UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2022

OR

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

For the transition period from __________ to __________.

Commission File Number 001-31303

Black Hills Corporation

Incorporated in South Dakota IRS Identification Number 46-0458824

7001 Mount Rushmore Road

Rapid City, South Dakota 57702

Registrant’s telephone number (605) 721-1700

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

NONE

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

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

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

Large Accelerated Filer	x	Accelerated Filer	☐
Non-accelerated Filer	☐	Smaller Reporting Company	☐
		Emerging Growth Company	☐

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

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

Securities registered pursuant to Section 12(b) of the Act:
	Title of each class	Trading Symbol(s)	Name of each exchange on which registered
	Common stock of $1.00 par value	BKH	New York Stock Exchange

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

	Class	Outstanding at October 31, 2022
Common stock, $1.00 par value		65,078,259	shares

TABLE OF CONTENTS
		Page
Glossary of Terms and Abbreviations		4
Forward-Looking Information		7
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements - unaudited	8
	Condensed Consolidated Statements of Income	8
	Condensed Consolidated Statements of Comprehensive Income	9
	Condensed Consolidated Balance Sheets	10
	Condensed Consolidated Statements of Cash Flows	12
	Condensed Consolidated Statements of Equity	13
	Notes to Condensed Consolidated Financial Statements	15
	Note 1. Management’s Statement	15
	Note 2. Regulatory Matters	16
	Note 3. Commitments, Contingencies and Guarantees	18
	Note 4. Revenue	19
	Note 5. Financing	21
	Note 6. Earnings Per Share	22
	Note 7. Risk Management and Derivatives	22
	Note 8. Fair Value Measurements	26
	Note 9. Other Comprehensive Income	28
	Note 10. Employee Benefit Plans	29
	Note 11. Income Taxes	30
	Note 12. Business Segment Information	30
	Note 13. Selected Balance Sheet Information	32

2

TABLE OF CONTENTS
		Page
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
	Executive Summary	33
	Recent Developments	33
	Results of Operations	36
	Consolidated Summary and Overview	36
	Non-GAAP Financial Measure	37
	Electric Utilities	38
	Gas Utilities	42
	Corporate and Other	44
	Consolidated Interest Expense, Other Income and Income Tax Expense	45
	Liquidity and Capital Resources	45
	Cash Flow Activities	45
	Capital Resources	47
	Credit Ratings	47
	Capital Requirements	48
	Critical Accounting Estimates	48
	New Accounting Pronouncements	48
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	49
Item 4.	Controls and Procedures	49
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49
Item 4.	Mine Safety Disclosures	50
Item 6.	Exhibits	50
Signatures		51

3

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 Energy	The name used to conduct the business of our utility companies
Black Hills Energy Services	Black Hills Energy Services Company, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas commodity supply for the Choice Gas Programs (doing business as Black Hills Energy).
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills Wyoming	Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
Blockchain Interruptible Service (BCIS) tariff	The BCIS tariff was proposed by Wyoming Electric and approved by the WPSC in 2019. The tariff was developed to attract new large electric loads related to blockchain and other industry growth with high energy demand.
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service in the Cheyenne, Wyoming area (doing business as Black Hills Energy). Also known as Wyoming Electric.
Chief Operating Decision Maker (CODM)	Chief Executive Officer
Choice Gas Program	Regulator-approved programs in Wyoming and Nebraska that allow certain utility customers to select their natural gas commodity supplier, providing for the unbundling of the commodity service from the distribution delivery service.
Colorado Electric	Black Hills Colorado Electric, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing electric service to customers in Colorado (doing business as Black Hills Energy).
Colorado Gas	Black Hills Colorado Gas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Colorado (doing business as Black Hills Energy).
Common Use System	The Common Use System is a jointly operated transmission system we participate in with Basin Electric Power Cooperative and Powder River Energy Corporation. The Common Use System provides transmission service over these utilities' combined 230-kilovolt (kV) and limited 69-kV transmission facilities within areas of southwestern South Dakota and northeastern Wyoming.
Consolidated Indebtedness to Capitalization Ratio	Any indebtedness outstanding at such time, divided by capital at such time. Capital being consolidated net worth (excluding non-controlling interest) plus consolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit Facility.
Cooling Degree Day	A cooling degree day is equivalent to each degree that the average of the high and low temperatures for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
CPCN	Certificate of Public Convenience and Necessity
CP Program	Commercial Paper Program

