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BLACK HILLS CORP /SD/ - Quarter Report: 2022 March (Form 10-Q)

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 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 FilerxAccelerated Filer
Non-accelerated FilerSmaller 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 classTrading Symbol(s)Name of each exchange on which registered
Common stock of $1.00 par valueBKHNew 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.
ClassOutstanding at April 29, 2022
Common stock, $1.00 par value64,833,223 shares


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GLOSSARY OF TERMS AND ABBREVIATIONS

The following terms and abbreviations appear in the text of this report and have the definitions described below:
AFUDCAllowance for Funds Used During Construction
AOCIAccumulated Other Comprehensive Income (Loss)
APSCArkansas Public Service Commission
Arkansas GasBlack 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).
ASCAccounting Standards Codification
ASUAccounting Standards Update issued by the FASB
ATMAt-the-market equity offering program
AvailabilityThe availability factor of a power plant is the percentage of the time that it is available to provide energy.
BHCBlack Hills Corporation; the Company
Black Hills Colorado IPPBlack Hills Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Electric Generation
Black Hills Electric GenerationBlack 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 EnergyThe name used to conduct the business of our utility companies
Black Hills Energy ServicesBlack 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 HoldingsBlack Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Utility HoldingsBlack Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills WyomingBlack Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
Cheyenne LightCheyenne 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 ProgramRegulator-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 ElectricBlack 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 GasBlack 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 SystemThe 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 RatioAny indebtedness outstanding at such time, divided by capital at such time. Capital being consolidated net worth (excluding non-controlling interest) plus consolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit Facility.
Cooling Degree Day (CDD)A cooling degree day is equivalent to each degree that the average of the high and low temperatures for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
CPCNCertificate of Public Convenience and Necessity
CP ProgramCommercial Paper Program
CPUCColorado Public Utilities Commission
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DthDekatherm. A unit of energy equal to 10 therms or approximately one million British thermal units (MMBtu)
FASBFinancial Accounting Standards Board
FitchFitch Ratings Inc.
GAAPAccounting principles generally accepted in the United States of America
Heating Degree Day (HDD)A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
Integrated GenerationNon-regulated power generation and mining businesses that are vertically integrated within our Electric Utilities segment.
Iowa GasBlack 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).
IPPIndependent Power Producer
IRSUnited States Internal Revenue Service
Kansas GasBlack 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).
KCCKansas Corporation Commission
kVKilovolt
LIBORLondon Interbank Offered Rate
MEANMunicipal Energy Agency of Nebraska
MMBtuMillion British thermal units
Moody’sMoody’s Investors Service, Inc.
MWMegawatts
MWhMegawatt-hours
Nebraska GasBlack 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 IIA 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.
OCIOther Comprehensive Income
PPAPower Purchase Agreement
PRPAPlatte River Power Authority
Pueblo Airport GenerationThe 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 WyomingA 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 ReadyVoluntary renewable energy subscription program for large commercial, industrial and governmental agency customers in South Dakota and Wyoming.
Revolving Credit FacilityOur $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.
SECUnited States Securities and Exchange Commission
Service Guard Comfort PlanAppliance protection plan that provides home appliance repair services through on-going monthly service agreements to residential utility customers.
S&PS&P Global Ratings, a division of S&P Global Inc.
South Dakota ElectricBlack 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).
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SPPSouthwest Power Pool
TCJATax Cuts and Jobs Act
Tech ServicesNon-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.
UtilitiesBlack Hills’ Electric and Gas Utilities
Wind Capacity FactorMeasures the amount of electricity a wind turbine produces in a given time period relative to its maximum potential.
Winter Storm UriFebruary 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.
WPSCWyoming Public Service Commission
Wygen IIA mine-mouth, coal-fired power plant owned by Wyoming Electric with a total capacity of 95 MW located at our Gillette, Wyoming energy complex.
Wyoming ElectricCheyenne 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 GasBlack 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).

FORWARD-LOOKING INFORMATION

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

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

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

Our ability to execute on our strategy;

Our ability to successfully execute our financing plans;

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

Board of Directors’ approval of any future quarterly dividends;

The impact of future governmental regulation;

