and withholdings $ 64,855 $ 74,387
Accrued property taxes 46,513 50,874
Customer deposits and prepayments 44,254 48,814
Accrued interest 46,408 33,680
Other (none of which is individually significant) 48,805 37,004
Total accrued liabilities $ 250,835 $ 244,759

~~(14)~~ Subsequent Events

Except as described in Notes 2 and ~~Note 2~~5, there have been no events subsequent to ~~September~~June 30, ~~2022,~~2023, which would require recognition in the ~~condensed~~ consolidated financial statements or disclosures.

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

The following discussions should be read in conjunction with the Notes contained herein and Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in ~~our 2021~~the 2022 Form 10-K.

Executive Summary

~~Black Hills Corporation (together with its subsidiaries, referred to herein as the “Company,” “we,” “us” or “our”) is~~We are a customer-focused energy solutions provider ~~that invests in its communities’ safety, sustainability and growth~~ with a mission of Improving Life with Energy for more than 1.3 million customers and a800+ communities we serve. Our vision to be the Energy Partner of Choice~~. The Company’s core mission—~~ directs our strategy to invest in the safety, sustainability and growth of our ~~primary focus — is to provide safe, reliable and cost-effective electric and natural gas~~eight-state service ~~to 1.3 million utility customers in over 800 communities in eight states,~~territory, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and ~~Wyoming.~~Wyoming, and to meet our essential objective of providing safe, reliable and cost-effective electricity and natural gas.

~~Recent Developments~~

~~Winter Storm Uri~~

~~In February 2021, Winter Storm Uri caused~~We conduct our business operations through two operating segments: Electric Utilities and Gas Utilities. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other. We conduct our utility operations under the name Black Hills Energy predominantly in rural areas of the Rocky Mountains and Midwestern states. We consider ourself a substantial increase in heating and energy demand and contributed to unforeseeable and unprecedented market prices for natural gas and electricity. As a result, we incurred significant incremental fuel, purchased powerdomestic electric and natural gas ~~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.~~ company.

We have ~~received final commission approval~~provided energy and served customers for ~~all of~~139 years, since the 1883 gold rush days in Deadwood, South Dakota. Throughout our ~~Winter Storm Uri cost recovery applications, which will allow full recovery of our incremental fuel, purchased power and natural gas costs. See~~ ~~Note 2~~ ofhistory, the ~~Notes to Condensed Consolidated Financial Statements for further information.~~

~~Macroeconomic Trends~~

~~We are monitoring macroeconomic trends including inflationary pressures on~~common thread that unites 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.~~

~~Higher commodity energy costs continue to have an effect on customer bills. Our utilities have regulatory mechanisms that allow them to pass prudently incurred costs of energy through~~past to the present is our commitment to serve our customers and communities. By being responsive and service focused, we can help our customers and communities thrive while meeting rapidly changing customer which mitigates our exposure. Customer billing rates are adjusted periodically to reflect changes in our cost of energy. As a result of increased customer billings, we incurred higher bad debt expense.

expectations.

~~Table of Contents~~

We are proactively managing increased costs of materials and supply chain disruptions to achieve our forecasted capital investment targets. We have contracted a significant majority of the materials needed to complete 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.

Inflationary pressures and supply chain constraints have increased our operating expenses, which included higher outside services expenses (i.e. consulting and contractor rates), materials expenses and vehicle expenses driven by higher fuel prices.

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 89% of our debt at ~~September 30, 2022~~

~~is fixed rate debt. Rising discount rates and r~~

~~ecent capital markets volatility had a limited impact to our~~ Recent Developments

~~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 lower total employee costs due to workforce attrition partially offset by increased employee and contractor costs related to attraction and retention of talent.

~~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.~~

~~Sustainability Goals Updated~~

On August 31, 2022, we published our 2021 Sustainability Report highlighting our environmental, social and governance achievements and strategies to further decarbonize our Utilities’ systems. The report highlights our progress toward reducing greenhouse gas emissions intensity by one-third off a 2005 baseline. In addition, we announced a new Net Zero by 2035 target for our Gas Utilities, which doubles the previous target of a 50% reduction by 2035. Net Zero will be achieved through pipeline material and main replacements, advanced leak detection, third-party damage reduction, expanding the use of RNG and hydrogen and utilizing carbon credit offsets.

~~Environmental Matters - Good Neighbor Rule~~

In March 2022, the EPA released its Good Neighbor Rule, which contains proposed revisions to the Cross-State Air Pollution Rule (CSAPR) framework and is intended to address ozone transport for the 2015 ozone National Ambient Air Quality Standards (NAAQS). The rule focuses on reductions of NOx, precursors to ozone formation and covers 26 states, including Wyoming for the first time. The EPA proposes to retain emissions allowance trading for generating facilities. Beginning in 2023, emissions budgets would be set at the level of reductions achievable through immediately available measures such as consistently operating existing emissions controls. Starting in 2026, emissions budgets would be set at levels achievable by the installation of Selective Catalytic Reactor controls at certain generating facilities. The EPA accepted comments on the proposal through June 21, 2022. We anticipate that any costs incurred as a result of the proposed rule would be recoverable through our regulatory mechanisms.

~~Inflation Reduction Act~~

The “Inflation Reduction Act” (“IRA”), signed into law by President Biden on August 16, 2022, features $370 billion in spending and tax incentives on clean energy provisions. Most notably, the IRA includes provisions such as the extension and expansion of production and investment tax credits for wind and solar; energy storage, renewable natural gas, and carbon capture and sequestration; and the transferability of clean energy tax credits. We are currently evaluating the IRA provisions to determine impacts and opportunities.

Business Segment Recent Developments

Electric Utilities

•

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

•

On ~~October 11, 2022,~~July 31, 2023, Colorado Electric issued a request for proposals for 400 MW of new resources to be in service between 2026 and 2029 to achieve objectives in its Clean Energy Plan. In March 2023, the ~~WPSC~~CPUC approved a ~~CPCN submitted~~unanimous settlement for Colorado Electric's Clean Energy Plan filed May 25, 2022. The Clean Energy Plan supports Colorado Electric's voluntary election to reduce carbon emissions 80% from 2005 levels by ~~Wyoming Electric to construct an estimated 260-mile transmission expansion project. The transmission expansion project, known as~~2030.

~~Ready Wyoming~~, will provide customers long-term price stability and greater flexibility as power markets develop in the Western States. Construction of the project is expected to take place in multiple phases or segments from 2023 through 2025 and will interconnect South Dakota Electric’s and Wyoming Electric’s transmission systems.

•

On July ~~21, 2022,~~24, 2023, Wyoming Electric set a new all-time and summer peak load of ~~294~~312 MW, surpassing the previous ~~summer peaks~~peak of ~~288~~294 MW set on July ~~18, 2022, 282 MW set on June 13, 2022 and 274 MW set in July 2021.~~

21, 2022.

~~Table of Contents~~

Gas Utilities

•~~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 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 in March 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 peaks of 252 MW set on January 5, 2022 and 247 MW set in December 2019.~~

•During the first quarter of 2022, Colorado Electric agreed to join SPP’s Western Energy Imbalance Service (“WEIS”) Market. On September 26, 2022, South Dakota Electric and Wyoming Electric also agreed to join the WEIS Market. South Dakota Electric and Wyoming Electric will join Colorado Electric in integrating into the WEIS 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 set a new winter peak load of 327 MW, surpassing the previous winter peak of 326 MW set in February 2021.~~

~~Gas Utilities~~

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

•During the third quarter of 2022, Kansas Gas and Nebraska Gas submitted proposals to their respective state utility commissions 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. Kansas Gas and Nebraska Gas designed their voluntary RNG and carbon offset programs as comprehensive four-year pilot programs starting in 2023 and running through 2026. On October 25, 2022, Kansas Gas received approval from the KCC for its voluntary RNG and carbon offset program. On June 6, 2022, Colorado Gas, had submitted a similar proposal to the CPUC. In response to intervenor-filed testimony, Colorado Gas filed a motion to withdraw its application which was granted by an administrative law judge on October 26, 2022.RMNG and Wyoming Gas.

Corporate and Other

•

On ~~April 13, 2022,~~June 16, 2023, we filed a ~~jury awarded $41~~new shelf registration statement with the SEC and entered into a new Equity Distribution Sales Agreement. The new Equity Distribution Sales Agreement is similar to our prior agreement and allows us to sell shares of common stock up to an aggregate of $400 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 have appealed the verdict.through our ATM program utilizing our shelf registration statement. See ~~additional information in~~ Note 35 of the Condensed Notes to ~~Condensed~~ Consolidated Financial ~~Statements.~~

Statements for further information.

•

On March 7, 2023, we completed a public debt offering of $350 million, 5.95% 5-year senior unsecured notes due March 15, 2028. The proceeds from the offering were used to repay notes outstanding under our commercial paper program and for other general corporate purposes. See Note 5 of the Condensed Notes to Consolidated Financial Statements for further information.

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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 ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 and ~~2021,~~2022, and our financial condition as of ~~September~~June 30, ~~2022~~2023 and December 31, ~~2021,~~2022, 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~~inter-segment eliminations and all amounts are presented on a pre-tax basis unless otherwise indicated. Minor differences in amounts may result due to rounding.