4

CPUC	Colorado Public Utilities Commission
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.
Integrated Generation	Non-regulated power generation and mining businesses that are vertically integrated within our Electric Utilities segment.
Iowa Gas	Black Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Iowa (doing business as Black Hills Energy).
IPP	Independent Power Producer
IRS	United States Internal Revenue Service
Kansas Gas	Black Hills Kansas Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Kansas (doing business as Black Hills Energy).
KCC	Kansas Corporation Commission
kV	Kilovolt
LIBOR	London Interbank Offered Rate
MEAN	Municipal Energy Agency of Nebraska
MMBtu	Million British thermal units
Moody’s	Moody’s Investors Service, Inc.
MW	Megawatts
MWh	Megawatt-hours
Nebraska Gas	Black Hills Nebraska Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Nebraska (doing business as Black Hills Energy).
Neil Simpson II	A mine-mouth, coal-fired power plant owned and operated by South Dakota Electric with a total capacity of 90 MW located at our Gillette, Wyoming energy complex.
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 and restated on July 19, 2021, and now terminates 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).

5

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.
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’ Electric and Gas Utilities
Wind Capacity Factor	Measures the amount of electricity a wind turbine produces in a given time period relative to its maximum potential.
Winter Storm Uri	February 2021 winter weather event that caused extreme cold temperatures in the central United States and led to unprecedented fluctuations in customer demand and market pricing for natural gas and energy.
WPSC	Wyoming Public Service Commission
Wygen I	A mine-mouth, coal-fired power plant with a total capacity of 90 MW located at our Gillette, Wyoming energy complex. Black Hills Wyoming owns 76.5% of the facility and Municipal Energy Agency of Nebraska (MEAN) owns the remaining 23.5%.
Wygen II	A mine-mouth, coal-fired power plant owned by Wyoming Electric with a total capacity of 95 MW located at our Gillette, Wyoming energy complex.
Wygen III	A mine-mouth, coal-fired power plant operated by South Dakota Electric with a total capacity of 110 MW located at our Gillette, Wyoming energy complex. South Dakota Electric owns 52% of the power plant, MDU owns 25% and the City of Gillette owns the remaining 23%.
Wyodak Plant	The 362 MW mine-mouth, coal-fired generating facility near Gillette, Wyoming, jointly owned by PacifiCorp (80%) and South Dakota Electric (20%). Our WRDC mine supplies all of the fuel for the facility.
Wyoming Electric	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in the Cheyenne, Wyoming area (doing business as Black Hills Energy).
Wyoming Gas	Black Hills Wyoming Gas, LLC, an indirect and wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Wyoming (doing business as Black Hills Energy).

6

FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q includes “forward-looking statements” as defined by the SEC. Forward-looking statements are all statements other than statements of historical fact including, without limitation, those statements that are identified by the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts” and similar expressions, and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are other than statements of historical facts. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements including, without limitation, the risk factors described in Item 1A of Part I of our 2021 Annual Report on Form 10-K, Part II, Item 1A of this Quarterly Report on Form 10-Q and other reports that we file with the SEC from time to time, and the following:

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

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

•Our ability to execute on our strategy;

•Our ability to successfully execute our financing plans;

•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.

7

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

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

8

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

See Note 9 for additional disclosures.

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

9

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

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

10

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

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

11

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

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

12

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

13

(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

14

BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

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

(1)    Management’s Statement

The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company”, “us”, “we” or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Condensed Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes included in our 2021 Annual Report on Form 10-K.

Segment Reporting

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

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

Use of Estimates and Basis of Presentation

The information furnished in the accompanying Condensed Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the September 30, 2022, December 31, 2021 and September 30, 2021 financial information. Certain lines of business in which we operate are highly seasonal, and our interim results of operations are not necessarily indicative of the results of operations to be expected for an entire year.