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

The effects of inflation and volatile energy prices; and

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

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

ITEM 1.        FINANCIAL STATEMENTS



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)Three Months Ended March 31,
20222021
(in thousands, except per share amounts)
Revenue$823,570 $633,432 
Operating expenses:
Fuel, purchased power and cost of natural gas sold436,926 293,147 
Operations and maintenance136,132 129,679 
Depreciation, depletion and amortization60,463 57,269 
Taxes - property and production16,696 15,022 
Total operating expenses650,217 495,117 
Operating income173,353 138,315 
Other income (expense):
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)(38,821)(37,825)
Interest income276 225 
Other income, net704 266 
Total other income (expense)(37,841)(37,334)
Income before income taxes135,512 100,981 
Income tax expense(14,488)(494)
Net income 121,024 100,487 
Net income attributable to non-controlling interest(3,498)(4,171)
Net income available for common stock$117,526 $96,316 
Earnings per share of common stock:
Earnings per share, Basic$1.82 $1.54 
Earnings per share, Diluted$1.82 $1.54 
Weighted average common shares outstanding:
Basic64,565 62,633 
Diluted64,721 62,691 

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.
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BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)Three Months Ended March 31,
20222021
(in thousands)
Net income$121,024 $100,487 
Other comprehensive income (loss), net of tax:
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $6 and $9, respectively)
(18)(16)
Reclassification adjustments of benefit plan liability - net loss (net of tax of $(45) and $(217), respectively)
143 381 
Derivative instruments designated as cash flow hedges:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(177) and $(190), respectively)
536 523 
Net unrealized gains (losses) on commodity derivatives (net of tax of $(340) and $(35), respectively)
1,047 107 
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $552 and $(8), respectively)
(1,702)23 
Other comprehensive income, net of tax1,018 
Comprehensive income121,030 101,505 
Less: comprehensive income attributable to non-controlling interest(3,498)(4,171)
Comprehensive income available for common stock$117,532 $97,334 

See Note 9 for additional disclosures.

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.
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BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)As of
March 31, 2022December 31, 2021
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents$16,330 $8,921 
Restricted cash and equivalents5,017 4,889 
Accounts receivable, net383,790 321,652 
Materials, supplies and fuel108,232 150,979 
Derivative assets, current7,382 4,373 
Income tax receivable, net17,991 18,017 
Regulatory assets, current265,496 270,290 
Other current assets45,070 29,012 
Total current assets849,308 808,133 
Property, plant and equipment7,927,840 7,856,573 
Less: accumulated depreciation and depletion(1,454,425)(1,407,397)
Total property, plant and equipment, net6,473,415 6,449,176 
Other assets:
Goodwill1,299,454 1,299,454 
Intangible assets, net10,474 10,770 
Regulatory assets, non-current457,848 526,309 
Other assets, non-current40,155 38,054 
Total other assets, non-current1,807,931 1,874,587 
TOTAL ASSETS$9,130,654 $9,131,896 

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.
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BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
(unaudited)As of
March 31, 2022December 31, 2021
(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable$173,102 $217,761 
Accrued liabilities227,209 244,759 
Derivative liabilities, current191 1,439 
Regulatory liabilities, current52,742 17,574 
Notes payable341,480 420,180 
Total current liabilities794,724 901,713 
Long-term debt, net of current maturities4,128,291 4,126,923 
Deferred credits and other liabilities:
Deferred income tax liabilities, net490,384 465,388 
Regulatory liabilities, non-current482,442 485,377 
Benefit plan liabilities123,111 123,925 
Other deferred credits and other liabilities140,680 141,447 
Total deferred credits and other liabilities1,236,617 1,216,137 
Commitments, contingencies and guarantees (Note 3)
Equity:
Stockholders’ equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 64,849,227 and 64,793,095 shares, respectively
64,849 64,793 
Additional paid-in capital1,786,980 1,783,436 
Retained earnings1,041,451 962,458 
Treasury stock, at cost – 19,685 and 54,078 shares, respectively
(1,287)(3,509)
Accumulated other comprehensive income (loss)(20,078)(20,084)
Total stockholders’ equity2,871,915 2,787,094 
Non-controlling interest99,107 100,029 
Total equity2,971,022 2,887,123 
TOTAL LIABILITIES AND TOTAL EQUITY$9,130,654 $9,131,896 