Consolidated Summary and Overview

Three Months Ended September 30, Nine Months Ended September 30,
2022 2021 2022 2021
(in thousands, except per share amounts)
Operating income (loss):
Electric Utilities $ 69,483 $ 72,840 $ 165,455 $ 159,645
Gas Utilities 10,583 17,257 162,318 139,336
Corporate and Other (587) (224) (2,552) (3,527)
Operating income 79,479 89,873 325,221 295,454
Interest expense, net (40,019) (38,018) (117,328) (113,820)
Other income, net 464 1,560 2,731 1,635
Income tax (expense) (2,090) (5,253) (15,920) (6,333)
Net income 37,834 48,162 194,704 176,936
Net income attributable to non-controlling interest (2,861) (4,050) (8,790) (11,347)
Net income available for common stock $ 34,973 $ 44,112 $ 185,914 $ 165,589
Total earnings per share of common stock, Diluted $ 0.54 $ 0.70 $ 2.86 $ 2.63


	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
	(in thousands, except per share amounts)
Operating income (loss):
Electric Utilities	$	46,619		$	45,226		$	107,679		$	95,972
Gas Utilities		17,725			28,195			132,350			151,735
Corporate and Other		(828	)		(1,032	)		(1,630	)		(1,965	)
Operating income		63,516			72,389			238,399			245,742

Interest expense, net		(41,521	)		(38,764	)		(85,025	)		(77,309	)
Other income (expense), net		(1,540	)		1,563			(866	)		2,267
Income tax benefit (expense)		6,089			658			(8,584	)		(13,830	)
Net income		26,544			35,846			143,924			156,870
Net income attributable to non-controlling interest		(3,491	)		(2,431	)		(6,787	)		(5,929	)
Net income available for common stock	$	23,053		$	33,415		$	137,137		$	150,941

Total earnings per share of common stock, Diluted	$	0.35		$	0.52		$	2.06		$	2.33

Three Months Ended ~~September~~June 30, ~~2022~~2023 Compared to the Three Months Ended ~~September~~June 30, ~~2021:~~

2022:

The variance to the prior year included the following:

•

Electric ~~Utilities’~~Utilities' operating income ~~decreased $3.4~~increased $1.4 million primarily due to ~~higher operating expenses, prior year mark-to-market gains on wholesale energy contacts~~new rates and ~~lower pricing on the new Wygen I PPA partially offset by increased~~ rider ~~revenues,~~recovery and increased transmission services ~~revenue~~ and off-system excess energy sales mostly offset by higher operating expenses and ~~favorable weather;~~unfavorable weather.

•

Gas ~~Utilities’~~Utilities' operating income decreased ~~$6.7~~$10.5 million primarily due to higher operating expenses and ~~mark-to-market losses~~a prior year one-time true-up of carrying costs accrued on ~~wholesale commodity contracts~~Winter Storm Uri regulatory assets partially offset by ~~favorable weather,~~ new rates and rider recovery and ~~carrying costs~~favorable mark-to-market adjustments on ~~our Winter Storm Uri regulatory asset;~~wholesale commodity contracts;

•

Interest expense increased ~~$2.0~~$2.8 million due to higher interest ~~rates and higher short-term borrowings;~~rates;

•

Other ~~income decreased $1.1~~expense increased $3.1 million primarily due to ~~a prior year recognition of death benefits from Company-owned life insurance;~~higher costs for our non-qualified benefit plans driven by market performance and higher non-service benefit plan costs driven by higher discount rates;

•

Income tax ~~expense decreased $3.2~~benefit increased $5.4 million driven by lower pre-tax income and a lower effective tax rate primarily due to a tax benefit from a Nebraska income tax rate decrease partially offset by a benefit from a similar Nebraska tax rate decrease in 2022 and lower ~~pre-tax income;~~wind PTCs driven by the March 2023 sale of Northern Iowa Windpower assets; and

•

Net income attributable to non-controlling interest ~~decreased $1.2~~increased $1.1 million due to ~~lower~~higher net income from Black Hills Colorado IPP primarily driven by ~~lower~~increased fired-engine hours.

Table of Contents

~~Nine~~

Six Months Ended ~~September~~June 30, ~~2022~~2023 Compared to ~~Nine~~the Six Months Ended ~~September~~June 30, ~~2021:~~

2022:

The variance to the prior year included the following:

•

Electric Utilities’ operating income increased $5.8 million primarily due to increased rider revenues, prior year impacts related to Colorado Electric’s TCJA-related bill credits to customers (which were offset by reduced income tax expense), increased transmission services revenue and off-system excess energy sales and prior year mark-to-market losses on wholesale energy contacts partially offset by higher operating expenses and lower pricing on the new Wygen I PPA;

•~~Gas Utilities’ operating income increased $23~~$11.7 million primarily due to new rates and rider recovery, ~~carrying costs~~a one-time gain on ~~our Winter Storm Uri regulatory asset, prior year Black Hills Energy Services Winter Storm Uri costs, customer growth~~the planned sale of Northern Iowa Windpower assets, and increased ~~usage per customer~~transmission services and off-system excess energy sales partially offset by higher operating ~~expenses;~~expenses and unfavorable weather.

•~~Corporate and Other expenses~~

Gas Utilities’ operating income decreased ~~$1.0~~$19.4 million primarily due to ~~an allocation~~higher operating expenses, a prior year one-time true-up of ~~a 2020 employee cost true-up in the first quarter of 2021, which was~~carrying costs accrued on Winter Storm Uri regulatory assets, unfavorable mark-to-market adjustments on wholesale commodity contracts and unfavorable weather partially offset ~~in our business segments;~~by new rates and rider recovery and retail customer growth and demand;

•

Interest expense increased ~~$3.5~~$7.7 million due to higher interest ~~rates and higher short-term and long-term debt balances;~~rates;

•

Other ~~income~~expense, net increased ~~$1.1~~$3.1 million primarily due to ~~lower~~higher costs for our non-qualified benefit plans ~~which were~~ driven by market performance ~~partially offset~~and higher non-service benefit plan costs driven by ~~a prior year recognition of death benefits from Company-owned life insurance;~~higher discount rates; and

•

Income tax ~~expense~~benefit increased ~~$9.6~~$5.2 million driven by ~~higher~~lower pre-tax income and a ~~higher~~lower effective tax rate primarily due to ~~prior year~~a tax ~~benefits~~benefit from ~~Colorado Electric and~~a Nebraska ~~Gas TCJA-related bill credits~~income tax rate decrease partially offset by ~~tax benefits~~a benefit from ~~state~~a similar Nebraska tax rate ~~changes;~~decrease in 2022 and

•~~Net income attributable to non-controlling interest decreased $2.6 million due to~~ lower ~~net income from Black Hills Colorado IPP primarily~~wind PTCs driven by ~~lower fired-engine hours and a planned outage.~~the March 2023 sale of Northern Iowa Windpower assets.

Segment Operating Results

A discussion of operating results from our business segments follows.

Non-GAAP Financial ~~Measure~~

Measures

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.

Table of Contents

Electric Utilities

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

Three Months Ended September 30, Nine Months Ended September 30,
2022 2021 Variance 2022 2021 Variance
Revenue:
Electric - regulated $ 245,269 $ 210,053 $ 35,216 $ 635,190 $ 614,652 $ 20,538
Other - non-regulated 13,401 10,351 3,050 34,396 32,172 2,224
Total revenue 258,669 220,404 38,265 669,586 646,824 22,762
Cost of fuel and purchased power:
Electric - regulated 84,309 50,238 34,071 191,511 194,314 (2,803)
Other - non-regulated 1,644 893 751 3,484 2,679 805
Total cost of fuel and purchased power 85,953 51,131 34,822 194,995 196,993 (1,998)
Electric Utility margin (non-GAAP) 172,716 169,273 3,443 474,591 449,831 24,760
Operations and maintenance 68,896 63,472 5,424 207,565 192,507 15,058
Depreciation and amortization 34,337 32,961 1,376 101,571 97,679 3,892
Total operating expenses 103,233 96,433 6,800 309,136 290,186 18,950
Operating income $ 69,483 $ 72,840 $ (3,357) $ 165,455 $ 159,645 $ 5,810


	Three Months Ended June 30,							Six Months Ended June 30,
	2023		2022		Variance			2023		2022		Variance
Revenue:
Electric - regulated	$	182,822	$	194,197	$	(11,375	)	$	389,523	$	389,921	$	(398	)
Other - non-regulated		10,251		10,182		69			22,259		20,995		1,264
Total revenue		193,073		204,379		(11,306	)		411,782		410,917		865

Cost of fuel and purchased power:
Electric - regulated		36,038		55,723		(19,685	)		90,688		107,202		(16,514	)
Other - non-regulated		366		909		(543	)		1,132		1,840		(708	)
Total cost of fuel and purchased power		36,404		56,632		(20,228	)		91,820		109,042		(17,222	)

Electric Utility margin (non-GAAP)		156,669		147,747		8,922			319,962		301,875		18,087

Operations and maintenance		74,219		69,000		5,219			141,373		138,669		2,704
Depreciation and amortization		35,831		33,521		2,310			70,910		67,234		3,676
Total operating expenses		110,050		102,521		7,529			212,283		205,903		6,380

Operating income	$	46,619	$	45,226	$	1,393		$	107,679	$	95,972	$	11,707

Three Months Ended ~~September~~June 30, ~~2022~~2023, Compared to the Three Months Ended ~~September~~June 30, ~~2021:~~

2022:

Electric Utility margin increased as a result of the following:


	(in millions)
Transmission services and off-system excess energy sales	$	4.2
New rates and rider recovery		4.2
Integrated Generation (a)		2.9
Weather		(2.4	)
	$	8.9

(a)



	~~(in millions)~~
~~New rates and rider recovery~~	$	~~3.9~~
~~Transmission services and off-system excess energy sales~~	~~1.7~~
~~Weather~~	~~1.0~~
~~Commercial and industrial load growth~~	~~0.7~~
~~Integrated Generation~~ ~~(a)~~	~~0.7~~
~~Lower pricing on new Wygen I PPA~~	~~(2.8)~~
~~Prior year mark-to-market on wholesale energy contracts~~	~~(2.5)~~
~~Other~~	~~0.7~~
~~Total increase in Electric Utility margin~~	$	~~3.4~~

~~__________~~

~~(a)~~ Primarily driven by favorable ~~market pricing.~~mining volumes due to a prior year planned outage and increased Black Hills Colorado IPP fired-engine hours.