Recently Issued Accounting Standards

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

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which was subsequently amended by ASU 2021-01. The standard provides relief for companies preparing for discontinuation of interest rates, such as LIBOR, and allows optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The amendments in this update are elective and are effective upon the ASU issuance through December 31, 2022. We are currently evaluating whether we will apply the optional guidance as we assess the impact of the discontinuance of LIBOR on our current arrangements but do not expect it to have a material impact on our financial position, results of operations and cash flows.

15

(2)    Regulatory Matters

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

	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 Annual Report on Form 10-K.

Arkansas Gas

On December 10, 2021, Arkansas Gas filed a rate review with the APSC seeking recovery of significant infrastructure investments in its 7,200-mile natural gas pipeline system. On October 10, 2022, the APSC approved a partial settlement agreement with all intervening parties for a general rate increase and authorized a capital structure of 45% equity and 55% debt and a return on equity of 9.6%. The APSC’s decision shifts approximately $10 million of rider revenue 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. New rates were effective on October 21, 2022.

16

RMNG

On October 7, 2022, RMNG filed a rate review with the CPUC seeking recovery of significant infrastructure investments in its 600-mile natural gas pipeline system. The rate review requests $12.3 million in new annual revenue based on a future test year with a capital structure of 52% equity and 48% debt and a return on equity of 12.3%. 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 quarter of 2023.

Winter Storm Uri

In February 2021, Winter Storm Uri caused a substantial increase in heating and energy demand and contributed to unforeseeable and unprecedented market prices for natural gas and electricity. As a result, we incurred significant incremental fuel, purchased power and natural gas costs.

Our Utilities submitted Winter Storm Uri cost recovery applications in our state jurisdictions seeking to recover $546 million of these incremental costs through separate tracking mechanisms over a weighted-average recovery period of 3.5 years. 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.

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, Wyoming Gas received approval from the WPSC for its Winter Storm Uri cost recovery application. 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 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 in the second 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.

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 electric distribution and 59-mile electric transmission systems. The rate review requests $15 million in new annual revenue with a capital structure of 54% equity and 46% debt and a return on equity of 10.3%. The request seeks to finalize rates in the first quarter of 2023.

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(3)    Commitments, Contingencies and Guarantees

There have been no significant changes to commitments, contingencies and guarantees from those previously disclosed in Note 3 of our Notes to the Consolidated Financial Statements in our 2021 Annual Report on Form 10-K except for those described below.

Agreement under Blockchain Interruptible Service Tariff

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

Power Sales Agreements

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

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(4)    Revenue

The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reportable segments for the three and nine months ended September 30, 2022 and 2021. 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 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

19

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

Short-term Debt

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

	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.

Revolving Credit Facility and CP Program

Our net short-term borrowings related to our Revolving Credit Facility and CP Program during the nine months ended September 30, 2022 were $81 million. The weighted average interest rate on short-term borrowings related to our Revolving Credit Facility and CP Program at September 30, 2022 was 3.35%.

Debt Covenants

Revolving Credit Facility

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

We were in compliance with our covenants at 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 financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of September 30, 2022, Wyoming Electric’s debt to capitalization ratio was 49%, which was in compliance with these financial covenants.

Equity

At-the-Market Equity Offering Program

During the three months ended September 30, 2022, we did not issue any shares of common stock under the ATM. During the nine months ended September 30, 2022, we issued a total of 0.3 million shares of common stock under the ATM for proceeds of $20 million, net of $0.2 million in issuance costs. During the three months ended September 30, 2021, we issued a total of 0.3 million shares of common stock under the ATM for proceeds of $23 million, net of $0.2 million in issuance costs. During the nine months ended September 30, 2021, we issued a total of 0.9 million shares of common stock under the ATM for proceeds of $63 million, net of $0.6 million in issuance costs.

21

(6)    Earnings Per Share

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	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 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.

Market Risk

Market risk is the potential loss that may occur as a result of an adverse change in market price, rate or supply. We are exposed but not limited to, the following market risks:

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

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

22

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 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.

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 October 2022 through December 2024. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price forward contracts to deliver gas to our Choice Gas Program customers. The gain or loss on these designated derivatives is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and reclassified into earnings in the same period that the underlying hedged item is recognized in earnings. Effectiveness of our hedging position is evaluated at least quarterly.