Operations and maintenance expense increased primarily due to $3.8 million of higher ~~generation-related~~generation expenses driven by planned outages and higher ~~vehicle expenses due to~~materials costs and $1.9 million of higher ~~fuel costs, increased royalties on higher mining revenues partially offset by lower employee costs.~~employee-related expenses.

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

~~Table of Contents~~

~~Nine~~Six Months Ended ~~September~~June 30, ~~2022~~2023, Compared to the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2021:~~

2022:

Electric Utility margin increased as a result of the following:


	(in millions)
New rates and rider recovery	$	9.2
Transmission services and off-system excess energy sales		6.5
Integrated Generation (a)		5.2
Weather		(2.2	)
Other		(0.6	)
	$	18.1

(a)



	~~(in millions)~~
~~New rates and rider recovery~~	$	~~10.5~~
~~Prior year TCJA-related bill credits~~ ~~(a)~~	~~9.3~~
~~Transmission services and off-system excess energy sales~~	~~4.4~~
~~Prior year mark-to-market on wholesale energy contracts~~	~~2.6~~
~~Integrated Generation~~ ~~(b)~~	~~1.8~~
~~Prior year Winter Storm Uri impacts~~ ~~(c)~~	~~1.2~~
~~Weather~~	~~0.8~~
~~Lower pricing on new Wygen I PPA~~	~~(7.9)~~
~~Other~~	~~2.1~~
~~Total increase in Electric Utility margin~~	$	~~24.8~~

~~__________~~

(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)~~ Primarily driven by favorable ~~market pricing.~~

~~(c) As a result of Winter Storm Uri, our Electric Utilities incurred a $0.8 million negative impact to our regulated wholesale power margins~~mining volumes due to ~~higher fuel costs~~a prior year planned outage, mining contract pricing 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.~~Colorado IPP fired-engine hours.

Table of Contents

Operations and maintenance expense increased primarily due to $6.2 million of higher ~~cloud computing licensing costs, higher generation-related~~mining and generation expenses ~~higher vehicle expenses due to~~driven by planned outages and higher fuel and materials costs and $5.4 million of higher ~~outside services~~employee-related expenses ~~and increased property taxes due to expiration of an abatement~~ partially offset by ~~lower employee costs.~~

a one-time $7.7 million gain on the planned sale of Northern Iowa Windpower assets. Other favorable variances, none of which were individually significant, comprised the remainder of the difference when compared to the same period in the prior year.

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

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,
	2023		2022		2023		2022		2023		2022		2023		2022
Residential	$	47,375	$	52,853	$	107,172	$	115,102		302,879		323,775		696,749		715,357
Commercial		63,530		68,756		125,602		133,109		498,239		509,830		1,009,029		1,000,248
Industrial		34,519		38,190		73,467		73,598		502,146		464,928		958,088		928,696
Municipal		4,204		4,992		8,471		9,567		37,571		40,240		73,337		75,545
Subtotal Retail Revenue - Electric		149,628		164,791		314,712		331,377		1,340,835		1,338,773		2,737,203		2,719,846
Contract Wholesale		3,206		4,339		8,610		10,262		118,344		150,645		263,135		332,852
Off-system/Power Marketing Wholesale		5,959		8,666		22,083		15,820		123,258		144,425		380,114		304,866
Other (a)		24,029		16,400		44,118		32,463		-		-		-		-
Total Regulated		182,822		194,197		389,523		389,921		1,582,437		1,633,843		3,380,452		3,357,564
Non-Regulated (b)		10,251		10,182		22,259		20,995		22,848		72,770		77,194		161,864
Total Revenue and Quantities Sold	$	193,073	$	204,379	$	411,782	$	410,917		1,605,285		1,706,613		3,457,646		3,519,428
Other Uses, Losses or Generation, net (c)										109,628		98,323		247,933		211,609
Total Energy										1,714,913		1,804,936		3,705,579		3,731,037

(a)

Revenue (in thousands) Quantities Sold (MWh)
Three Months Ended
September 30, Nine Months Ended
September 30, Three Months Ended
September 30, Nine Months Ended
September 30,
2022 2021 2022 2021 2022 2021 2022 2021
Residential $ 72,115 $ 66,138 $ 187,217 $ 192,349 421,782 419,001 1,137,139 1,150,150
Commercial 77,314 70,696 210,423 214,512 581,239 576,037 1,581,487 1,570,455
Industrial 47,090 37,323 120,688 115,518 483,223 459,076 1,411,919 1,316,060
Municipal 6,093 5,069 15,660 14,471 46,745 47,515 122,290 123,620
Subtotal Retail Revenue - Electric 202,612 179,226 533,989 536,850 1,532,989 1,501,629 4,252,835 4,160,285
Contract Wholesale 8,378 3,855 18,639 12,787 160,070 129,221 492,922 415,979
Off-system/Power Marketing Wholesale 16,769 13,511 32,590 25,549 131,469 120,224 436,335 329,426
Other (a)
17,509 13,461 49,972 39,466 — — — —
Total Regulated 245,269 210,053 635,190 614,652 1,824,528 1,751,074 5,182,092 4,905,690
Non-Regulated (b)
13,401 10,351 34,396 32,172 59,745 56,583 221,609 197,506
Total Revenue and Quantities Sold $ 258,669 $ 220,404 $ 669,586 $ 646,824 1,884,273 1,807,657 5,403,701 5,103,196
Other Uses, Losses or Generation, net (c)
125,613 139,521 337,222 367,201
Total Energy 2,009,886 1,947,178 5,740,923 5,470,397

~~__________~~

~~(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,
	2023		2022		2023		2022		2023		2022		2023		2022
Colorado Electric	$	62,338	$	71,197	$	136,133	$	146,642		536,754		568,890		1,141,298		1,188,478
South Dakota Electric		70,950		76,195		157,563		154,792		545,224		600,172		1,254,044		1,244,395
Wyoming Electric		49,939		47,146		96,610		89,235		500,459		464,781		985,110		924,691
Integrated Generation		9,846		9,841		21,476		20,248		22,848		72,770		77,194		161,864
Total Revenue and Quantities Sold	$	193,073	$	204,379	$	411,782	$	410,917		1,605,285		1,706,613		3,457,646		3,519,428


	Three Months Ended June 30,				Six Months Ended June 30,
Quantities Generated and Purchased by Fuel Type (MWh)	2023		2022		2023		2022
Generated:
Coal		620,952		589,438		1,295,899		1,252,876
Natural Gas and Oil		451,237		262,157		952,303		558,579
Wind		150,622		244,456		381,346		498,024
Total Generated		1,222,811		1,096,051		2,629,548		2,309,479
Purchased:
Coal, Natural Gas, Oil and Other Market Purchases		421,037		608,045		910,853		1,196,205
Wind		71,065		100,840		165,178		225,353
Total Purchased		492,102		708,885		1,076,031		1,421,558

Total Generated and Purchased		1,714,913		1,804,936		3,705,579		3,731,037

Table of Contents

Revenue (in thousands) Quantities Sold (MWh)
Three Months Ended September 30, Nine Months Ended September 30, Three Months Ended September 30, Nine Months Ended September 30,
2022 2021 2022 2021 2022 2021 2022 2021
Colorado Electric $ 96,380 $ 82,971 $ 243,022 $ 226,417 647,532 667,477 1,836,010 1,817,821
South Dakota Electric 94,281 80,674 249,073 247,443 684,059 630,832 1,928,454 1,794,308
Wyoming Electric 55,058 46,813 144,293 142,364 492,938 452,765 1,417,629 1,293,561
Integrated Generation 12,950 9,946 33,198 30,600 59,744 56,583 221,608 197,506
Total Revenue and Quantities Sold $ 258,669 $ 220,404 $ 669,586 $ 646,824 1,884,273 1,807,657 5,403,701 5,103,196


	Three Months Ended June 30,				Six Months Ended June 30,
Quantities Generated and Purchased (MWh)	2023		2022		2023		2022
Generated:
Colorado Electric		120,374		112,117		280,575		197,548
South Dakota Electric		447,492		367,936		1,011,536		823,541
Wyoming Electric		215,169		225,720		445,731		430,318
Integrated Generation		439,776		390,278		891,706		858,072
Total Generated		1,222,811		1,096,051		2,629,548		2,309,479
Purchased:
Colorado Electric		128,359		255,969		325,983		556,366
South Dakota Electric		104,333		248,625		261,305		445,688
Wyoming Electric		246,165		185,932		455,958		376,737
Integrated Generation		13,245		18,359		32,785		42,767
Total Purchased		492,102		708,885		1,076,031		1,421,558

Total Generated and Purchased		1,714,913		1,804,936		3,705,579		3,731,037


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Degree Days	Actual	Variance from Normal	Actual	Variance from Normal	Actual	Variance from Normal	Actual	Variance from Normal
Heating Degree Days:
Colorado Electric	588	(5)%	556	(5)%	3,339	6%	3,271	5%
South Dakota Electric	1,035	(5)%	1,221	13%	4,481	3%	4,469	3%
Wyoming Electric	1,081	(9)%	1,159	(3)%	4,382	5%	4,291	2%
Combined (a)	840	(6)%	904	3%	3,940	4%	3,885	4%

Cooling Degree Days:
Colorado Electric	131	(56)%	333	24%	131	(56)%	333	24%
South Dakota Electric	36	(67)%	107	15%	36	(67)%	107	15%
Wyoming Electric	14	(82)%	121	102%	14	(82)%	121	102%
Combined (a)	75	(60)%	213	28%	75	(60)%	213	28%

(a)

Three Months Ended September 30, Nine Months Ended September 30,
Quantities Generated and Purchased by Fuel Type (MWh) 2022 2021 2022 2021
Generated:
Coal 736,181 711,148 1,989,057 1,953,104
Natural Gas and Oil 457,790 508,170 1,016,369 1,259,111
Wind 143,278 162,924 641,302 572,507
Total Generated 1,337,249 1,382,242 3,646,728 3,784,722
Purchased:
Coal, Natural Gas, Oil and Other Market Purchases 609,699 495,905 1,805,904 1,441,792
Wind 62,938 69,031 288,291 243,883
Total Purchased 672,637 564,936 2,094,195 1,685,675
Total Generated and Purchased 2,009,886 1,947,178 5,740,923 5,470,397

Three Months Ended September 30, Nine Months Ended September 30,
Quantities Generated and Purchased (MWh) 2022 2021 2022 2021
Generated:
Colorado Electric 127,090 150,646 324,638 351,723
South Dakota Electric 510,443 538,632 1,333,984 1,450,113
Wyoming Electric 236,761 221,845 667,079 618,375
Integrated Generation 462,955 471,119 1,321,027 1,364,511
Total Generated 1,337,249 1,382,242 3,646,728 3,784,722
Purchased:
Colorado Electric 251,076 244,613 807,442 716,506
South Dakota Electric 221,872 150,269 667,560 446,904
Wyoming Electric 174,946 146,489 551,683 454,091
Integrated Generation 24,743 23,565 67,510 68,174
Total Purchased 672,637 564,936 2,094,195 1,685,675
Total Generated and Purchased 2,009,886 1,947,178 5,740,923 5,470,397

~~Table of Contents~~

Three Months Ended September 30, Nine Months Ended September 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 25 (66) % 22 (78) % 3,296 4 % 3,348 (1) %
South Dakota Electric 91 (57) % 90 (60) % 4,560 — % 4,462 — %
Wyoming Electric 119 (60) % 112 (62) % 4,410 (2) % 4,594 2 %
Combined (a)
66 (60) % 63 (65) % 3,952 1 % 3,979 — %
Cooling Degree Days:
Colorado Electric 1,028 28 % 942 38 % 1,361 27 % 1,242 39 %
South Dakota Electric 707 38 % 649 22 % 814 35 % 816 29 %
Wyoming Electric 580 72 % 487 63 % 701 77 % 604 74 %
Combined (a)
828 36 % 751 35 % 1,041 34 % 968 39 %

~~__________~~

~~(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)	2023	2022	2023	2022
Coal (b)	92.0%	82.1%	92.4%	86.3%
Natural gas and diesel oil	93.5%	95.1%	93.9%	95.2%
Wind	93.0%	93.8%	93.4%	94.7%
Total Availability	93.0%	91.4%	93.4%	92.7%

Wind Capacity Factor	34.4%	39.8%	41.2%	40.9%

(a)

Three Months Ended September 30, Nine Months Ended September 30,
Contracted generating facilities Availability by fuel type (a)
2022 2021 2022 2021
Coal (b) (c)
96.5 % 94.4 % 89.7 % 88.9 %
Natural gas and diesel oil 97.0 % 97.4 % 95.8 % 95.0 %
Wind 94.4 % 96.5 % 94.6 % 95.7 %
Total Availability 96.4 % 96.4 % 94.0 % 93.5 %
Wind Capacity Factor 22.9 % 26.8 % 34.7 % 30.9 %

~~__________~~

~~(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.

Table of Contents

Gas Utilities

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

Three Months Ended September 30, Nine Months Ended September 30,
2022 2021 Variance 2022 2021 Variance
Revenue:
Natural gas - regulated $ 192,104 $ 150,075 $ 42,029 $ 1,046,910 $ 700,617 $ 346,293
Other - non-regulated 16,184 14,608 1,576 56,938 52,635 4,303
Total revenue 208,288 164,683 43,605 1,103,849 753,252 350,597
Cost of natural gas sold:
Natural gas - regulated 77,590 43,884 33,706 588,007 289,168 298,839
Other - non-regulated 5,187 (750) 5,937 11,242 10,131 1,111
Total cost of natural gas sold 82,778 43,134 39,644 599,249 299,299 299,950
Gas Utility margin (non-GAAP) 125,510 121,549 3,961 504,600 453,953 50,647
Operations and maintenance 85,311 78,161 7,150 255,441 237,624 17,817
Depreciation and amortization 29,616 26,131 3,485 86,841 76,993 9,848
Total operating expenses 114,927 104,292 10,635 342,282 314,617 27,665
Operating income $ 10,583 $ 17,257 $ (6,674) $ 162,318 $ 139,336 $ 22,982


	Three Months Ended June 30,							Six Months Ended June 30,
	2023		2022		Variance			2023		2022		Variance
Revenue:
Natural gas - regulated	$	206,763	$	258,349	$	(51,586	)	$	881,536	$	854,807	$	26,729
Other - non-regulated		15,957		15,821		136			48,100		40,755		7,345
Total revenue		222,720		274,169		(51,450	)		929,636		895,561		34,074

Cost of natural gas sold:
Natural gas - regulated		81,540		126,704		(45,164	)		535,646		510,416		25,230
Other - non-regulated		3,415		5,040		(1,625	)		20,275		6,055		14,220
Total cost of natural gas sold		84,955		131,744		(46,789	)		555,921		516,471		39,450

Gas Utility margin (non-GAAP)		137,765		142,425		(4,660	)		373,715		379,090		(5,375	)

Operations and maintenance		91,223		83,689		7,534			186,050		170,130		15,920
Depreciation and amortization		28,817		30,541		(1,724	)		55,315		57,225		(1,910	)
Total operating expenses		120,040		114,230		5,810			241,365		227,355		14,010

Operating income	$	17,725	$	28,195	$	(10,470	)		132,350	$	151,735	$	(19,385	)

Three Months Ended ~~September~~June 30, ~~2022~~2023, Compared to the Three Months Ended ~~September~~June 30, ~~2021:~~

2022:

Gas Utility margin ~~increased~~decreased as a result of the following:



	~~(in millions)~~
~~Weather~~ ~~(a)~~	$	~~4.4~~
~~New rates and rider recovery~~	~~3.5~~
~~Carrying costs on Winter Storm Uri regulatory asset~~ ~~(b)~~	~~1.9~~
~~Mark-to-market on non-utility natural gas commodity contracts~~	~~(2.5)~~
~~Decreased usage per customer~~	~~(0.9)~~
~~Other~~	~~(2.4)~~
~~Total increase in Gas Utility margin~~	$	~~4.0~~

~~__________~~

(a) Weather impacts for the three months ended September 30, 2022 compared to the same period in the prior year include $3.8 million of increased irrigation loads to agriculture customers in our Nebraska Gas service territory.


	(in millions)
Prior year true-up of Winter Storm Uri carrying costs (a)	$	(10.3	)
Weather		(0.7	)
Mark-to-market on non-utility natural gas commodity contracts		3.0
New rates and rider recovery		2.6
Residential growth and usage		0.8
Other		(0.1	)
	$	(4.7	)

~~(b)~~ (a)

In certain jurisdictions, we have ~~Commission~~commission approval to recover carrying costs on Winter Storm Uri regulatory assets which offset increased interest expense. ~~See~~During the second quarter of 2022, we accrued a one-time, $10.3 million true-up of these carrying costs to reflect commission authorized rates.

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

Operations and maintenance expense increased primarily due to ~~increased bad debt expense primarily attributable to~~$6.0 million of higher ~~customer billings,~~employee-related expenses and $0.5 million of higher materials and outside services ~~and materials expenses, and higher vehicle expenses due to higher fuel costs partially offset by lower employee costs.~~expenses.

Depreciation and amortization ~~increased primarily due~~was comparable to ~~a higher asset base driven by~~the same period in the prior ~~year capital expenditures.~~year.