23

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

	September 30, 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 30, 2022, 2,292,300 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 30, 2022, the Company posted $4.6 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

24

Derivatives Designated as Hedge Instruments

The impacts of cash flow hedges on our Condensed Consolidated Statements of Comprehensive Income and Condensed Consolidated Statements of Income are presented below for the three and nine months ended September 30, 2022 and 2021. Note that this presentation does not reflect the gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.

	Three Months Ended 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 30, 2022, $4.0 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 months ended September 30, 2022 and 2021. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.

		Three Months Ended 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

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

(8)    Fair Value Measurements

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

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

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

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

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

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

Recurring Fair Value Measurements

Derivatives

The commodity contracts for our Utilities segments are valued using the market approach and include forward strip pricing at liquid delivery points, exchange-traded futures, options, basis swaps and over-the-counter swaps and options (Level 2) for wholesale electric energy and natural gas contracts. For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable contract. For over-the-counter instruments, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a credit valuation adjustment based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position. For additional information, see Note 1 of our Notes to the Consolidated Financial Statements in our 2021 Annual Report on Form 10-K.

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

	As of 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 30, 2022, $6.6 million of our commodity derivative assets and $6.6 million of our commodity liabilities, as well as related gross collateral amounts, were subject to master netting agreements.

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

__________

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

Pension and Postretirement Plan Assets

Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about the fair value measurements of their assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 13 to the Consolidated Financial Statements included in our 2021 Annual Report on Form 10-K.

Other Fair Value Measures

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

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

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

(9)    Other Comprehensive Income

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

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

	Location on the Condensed Consolidated Statements of Income	Amount Reclassified from AOCI				Amount Reclassified from AOCI
		Three Months Ended 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)

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

	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps		Commodity Derivatives		Employee Benefit Plans		Total
As of December 31, 2021	$	(10,384)	$	1,476	$	(11,176)	$	(20,084)
Other comprehensive income (loss)
before reclassifications	—		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 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

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Plan Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made in the first nine months of 2022 and anticipated contributions for 2022 and 2023 are as follows (in thousands):

	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

Income Tax Expense (Benefit) and Effective Tax Rates

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

Income tax expense for the three months ended September 30, 2022 was $2.1 million compared to $5.3 million for the same period in 2021. 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. The lower effective tax rate was primarily due to tax benefits from state rate changes.

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

Income tax expense for the nine months ended September 30, 2022 was $16 million compared to $6.3 million for the same period in 2021. For the nine months ended September 30, 2022, the effective tax rate was 7.6% compared to 3.5% for the same period in 2021. The higher effective tax rate was primarily due to $10 million of prior year tax benefits from Colorado Electric and Nebraska Gas TCJA-related bill credits to customers (which were offset by reduced revenue) partially offset by $3.4 million 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).

(12)    Business Segment Information

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

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

Our operating segments are equivalent to our reportable segments.

30

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 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

31

	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

(13)    Selected Balance Sheet Information

Accounts Receivable and Allowance for Credit Losses

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

	September 30, 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 months ended September 30, 2022 and 2021, respectively, were as follows (in thousands):

	Balance at Beginning of Year		Additions Charged to Costs and Expenses		Recoveries and Other Additions		Write-offs and Other Deductions		Balance at 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:

	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

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Accrued Liabilities

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

	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 Note 2, there have been no events subsequent to September 30, 2022, which would require recognition in the condensed consolidated financial statements or disclosures.

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

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

Executive Summary

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

Recent Developments

Winter Storm Uri

In February 2021, Winter Storm Uri caused a substantial increase in heating and energy demand and contributed to unforeseeable and unprecedented market prices for natural gas and electricity. As a result, we incurred significant incremental fuel, purchased power 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. 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. See Note 2 of the Notes to Condensed Consolidated Financial Statements for further information.

Macroeconomic Trends

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

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 to the 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.

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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 recent capital markets volatility had a limited impact to our 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 Notes to Condensed Consolidated Financial Statements for recent rate review activity for Wyoming Electric.