~~Table of Contents~~

~~Nine~~Six Months Ended ~~September~~June 30, ~~2022~~2023, Compared to the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2021:~~

2022:

Gas Utility margin ~~increased~~decreased as a result of the following:



	~~(in millions)~~
~~New rates and rider recovery~~	$	~~21.0~~
~~Carrying costs on Winter Storm Uri regulatory asset~~ ~~(a)~~	~~16.5~~
~~Prior year Black Hills Energy Services Winter Storm Uri costs~~ ~~(b)~~	~~8.2~~
~~Customer growth and increased usage per customer~~	~~4.8~~
~~Weather~~ ~~(c)~~	~~3.4~~
~~Increased transportation and transmission volumes~~	~~1.1~~
~~Current and prior year TCJA-related bill credits~~ ~~(d)~~	~~0.8~~
~~Mark-to-market on non-utility natural gas commodity contracts~~	~~(3.4)~~
~~Other~~	~~(1.8)~~
~~Total increase in Gas Utility margin~~	$	~~50.6~~

~~__________~~


	(in millions)
Prior year true-up of Winter Storm Uri carrying costs (a)	$	(10.3	)
Mark-to-market on non-utility natural gas commodity contracts		(4.0	)
Weather		(2.9	)
New rates and rider recovery		7.8
Non-residential retail growth and demand		2.9
Residential growth and usage		1.6
Other		(0.5	)
	$	(5.4	)

(a)

In certain jurisdictions, we have ~~Commission~~commission approval to recover carrying costs on Winter Storm Uri regulatory assets which offset increased interest expense. ~~Additionally,~~During the ~~carrying costs~~second quarter of 2022, we accrued ~~during the nine months ended September 30, 2022 included~~ a one-time, $10.3 million true-up of these carrying costs to reflect ~~Commission~~commission authorized rates. ~~See~~

~~Note 2~~Table of Contents

~~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) Weather impacts for the nine months ended September 30, 2022 compared to the same period in the prior year include $4.3 million of increased irrigation loads to agriculture customers in our Nebraska Gas service territory.

(d) In June 2021, Nebraska Gas provided $2.9 million TCJA-related bill credits to its customers. For the nine months ended September 30, 2022, Kansas Gas provided $2.1 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 ~~increased bad debt expense primarily attributable to~~$11.9 million of higher ~~customer billings,~~employee-related expenses and $3.1 million of higher ~~cloud computing licensing costs, higher~~materials and outside services ~~and materials expenses, higher vehicle expenses due to higher fuel costs and increased property taxes due to a higher asset base partially offset by lower employee costs.~~expenses.

Depreciation and amortization ~~increased primarily due~~was comparable to ~~a higher asset base driven by~~the same period in the prior ~~year capital expenditures.~~year.

Operating Statistics
Revenue (in thousands) Quantities Sold and Transported (Dth)
Three Months Ended
September 30, Nine Months Ended
September 30, Three Months Ended
September 30, Nine Months Ended
September 30,
2022 2021 2022 2021 2022 2021 2022 2021
Residential $ 85,398 $ 68,646 $ 604,568 $ 401,413 3,572,971 3,564,722 43,910,976 42,708,511
Commercial 36,819 27,038 256,643 155,015 2,374,179 2,426,019 21,505,127 20,732,271
Industrial 26,155 13,863 52,268 24,576 3,153,641 2,873,540 6,468,756 5,109,501
Other 2,566 2,706 7,638 1,816 — — — —
Total Distribution 150,937 112,253 921,117 582,820 9,100,791 8,864,281 71,884,859 68,550,283
Transportation and Transmission 41,166 37,822 125,794 117,797 35,302,591 34,735,601 117,971,404 114,124,253
Total Regulated 192,104 150,075 1,046,910 700,617 44,403,382 43,599,882 189,856,263 182,674,536
Non-regulated Services 16,184 14,608 56,938 52,635 — — — —
Total Revenue and Quantities Sold $ 208,288 $ 164,683 $ 1,103,849 $ 753,252 44,403,382 43,599,882 189,856,263 182,674,536


	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,
	2023		2022		2023		2022		2023		2022		2023		2022
Residential	$	116,577	$	143,127	$	545,153	$	519,171		7,596,797		8,523,755		37,532,381		40,338,005
Commercial		44,278		61,182		226,801		219,824		4,058,186		4,499,245		18,062,258		19,130,948
Industrial		7,109		16,875		16,308		26,113		1,408,612		2,150,532		2,447,045		3,315,115
Other		2,804		2,300		4,248		5,072		-		-		-		-
Total Distribution		170,768		223,483		792,510		770,179		13,063,595		15,173,532		58,041,684		62,784,068
Transportation and Transmission		35,995		34,865		89,026		84,627		34,226,643		37,623,610		81,406,183		82,668,813
Total Regulated		206,763		258,349		881,536		854,807		47,290,238		52,797,142		139,447,867		145,452,881
Non-regulated Services (a)		15,957		15,821		48,100		40,755		-		-		-		-
Total Revenue and Quantities Sold	$	222,720	$	274,169	$	929,636	$	895,561		47,290,238		52,797,142		139,447,867		145,452,881

(a)

Includes Black Hills Energy Services and non-regulated services under the Service Guard Comfort Plan, Tech Services and HomeServe.


	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,
	2023		2022		2023		2022		2023		2022		2023		2022
Arkansas Gas	$	35,231	$	51,815	$	161,868	$	179,624		5,250,053		5,445,450		16,725,803		18,373,186
Colorado Gas		51,463		50,328		196,349		170,381		5,639,570		6,365,777		19,694,864		19,784,461
Iowa Gas		23,896		42,050		149,353		162,629		7,111,510		8,178,613		21,402,918		23,554,795
Kansas Gas		23,533		35,482		95,754		94,333		7,123,557		8,762,807		18,297,059		19,751,874
Nebraska Gas		57,614		62,337		222,564		196,571		15,724,842		16,714,480		42,805,632		44,050,254
Wyoming Gas		30,983		32,157		103,748		92,023		6,440,706		7,330,015		20,521,591		19,938,311
Total Revenue and Quantities Sold	$	222,720	$	274,169	$	929,636	$	895,561		47,290,238		52,797,142		139,447,867		145,452,881


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Heating Degree Days	Actual	Variance from Normal	Actual	Variance from Normal	Actual	Variance from Normal	Actual	Variance from Normal
Arkansas Gas (a)	278	(15)%	271	(18)%	1,944	(18)%	2,370	(3)%
Colorado Gas	900	2%	817	(14)%	3,987	8%	3,763	(3)%
Iowa Gas	583	(20)%	803	17%	3,830	(9)%	4,382	8%
Kansas Gas (a)	370	(18)%	436	(2)%	2,743	(6)%	3,020	4%
Nebraska Gas	516	(21)%	679	7%	3,570	(4)%	3,720	1%
Wyoming Gas	1,149	(3)%	1,326	9%	4,773	14%	4,598	4%
Combined (b)	674	(10)%	768	2%	3,870	1%	3,933	2%

~~Table of Contents~~(a)

Revenue (in thousands) Quantities Sold & Transported (Dth)
Three Months Ended
September 30, Nine Months Ended
September 30, Three Months Ended
September 30, Nine Months Ended
September 30,
2022 2021 2022 2021 2022 2021 2022 2021
Arkansas Gas $ 30,663 $ 25,188 $ 210,287 $ 145,176 4,396,388 4,319,944 22,769,574 23,345,095
Colorado Gas 32,239 22,452 202,620 135,764 3,408,420 3,798,587 23,192,881 23,121,887
Iowa Gas 24,580 22,015 187,209 108,600 5,103,212 5,810,932 28,658,007 27,141,518
Kansas Gas 38,029 25,972 132,362 87,198 9,202,701 9,075,960 28,954,575 26,694,184
Nebraska Gas 61,588 51,538 258,159 187,673 17,237,325 16,174,821 61,287,579 59,281,802
Wyoming Gas 21,189 17,518 113,212 88,841 5,055,336 4,419,638 24,993,647 23,090,050
Total Revenue and Quantities Sold $ 208,288 $ 164,683 $ 1,103,849 $ 753,252 44,403,382 43,599,882 189,856,263 182,674,536

Three Months Ended September 30, Nine Months Ended September 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)
16 (63)% 11 (74)% 2,386 (4)% 2,515 1%
Colorado Gas 84 (61)% 92 (51)% 3,847 (6)% 3,922 (4)%
Iowa Gas 92 (34)% 42 (70)% 4,474 7% 4,155 (1)%
Kansas Gas (a)
23 (58)% 10 (82)% 3,043 3% 3,079 4%
Nebraska Gas 48 (56)% 33 (70)% 3,768 —% 3,754 (1)%
Wyoming Gas 140 (55)% 153 (50)% 4,738 1% 4,778 1%
Combined (b)
70 (53)% 53 (61)% 4,003 —% 3,978 —%

~~__________~~

~~(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.

Table of Contents

Corporate and Other

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

Three Months Ended September 30, Nine Months Ended September 30,
2022 2021 Variance 2022 2021 Variance
Operating (loss) $ (587) $ (224) $ (363) $ (2,552) $ (3,527) $ 975


	Three Months Ended June 30,								Six Months Ended June 30,
	2023			2022			Variance		2023			2022			Variance
Operating (loss)	$	(828	)	$	(1,032	)	$	204	$	(1,630	)	$	(1,965	)	$	335

Three Months Ended ~~September~~June 30, ~~2022~~2023, Compared to the Three Months Ended ~~September~~June 30, ~~2021:~~

2022:

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

~~Nine~~Six Months Ended ~~September~~June 30, ~~2022~~2023, Compared to the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2021:~~

2022:

~~The decrease in~~

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

prior year.

~~Table of Contents~~

Consolidated Interest Expense, Other Income and Income Tax Expense

Three Months Ended September 30, Nine Months Ended September 30,
2022 2021 Variance 2022 2021 Variance
(in thousands)
Interest expense, net $ (40,019) $ (38,018) $ (2,001) $ (117,328) $ (113,820) $ (3,508)
Other income, net 464 1,560 $ (1,096) $ 2,731 $ 1,635 $ 1,096
Income tax (expense) (2,090) (5,253) $ 3,163 $ (15,920) $ (6,333) $ (9,587)


	Three Months Ended June 30,									Six Months Ended June 30,
	2023			2022			Variance			2023			2022			Variance
	(in thousands)
Interest expense, net	$	(41,521	)	$	(38,764	)	$	(2,757	)	$	(85,025	)	$	(77,309	)	$	(7,716	)
Other income (expense), net		(1,540	)		1,563			(3,103	)		(866	)		2,267			(3,133	)
Income tax benefit (expense)		6,089			658			5,431			(8,584	)		(13,830	)		5,246

Three Months Ended ~~September~~June 30, ~~2022~~2023, Compared to the Three Months Ended ~~September~~June 30, ~~2021:~~

2022:

Interest ~~Expense,~~expense, net

The increase in Interest expense, net was due to higher interest ~~rates and higher short-term debt balances.~~

rates.

~~Other Income, net~~

~~The decrease in~~ Other income (expense), net ~~was primarily driven by a prior year recognition of death benefits from Company-owned life insurance.~~

~~Income Tax (Expense)~~

Income tax expense decreased primarily due to lower pre-tax income partially offset by lower effective tax rate. For the three months ended September 30, 2022, the effective tax rate was 5.2% compared to 9.8% for the same period in 2021. See ~~Note 11~~

~~of the Notes to Condensed Consolidated Financial Statements for discussion of effective tax rate variances.~~

~~Nine Months Ended September 30, 2022 Compared to the Nine Months Ended September 30, 2021:~~

~~Interest Expense, net~~

~~The increase in Interest~~Other expense, net ~~was~~increased due to higher ~~interest rates and higher short-term and long-term debt balances.~~

~~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 and ~~a prior year recognition of death benefits from Company-owned life insurance partially offset by~~ higher non-service ~~pension~~benefit plan costs primarily driven by a higher discount ~~rate.~~

rates.

~~Income Tax (Expense)~~

Income tax ~~expense~~benefit

Income tax benefit increased primarily due to ~~higher~~lower pre-tax income and a ~~higher~~lower effective tax rate. For the ~~nine~~three months ended ~~September~~June 30, ~~2022,~~2023, the effective tax rate was ~~7.6%~~(29.8)% compared to ~~3.5%~~(1.9)% for the same period in ~~2021.~~2022. See Note 11 of the Condensed Notes to ~~Condensed~~ Consolidated Financial Statements for discussion of effective tax rate variances.

Six Months Ended June 30, 2023, Compared to the Six Months Ended June 30, 2022:

Interest expense, net

The increase in Interest expense, net was due to higher interest rates.

Other income (expense), net

Other expense, net increased primarily due to higher costs for our non-qualified benefit plans which were driven by market performance and higher non-service benefit plan costs driven by higher discount rates.

Income tax (expense)

Income tax (expense) decreased primarily due to lower pre-tax income and a lower effective tax rate. For the six months ended June 30, 2023, the effective tax rate was 5.6% compared to 8.1% for the same period in 2022. See Note 11 of the Condensed Notes to Consolidated Financial Statements for discussion of effective tax rate variances.

Table of Contents

Liquidity and Capital Resources

There have been no material changes in Liquidity and Capital Resources from those reported in Item 7 of our ~~2021~~2022 Annual Report on Form 10-K except as described below.

CASH FLOW ACTIVITIES

~~Cash Flow Activities~~

The following ~~table summarizes~~tables summarize our cash flows for the ~~nine~~six months ended ~~September~~June 30, 2023, (in thousands):

Cash provided by (used in): 2022 2021 Variance
Operating activities $ 494,287 $ (144,760) $ 639,047
Investing activities $ (466,321) $ (484,106) $ 17,785
Financing activities $ (24,684) $ 633,061 $ (657,745)

Operating Activities:

~~Table of Contents~~

~~Nine~~


	Six Months Ended June 30,
	2023			2022			Variance
Cash earnings (net income plus non-cash adjustments)	$	287,792		$	296,002		$	(8,210	)
Changes in certain operating assets and liabilities:
Accounts receivable and other current assets		339,842			48,648			291,194
Accounts payable and accrued liabilities		(201,389	)		(24,130	)		(177,259	)
Regulatory assets and liabilities		186,699			128,315			58,384
		325,152			152,833			172,319
Other operating activities		(7,873	)		(6,805	)		(1,068	)
Net cash provided by operating activities	$	605,071		$	442,030		$	163,041

Six Months Ended ~~September~~June 30, ~~2022~~2023, Compared to the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2021~~

2022

~~Operating Activities:~~

Net cash provided by ~~(used in)~~ operating activities was ~~$639~~$163.0 million higher than the same period in ~~2021.~~2022. The variance to the prior year was primarily attributable to:

•

Cash earnings (net income plus non-cash adjustments) were ~~$28~~$8.2 million ~~higher~~lower for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 compared to the same period in the prior year primarily due to ~~increased Electric~~higher operating expenses and ~~Gas Utility margins driven by new rates and increased rider revenues and prior year impacts from Winter Storm Uri.~~higher interest expense.

•

Net inflows from changes in certain operating assets and liabilities were ~~$622~~$172.3 million higher, primarily attributable to:

◦Cash inflows increased by $687 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 $92~~$291.2 million as a result of changes in accounts receivable and other current assets primarily driven by higher collections on pass-through revenues ~~reflecting higher~~and lower natural gas in storage inventories driven by fluctuations in commodity ~~prices;~~prices and timing of injections and withdrawals;

◦Cash outflows ~~decreased~~increased by ~~$26~~$177.3 million as a result of ~~changes~~decreases in accounts payable and accrued liabilities primarily driven by fluctuations in commodity prices, payment timing of natural gas and power purchases and changes in other working capital ~~requirements.~~requirements; and

Cash inflows increased by $58.4 million as a result of changes in our regulatory assets and liabilities primarily due to higher recoveries of deferred gas and fuel cost adjustments driven by fluctuations in commodity prices and higher recoveries of Winter Storm Uri incremental and carrying costs from customers.

•

Cash outflows increased by ~~$10~~$1.1 million for other operating ~~activities primarily due~~activities.

Table of Contents

Investing Activities:


	Six Months Ended June 30,
	2023			2022			Variance
Capital expenditures	$	(261,739	)	$	(293,803	)	$	32,064
Other investing activities		16,367			2,418			13,949
Net cash (used in) investing activities	$	(245,372	)	$	(291,385	)	$	46,013

Six Months Ended June 30, 2023, Compared to ~~higher cloud computing licensing costs and preliminary survey charges.~~the Six Months Ended June 30, 2022

~~Investing Activities:~~

Net cash used in investing activities was ~~$18~~$46.0 million lower than the same period in ~~2021.~~2022. The variance to the prior year was primarily attributable to:

•~~Capital~~

Cash outflows decreased by $32.1 million as a result of lower capital expenditures ~~of $466 million for the nine months ended September 30, 2022 compared to $498 million for the same period in the prior year. Lower current year expenditures~~which were driven by lower programmatic safety, reliability and integrity spending at our Gas and Electric Utilities; and

•

Cash inflows ~~decreased~~increased by ~~$14~~$13.9 million for other investing activities ~~which was~~ primarily ~~driven by prior year sales~~due to proceeds from the sale of ~~transmission assets and facilities, none of which were individually material.~~Northern Iowa Windpower assets.

Financing Activities:


	Six Months Ended June 30,
	2023			2022			Variance
Dividends paid on common stock	$	(83,114	)	$	(77,136	)	$	(5,978	)
Common stock issued		54,689			20,095			34,594
Short-term and long-term debt (repayments), net		(185,600	)		(85,130	)		(100,470	)
Distributions to non-controlling interests		(9,017	)		(8,604	)		(413	)
Other financing activities		(5,095	)		1,682			(6,777	)
Net cash (used in) financing activities	$	(228,137	)	$	(149,093	)	$	(79,044	)

Six Months Ended June 30, 2023, Compared to the Six Months Ended June 30, 2022

Net cash ~~provided by (used in)~~used in financing activities was ~~$658~~$79.0 million higher than the same period in ~~2021.~~2022. The variance to the prior year was primarily attributable to:

•

Cash ~~inflows decreased $609~~outflows increased $100.5 million due to ~~decreases~~short-term debt repayments in excess of short-term and long-term ~~borrowings primarily driven by prior year financing activities related to Winter Storm Uri;~~borrowings;

•

Cash inflows ~~decreased $43~~increased $34.6 million due to ~~decreased~~higher issuances of common stock;

•

Cash outflows increased ~~$8.9~~$6.0 million due to increased dividends paid on common stock; and

•

Cash ~~inflows~~outflows increased by ~~$4.4~~$6.8 million for other financing ~~activities.~~

activities primarily due to financing costs in the March 7, 2023 debt offering.

CAPITAL RESOURCES

Shelf Registration Statement

See ~~Table~~Recent Developments above and Note 5 of ~~Contents~~the Condensed Notes to Consolidated Financial Statements for recent updates on our shelf registration.

~~Capital Resources~~

Short-term Debt

See Note 5 of the Condensed Notes to Consolidated Financial Statements for information on our Revolving Credit Facility and CP ~~Program~~

Program.

~~Our Revolving Credit Facility~~

Long-term Debt

See Recent Developments above and ~~CP Program had the following borrowings, outstanding letters of credit and available capacity:~~

Current Short-term borrowings at
Letters of Credit (a) at
Available Capacity at
Credit Facility Expiration Capacity September 30, 2022 September 30, 2022 September 30, 2022
(in millions)
Revolving Credit Facility and CP Program July 19, 2026 $ 750 $ 501 $ 20 $ 229

~~__________~~

(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 Condensed Notes to ~~Condensed~~ Consolidated Financial ~~Statements.~~

~~The weighted average interest rate~~Statements for recent updates on ~~short-term borrowings at September 30, 2022 was 3.35%. Short-term borrowing activity for the nine months ended September 30, 2022 was:~~

our long-term debt.