•On October 11, 2022, the WPSC approved a CPCN submitted by Wyoming Electric to construct an estimated 260-mile transmission expansion project. The transmission expansion project, known as 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, Wyoming Electric set a new all-time and summer peak load of 294 MW, surpassing the previous summer peaks of 288 MW set on July 18, 2022, 282 MW set on June 13, 2022 and 274 MW set in July 2021.

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•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 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.

Corporate and Other

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

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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 months ended September 30, 2022 and 2021, and our financial condition as of September 30, 2022 and December 31, 2021, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period or for the entire year.

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

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

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

The variance to the prior year included the following:

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

•Gas Utilities’ operating income decreased $6.7 million primarily due to higher operating expenses and mark-to-market losses on wholesale commodity contracts partially offset by favorable weather, new rates and rider recovery and carrying costs on our Winter Storm Uri regulatory asset;

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

•Other income decreased $1.1 million primarily due to a prior year recognition of death benefits from Company-owned life insurance;

•Income tax expense decreased $3.2 million primarily due to lower pre-tax income; and

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

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

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

•Corporate and Other expenses decreased $1.0 million primarily due to an allocation of a 2020 employee cost true-up in the first quarter of 2021, which was offset in our business segments;

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

•Other income increased $1.1 million primarily due to lower costs for our non-qualified benefit plans which were driven by market performance partially offset by a prior year recognition of death benefits from Company-owned life insurance;

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

•Net income attributable to non-controlling interest decreased $2.6 million due to lower net income from Black Hills Colorado IPP primarily driven by lower fired-engine hours and a planned outage.

Segment Operating Results

A discussion of operating results from our business segments follows.

Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Electric and Gas Utility margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Electric and Gas Utility margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of operation and maintenance expenses, depreciation and amortization expenses, and property and production taxes from the measure.

Electric Utility margin is calculated as operating revenue less cost of fuel and purchased power. Gas Utility margin is calculated as operating revenue less cost of natural gas sold. Our Electric and Gas Utility margin is impacted by 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.

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

Electric Utility margin increased as a result of the following:

	(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.

Operations and maintenance expense increased primarily due to higher generation-related expenses, higher vehicle expenses due to higher fuel costs, increased royalties on higher mining revenues partially offset by lower employee costs.

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

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

Electric Utility margin increased as a result of the following:

	(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 due to higher fuel costs and $2.1 million of incremental fuel costs that are not recoverable through our fuel cost recovery mechanisms partially offset by $1.7 million of increased Electric Utility margin realized under Black Hills Wyoming’s Economy Energy PSA.

Operations and maintenance expense increased primarily due to higher cloud computing licensing costs, higher generation-related expenses, higher vehicle expenses due to higher fuel costs, higher outside services expenses and increased property taxes due to expiration of an abatement partially offset by lower employee costs.

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

Operating Statistics

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

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	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 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

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	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 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.

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

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Gas Utilities

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

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

Gas Utility margin increased 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.

(b)    In certain jurisdictions, we have Commission approval to recover carrying costs on Winter Storm Uri regulatory assets which offset increased interest expense. See 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 higher customer billings, higher outside services and materials expenses, and higher vehicle expenses due to higher fuel costs partially offset by lower employee costs.

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

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

Gas Utility margin increased 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

__________

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

(b)    Black Hills Energy Services offers fixed contract pricing for non-regulated gas supply services to our regulated natural gas customers. The increased cost of natural gas sold during Winter Storm Uri was not recoverable through a regulatory mechanism.

(c) 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 higher customer billings, higher cloud computing licensing costs, higher 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.

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

Operating Statistics

	Revenue (in thousands)								Quantities Sold and Transported (Dth)
	Three Months Ended 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

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	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.

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

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

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

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

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Consolidated Interest Expense, Other Income and Income Tax Expense

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

Interest Expense, net

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

Other Income, net

The decrease in Other income, 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 expense, net was 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 costs primarily driven by a higher discount rate.

Income Tax (Expense)

Income tax expense increased due to higher pre-tax income and a higher effective tax rate. For the nine months ended September 30, 2022, the effective tax rate was 7.6% compared to 3.5% for the same period in 2021. See Note 11 of the Notes to Condensed Consolidated Financial Statements for discussion of effective tax rate variances.