	~~(dollars in millions)~~
38 Table of Contents ~~Maximum amount outstanding (based on daily outstanding balances)~~	$	~~508~~
~~Average amount outstanding (based on daily outstanding balances)~~	$	~~347~~
~~Weighted average interest rates~~	~~1.41~~		%

Covenant Requirements

The Revolving Credit Facility and Wyoming Electric’s financing agreements contain covenant requirements. We were in compliance with these covenants as of ~~September~~June 30, ~~2022.~~2023. See Note 5 of the Condensed Notes to ~~Condensed~~ Consolidated Financial Statements for more information.

Equity

See Recent Developments above and Note 5 of the Condensed Notes to ~~Condensed~~ Consolidated Financial Statements for ~~information related to common stock issuances under the ATM.~~recent updates regarding equity.

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 and various financing alternatives, which could include our Revolving Credit Facility, our CP Program, the issuance of common stock under our ATM program or in an opportunistic block ~~trade, or through a non-controlling investment by a third party in certain operating assets.~~trade. We plan to re-finance a portion of our $525 million, 4.25%, senior unsecured notes due November 30, 2023, at or before maturity date.

CREDIT RATINGS

~~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 and outlook and risk profile of BHC at ~~September~~June 30, ~~2022:~~

2023:


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

~~__________~~

(a)

~~(a)~~ On ~~August 26, 2022,~~February 17, 2023, S&P reported BBB+ rating and maintained a Stable outlook.

(b)

On December 20, ~~2021,~~2022, Moody’s reported Baa2 rating and maintained a Stable outlook.

(c)

On October 6, 2022, Fitch reported BBB+ rating and maintained a Stable outlook.

~~Table of Contents~~

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

2023:


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

~~__________~~

(a)

~~(a)~~ On ~~March 31, 2022,~~February 17, 2023, S&P reported A rating.

(b)

On October 6, 2022, Fitch reported A rating.

CAPITAL REQUIREMENTS

~~Capital Requirements~~

Capital Expenditures

Actual
Forecasted (c)
Capital Expenditures by Segment
Nine Months Ended September 30, 2022 (a)
2022 (b)
2023 2024 2025 2026
(in millions)
Electric Utilities $ 180 $ 255 $ 197 $ 348 $ 226 $ 194
Gas Utilities 255 364 386 452 412 393
Corporate and Other 7 8 17 19 20 19
Incremental Projects (d)
— — — — 45 100
$ 442 $ 627 $ 600 $ 819 $ 703 $ 706


	Actual		Forecasted
Capital Expenditures by Segment	Six Months Ended June 30, 2023 (a)		2023 (b)		2024		2025		2026		2027
(in millions)
Electric Utilities	$	100	$	212	$	348	$	268	$	184	$	163
Gas Utilities		153		386		452		412		393		444
Corporate and Other		3		17		19		20		19		18
Incremental Projects (c)		-		-		-		-		104		75
	$	256	$	615	$	819	$	700	$	700	$	700

~~__________~~

(a)

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

(b)

Includes actual capital expenditures for the ~~nine~~six months ended ~~September~~June 30, ~~2022.~~2023.

(c) The increase in forecasted capital expenditures is primarily driven by RNG projects at our Gas Utilities. Additionally, we have identified various other projects at our Electric and Gas Utilities that we previously disclosed as incremental.

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

Table of Contents

Dividends

Dividends paid on our common stock totaled ~~$116~~$83.1 million for the ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, or ~~$0.595~~$0.625 per share per quarter. On ~~October 25, 2022,~~July 24, 2023, our board of directors declared a quarterly dividend of $0.625 per share payable ~~December~~September 1, ~~2022,~~2023, equivalent to an annual dividend of $2.50 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~~

Funding Status of Employee Benefit Plans

Based on the ~~Notes~~fair value of assets and estimated discount rate used to ~~Condensed Consolidated Financial Statements for~~value benefit obligations as of June 30, 2023, we estimate the unfunded status of our employee benefit plans to be approximately $30 million compared to $35 million at December 31, 2022. 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 ~~updates~~capital markets volatility had a limited impact to our ~~purchase~~funded status and does not require interim re-measurement of our pension plan assets or defined benefit obligations.

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Critical Accounting Estimates

~~There have been no material changes in~~

A summary of our critical accounting estimates ~~from those reported~~is included in our ~~2021~~2022 Annual Report on Form 10-K. ~~We are closely monitoring the impacts~~There were no material changes made as 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.

June 30, 2023.

New Accounting Pronouncements

Other than the pronouncements reported in our ~~2021~~2022 Annual Report on Form 10-K and those discussed in Note 1 of the Condensed 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.

~~Table of Contents~~

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 2022 Annual Report on Form 10-K.

ITEM 4.CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of ~~September~~June 30, ~~2022.~~2023. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at ~~September~~June 30, ~~2022.~~

2023.

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

Changes in Internal Control over Financial Reporting

During the quarter ended ~~September~~June 30, ~~2022,~~2023, 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~~2022 Annual Report on Form ~~10-K and~~ 10-K.~~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~~2022 Annual Report on Form 10-K.

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

The following table contains monthly information about our acquisitions of equity securities for the three months ended ~~September~~June 30, ~~2022:~~

2023:


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, 2023 - April 30, 2023		1	$	63.12		-		-
May 1, 2023 - May 31, 2023		755		66.14		-		-
June 1, 2023 - June 30, 2023		2		60.48		-		-
Total		758	$	66.12		-		-

(a)

Period
Total Number of Shares Purchased (a)
Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
July 1, 2022 - July 31, 2022 2 $ 75.59 — —
August 1, 2022 - August 31, 2022 341 $ 74.67 — —
September 1, 2022 - September 30, 2022 3 $ 76.42 — —
Total 346 $ 74.69 — —

~~__________~~

~~(a)~~ Shares were acquired under the share withholding provisions of the Amended and Restated 2015 Omnibus Incentive Plan for payment of taxes associated with the vesting of various equity compensation plans.

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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.

ITEM 5. OTHER INFORMATION

None of our directors or officers adopted, modified, or terminated a Rule 10b5-1 trading arrangement or a non-Rule 10b5-1 trading arrangement during the three months ended June 30, 2023.

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~~

Exhibit Number	Description

3.2	Amended and Restated Bylaws of Black Hills Corporation dated April 24, 2023 (filed as Exhibit 3.2 to the Registrant's Form 8-K filed May 3, 2023).
10.1*	First Amendment to Fourth Amended and Restated Credit Agreement dated as of May 9, 2023 (relating to $750 million Revolving Credit Facility), among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and U.S. Bank, National Association, as Administrative Agent.
10.2	Equity Distribution Sales Agreement dated June 16, 2023 among Black Hills Corporation and the several Agents named therein (filed as Exhibit 1.1 to the Registrant’s Form 8-K filed on June 20, 2023).
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
95*	Mine Safety and Health Administration Safety Data.
101.INS*	XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document
104*	Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)

Table of Contents

SIGNATURES

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

BLACK HILLS CORPORATION


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

		/s/ ~~Richard W. Kinzley~~Kimberly F. Nooney
		~~Richard W. Kinzley,~~Kimberly F. Nooney, Senior Vice President and
		Chief Financial Officer

Dated:	~~November~~August 3, ~~2022~~2023


(unaudited)	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
	(in thousands, except per share amounts)

Revenue	$	462,612	$	380,590	$	1,760,377	$	1,386,594

Operating expenses:
Fuel, purchased power and cost of natural gas sold	168,535		94,057		793,632		495,678
Operations and maintenance	134,449		122,277		403,549		375,201
Depreciation, depletion and amortization	64,019		59,159		188,610		174,871
Taxes - property and production	16,130		15,224		49,365		45,390
Total operating expenses	383,133		290,717		1,435,156		1,091,140

Operating income	79,479		89,873		325,221		295,454

Other income (expense):

Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	(40,580)		(38,604)		(118,454)		(115,098)
Interest income	561		586		1,126		1,278
Other income, net	464		1,560		2,731		1,635
Total other income (expense)	(39,555)		(36,458)		(114,597)		(112,185)

Income before income taxes	39,924		53,415		210,624		183,269
Income tax (expense)	(2,090)		(5,253)		(15,920)		(6,333)
Net income	37,834		48,162		194,704		176,936
Net income attributable to non-controlling interest	(2,861)		(4,050)		(8,790)		(11,347)
Net income available for common stock	$	34,973	$	44,112	$	185,914	$	165,589

Earnings per share of common stock:
Earnings per share, Basic	$	0.54	$	0.70	$	2.87	$	2.63
Earnings per share, Diluted	$	0.54	$	0.70	$	2.86	$	2.63

Weighted average common shares outstanding:
Basic	64,876		63,341		64,722		62,950
Diluted	65,061		63,436		64,910		63,046


(unaudited)	As of
	September 30, 2022		December 31, 2021
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	11,693	$	8,921
Restricted cash and equivalents	5,399		4,889
Accounts receivable, net	249,747		321,652
Materials, supplies and fuel	223,162		150,979
Derivative assets, current	3,868		4,373
Income tax receivable, net	17,112		18,017
Regulatory assets, current	290,087		270,290
Other current assets	48,180		29,012
Total current assets	849,248		808,133

Property, plant and equipment	8,236,053		7,856,573
Less: accumulated depreciation and depletion	(1,538,731)		(1,407,397)
Total property, plant and equipment, net	6,697,322		6,449,176

Other assets:
Goodwill	1,299,454		1,299,454
Intangible assets, net	9,883		10,770
Regulatory assets, non-current	416,119		526,309
Other assets, non-current	50,268		38,054
Total other assets, non-current	1,775,724		1,874,587

TOTAL ASSETS	$	9,322,294	$	9,131,896


Three Months Ended September 30, 2022	Electric Utilities		Gas Utilities		Inter-company Revenues		Total
Customer types:	(in thousands)
Retail	$	211,489	$	157,203	$	—	$	368,692
Transportation	—		41,006		(99)		40,907
Wholesale	13,667		—		—		13,667
Market - off-system sales	16,770		186		—		16,956
Transmission/Other	15,919		8,875		(4,148)		20,646
Revenue from contracts with customers	$	257,845	$	207,270	$	(4,247)	$	460,868
Other revenues	824		1,018		(98)		1,744
Total revenues	$	258,669	$	208,288	$	(4,345)	$	462,612

Timing of revenue recognition:
Services transferred at a point in time	$	7,928	$	—	$	—	$	7,928
Services transferred over time	249,917		207,270		(4,247)		452,940
Revenue from contracts with customers	$	257,845	$	207,270	$	(4,247)	$	460,868


Three Months Ended September 30, 2021	Electric Utilities		Gas Utilities		Inter-company Revenues		Total
Customer Types:	(in thousands)
Retail	$	185,892	$	115,908	$	—	$	301,800
Transportation	—		37,651		(110)		37,541
Wholesale	7,247		—		—		7,247
Market - off-system sales	13,511		75		—		13,586
Transmission/Other	12,904		9,863		(4,288)		18,479
Revenue from contracts with customers	$	219,554	$	163,497	$	(4,398)	$	378,653
Other revenues	850		1,186		(99)		1,937
Total Revenues	$	220,404	$	164,683	$	(4,497)	$	380,590

Timing of Revenue Recognition:
Services transferred at a point in time	$	6,968	$	—	$	—	$	6,968
Services transferred over time	212,586		163,497		(4,398)		371,685
Revenue from contracts with customers	$	219,554	$	163,497	$	(4,398)	$	378,653


Nine Months Ended September 30, 2022	Electric Utilities		Gas Utilities		Inter-company Revenues		Total
Customer types:	(in thousands)
Retail	$	553,327	$	947,290	$	—	$	1,500,617
Transportation	—		125,196		(298)		124,898
Wholesale	32,370		—		—		32,370
Market - off-system sales	32,590		602		—		33,192
Transmission/Other	46,535		27,794		(12,445)		61,884
Revenue from contracts with customers	$	664,822	$	1,100,882	$	(12,743)	$	1,752,961
Other revenues	4,764		2,967		(315)		7,416
Total revenues	$	669,586	$	1,103,849	$	(13,058)	$	1,760,377

Timing of revenue recognition:
Services transferred at a point in time	$	21,712	$	—	$	—	$	21,712
Services transferred over time	643,110		1,100,882		(12,743)		1,731,249
Revenue from contracts with customers	$	664,822	$	1,100,882	$	(12,743)	$	1,752,961


Nine Months Ended September 30, 2021	Electric Utilities		Gas Utilities		Inter-company Revenues		Total
Customer Types:	(in thousands)
Retail	$	554,143	$	601,358	$	—	$	1,155,501
Transportation	—		117,251		(329)		116,922
Wholesale	24,261		—		—		24,261
Market - off-system sales	25,549		235		—		25,784
Transmission/Other	38,315		29,378		(12,868)		54,825
Revenue from contracts with customers	$	642,268	$	748,222	$	(13,197)	$	1,377,293
Other revenues	4,556		5,030		(285)		9,301
Total Revenues	$	646,824	$	753,252	$	(13,482)	$	1,386,594

Timing of Revenue Recognition:
Services transferred at a point in time	$	20,658	$	—	$	—	$	20,658
Services transferred over time	621,610		748,222		(13,197)		1,356,635
Revenue from contracts with customers	$	642,268	$	748,222	$	(13,197)	$	1,377,293


	September 30, 2022				December 31, 2021
	Balance Outstanding		Letters of Credit (a)		Balance Outstanding		Letters of Credit (a)

Revolving Credit Facility	$	—	$	20,193	$	—	$	27,209
CP Program	501,350		—		420,180		—
Total Notes payable	$	501,350	$	20,193	$	420,180	$	27,209


	September 30, 2022		December 31, 2021
	Notional Amounts (MMBtus)	Maximum Term (months) (a)	Notional Amounts (MMBtus)	Maximum Term (months) (a)
Natural gas futures purchased	1,780,000	6	590,000	3
Natural gas options purchased, net	5,500,000	6	3,100,000	3
Natural gas basis swaps purchased	1,530,000	6	870,000	3
Natural gas over-the-counter swaps, net (b)	6,050,000	27	4,570,000	34
Natural gas physical contracts, net (c)	29,017,775	15	16,416,677	24


	As of September 30, 2022
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting (a)		Total
	(in thousands)
Assets:
Commodity derivatives — Gas Utilities	$	—	$	11,832	$	—	$	(6,594)	$	5,238

Total	$	—	$	11,832	$	—	$	(6,594)	$	5,238

Liabilities:
Commodity derivatives — Gas Utilities	$	—	$	12,212	$	—	$	(6,619)	$	5,593

Total	$	—	$	12,212	$	—	$	(6,619)	$	5,593


	September 30, 2022				December 31, 2021
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current maturities (a)	$	4,131,033	$	3,736,930	$	4,126,923	$	4,570,619


Three Months Ended September 30, 2022	External Operating Revenue				Inter-company Operating Revenue				Total Revenues
	Contract Customers		Other Revenues		Contract Customers		Other Revenues
Segment:
Electric Utilities	$	254,917	$	824	$	2,928	$	—	$	258,669
Gas Utilities	205,951		920		1,319		98		208,288
Inter-company eliminations	—		—		(4,247)		(98)		(4,345)
Total	$	460,868	$	1,744	$	—	$	—	$	462,612


	Revenue (in thousands)								Quantities Sold (MWh)
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,		Nine Months Ended September 30,
	2022		2021		2022		2021		2022	2021	2022	2021

Residential	$	72,115	$	66,138	$	187,217	$	192,349	421,782	419,001	1,137,139	1,150,150
Commercial	77,314		70,696		210,423		214,512		581,239	576,037	1,581,487	1,570,455
Industrial	47,090		37,323		120,688		115,518		483,223	459,076	1,411,919	1,316,060
Municipal	6,093		5,069		15,660		14,471		46,745	47,515	122,290	123,620
Subtotal Retail Revenue - Electric	202,612		179,226		533,989		536,850		1,532,989	1,501,629	4,252,835	4,160,285
Contract Wholesale	8,378		3,855		18,639		12,787		160,070	129,221	492,922	415,979
Off-system/Power Marketing Wholesale	16,769		13,511		32,590		25,549		131,469	120,224	436,335	329,426
Other (a)	17,509		13,461		49,972		39,466		—	—	—	—
Total Regulated	245,269		210,053		635,190		614,652		1,824,528	1,751,074	5,182,092	4,905,690
Non-Regulated (b)	13,401		10,351		34,396		32,172		59,745	56,583	221,609	197,506
Total Revenue and Quantities Sold	$	258,669	$	220,404	$	669,586	$	646,824	1,884,273	1,807,657	5,403,701	5,103,196
Other Uses, Losses or Generation, net (c)									125,613	139,521	337,222	367,201
Total Energy									2,009,886	1,947,178	5,740,923	5,470,397


	Revenue (in thousands)								Quantities Sold & Transported (Dth)
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,		Nine Months Ended September 30,
	2022		2021		2022		2021		2022	2021	2022	2021

Arkansas Gas	$	30,663	$	25,188	$	210,287	$	145,176	4,396,388	4,319,944	22,769,574	23,345,095
Colorado Gas	32,239		22,452		202,620		135,764		3,408,420	3,798,587	23,192,881	23,121,887
Iowa Gas	24,580		22,015		187,209		108,600		5,103,212	5,810,932	28,658,007	27,141,518
Kansas Gas	38,029		25,972		132,362		87,198		9,202,701	9,075,960	28,954,575	26,694,184
Nebraska Gas	61,588		51,538		258,159		187,673		17,237,325	16,174,821	61,287,579	59,281,802
Wyoming Gas	21,189		17,518		113,212		88,841		5,055,336	4,419,638	24,993,647	23,090,050
Total Revenue and Quantities Sold	$	208,288	$	164,683	$	1,103,849	$	753,252	44,403,382	43,599,882	189,856,263	182,674,536


Cash provided by (used in):	2022		2021		Variance
Operating activities	$	494,287	$	(144,760)	$	639,047
Investing activities	$	(466,321)	$	(484,106)	$	17,785
Financing activities	$	(24,684)	$	633,061	$	(657,745)


	Actual		Forecasted (c)
Capital Expenditures by Segment	Nine Months Ended September 30, 2022 (a)		2022 (b)		2023		2024		2025		2026
(in millions)
Electric Utilities	$	180	$	255	$	197	$	348	$	226	$	194
Gas Utilities	255		364		386		452		412		393
Corporate and Other	7		8		17		19		20		19
Incremental Projects (d)	—		—		—		—		45		100
	$	442	$	627	$	600	$	819	$	703	$	706