Liquidity and Capital Resources

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

Cash Flow Activities

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

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

Operating Activities:

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

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

•Net inflows from changes in certain operating assets and liabilities were $622 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 million as a result of changes in accounts receivable and other current assets primarily driven by higher pass-through revenues reflecting higher commodity prices; and

◦Cash outflows decreased by $26 million as a result of changes in accounts payable and accrued liabilities primarily driven by payment timing of natural gas and power purchases and other working capital requirements.

•Cash outflows increased by $10 million for other operating activities primarily due to higher cloud computing licensing costs and preliminary survey charges.

Investing Activities:

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

•Capital expenditures of $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 were driven by lower programmatic safety, reliability and integrity spending at our Gas and Electric Utilities; and

•Cash inflows decreased by $14 million for other investing activities which was primarily driven by prior year sales of transmission assets and facilities, none of which were individually material.

Financing Activities:

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

•Cash inflows decreased $609 million due to decreases in short-term and long-term borrowings primarily driven by prior year financing activities related to Winter Storm Uri;

•Cash inflows decreased $43 million due to decreased issuances of common stock;

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

•Cash inflows increased by $4.4 million for other financing activities.

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Capital Resources

Short-term Debt

Revolving Credit Facility and CP Program

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

		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 Notes to Condensed Consolidated Financial Statements.

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

	(dollars in millions)
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 30, 2022. See Note 5 of the Notes to Condensed Consolidated Financial Statements for more information.

Equity

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

Future Financing Plans

We will continue to assess debt and equity needs to support our capital investment plans and other strategic objectives. We plan to fund our capital plan and strategic objectives by using cash generated from operating activities 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. We plan to re-finance our $525 million, 4.25%, senior unsecured notes due November 30, 2023, at or before maturity date.

Credit Ratings

After assessing the current operating performance, liquidity and credit ratings of the Company, management believes that the Company will have access to the capital markets at prevailing market rates for companies with comparable credit ratings.

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

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

__________

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

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

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

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

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

__________

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

(b)    On October 6, 2022, Fitch reported A rating.

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

__________

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

(b)    Includes actual capital expenditures for the nine months ended September 30, 2022.

(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.

Dividends

Dividends paid on our common stock totaled $116 million for the nine months ended September 30, 2022, or $0.595 per share per quarter. On October 25, 2022, our board of directors declared a quarterly dividend of $0.625 per share payable December 1, 2022, equivalent to an annual dividend of $2.50 per share. The amount of future cash dividends to be declared and paid, if any, will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our Revolving Credit Facility and our future business prospects.

Unconditional Purchase Obligations

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

Critical Accounting Estimates

There have been no material changes in our critical accounting estimates from those reported in our 2021 Annual Report on Form 10-K. We are closely monitoring the impacts of recent macroeconomic trends and Winter Storm Uri on our critical accounting estimates including, but not limited to, collectibility of customer receivables, cost recoverability through regulatory assets, impairment risk of goodwill and long-lived assets, valuation of pension assets and liabilities and contingent liabilities. For more information on our critical accounting estimates, see Part II, Item 7 of our 2021 Annual Report on Form 10-K.

New Accounting Pronouncements

Other than the pronouncements reported in our 2021 Annual Report on Form 10-K and those discussed in Note 1 of the Notes to Condensed Consolidated Financial Statements, there have been no new accounting pronouncements that are expected to have a material effect on our financial position, results of operations or cash flows.

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ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4.    CONTROLS AND PROCEDURES

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

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

Changes in Internal Control over Financial Reporting

During the quarter ended September 30, 2022, there have been no changes in our internal controls over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART II.    OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS

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

ITEM 1A.RISK FACTORS

There are no material changes to the risk factors previously disclosed in Item 1A of Part I in our 2021 Annual Report on Form 10-K.

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

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

Period	Total Number of Shares Purchased (a)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
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 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 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
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)

50

SIGNATURES

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

BLACK HILLS CORPORATION

		/s/ Linden R. Evans
		Linden R. Evans, President and
		Chief Executive Officer
		/s/ Richard W. Kinzley
		Richard W. Kinzley, Senior Vice President and
		Chief Financial Officer
Dated:	November 3, 2022

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