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.
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BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)Three Months Ended March 31,
20222021
Operating activities:(in thousands)
Net income $121,024 $100,487 
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization60,463 57,269 
Deferred financing cost amortization2,475 2,214 
Stock compensation3,638 3,257 
Deferred income taxes14,462 153 
Employee benefit plans1,173 2,304 
Other adjustments, net5,337 6,151 
Changes in certain operating assets and liabilities:
Materials, supplies and fuel34,995 15,932 
Accounts receivable and other current assets(71,241)(11,599)
Accounts payable and other current liabilities(8,422)(23,602)
Regulatory assets98,528 (533,006)
Regulatory liabilities— (5,291)
Other operating activities, net1,689 (355)
Net cash provided by (used in) operating activities264,121 (386,086)
Investing activities:
Property, plant and equipment additions(136,779)(146,302)
Other investing activities(1,065)78 
Net cash (used in) investing activities(137,844)(146,224)
Financing activities:
Dividends paid on common stock(38,533)(35,514)
Common stock issued3,791 — 
Term loan - borrowings— 800,000 
Term loan - repayments— (200,000)
Net borrowings (payments) of Revolving Credit Facility and CP Program(78,700)(18,170)
Long-term debt - repayments— (1,436)
Distributions to non-controlling interest(4,420)(4,644)
Other financing activities(878)(740)
Net cash provided by (used in) financing activities(118,740)539,496 
Net change in cash, restricted cash and cash equivalents7,537 7,186 
Cash, restricted cash and cash equivalents at beginning of period13,810 10,739 
Cash, restricted cash and cash equivalents at end of period$21,347 $17,925 
Supplemental cash flow information:
Cash (paid) refunded during the period:
Interest, net of amounts capitalized$(23,605)$(21,232)
Income taxes— 990 
Non-cash investing and financing activities:
Accrued property, plant and equipment purchases at March 3139,559 51,914 

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.
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BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(unaudited)Common StockTreasury Stock
(in thousands except share amounts)SharesValueSharesValueAdditional Paid in CapitalRetained EarningsAOCINon-controlling InterestTotal
December 31, 202164,793,095 $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— — — — — — — 
Dividends on common stock ($0.595 per share)
— — — — — (38,533)— — (38,533)
Share-based compensation425 — (34,393)2,222 (191)— — — 2,031 
Issuance of common stock55,707 56 — — 3,776 — — — 3,832 
Issuance costs— — — — (41)— — — (41)
Distributions to non-controlling interest— — — — — — — (4,420)(4,420)
March 31, 202264,849,227 $64,849 19,685 $(1,287)$1,786,980 $1,041,451 $(20,078)$99,107 $2,971,022 

(unaudited)Common StockTreasury Stock
(in thousands except share amounts)SharesValueSharesValueAdditional Paid in CapitalRetained EarningsAOCINon-controlling InterestTotal
December 31, 202062,827,179 $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 compensation82,794 83 7,448 (445)1,672 — — — 1,310 
Other— — — — — (2)— — (2)
Distributions to non-controlling interest— — — — — — — (4,644)(4,644)
March 31, 202162,909,973 $62,910 39,940 $(2,564)$1,658,957 $931,538 $(26,328)$100,789 $2,725,302 

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BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 2021 Annual Report on Form 10-K)


(1)    Management’s Statement

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

Segment Reporting

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

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

Use of Estimates and Basis of Presentation

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

Recently Issued Accounting Standards

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

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

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(2)    Regulatory Matters

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

As ofAs of
March 31, 2022December 31, 2021
Regulatory assets
Winter Storm Uri (a)
$438,675 $509,025 
Deferred energy and fuel cost adjustments (b)
67,068 59,973 
Deferred gas cost adjustments (b)
1,917 9,488 
Gas price derivatives (b)
220 2,584 
Deferred taxes on AFUDC (b)
7,420 7,457 
Employee benefit plans and related deferred taxes (c)
87,947 88,923 
Environmental (b)
1,375 1,385 
Loss on reacquired debt (b)
20,561 21,011 
Deferred taxes on flow through accounting (b)
69,387 63,243 
Decommissioning costs (b)
5,339 5,961 
Other regulatory assets (b)
23,435 27,549 
Total regulatory assets723,344 796,599 
   Less current regulatory assets(265,496)(270,290)
Regulatory assets, non-current$457,848 $526,309 
Regulatory liabilities
Deferred energy and gas costs (b)
$38,343 $6,113 
Employee benefit plan costs and related deferred taxes (c)
31,943 32,241 
Cost of removal (b)
181,690 179,976 
Excess deferred income taxes (c)
259,856 264,042 
Other regulatory liabilities (c)
23,352 20,579 
Total regulatory liabilities535,184 502,951 
   Less current regulatory liabilities(52,742)(17,574)
Regulatory liabilities, non-current$482,442 $485,377 
__________
(a)    Timing of Winter Storm Uri incremental cost recovery and associated carrying costs vary by jurisdiction and some jurisdictions are still subject to pending applications with the respective utility commission. See further information below.
(b)    Recovery of costs, but we are not allowed a rate of return.
(c)    In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base.

Regulatory Activity

Except as discussed below, there have been no other significant changes to our Regulatory Matters from those previously disclosed in Note 2 of the Notes to the Consolidated Financial Statements in our 2021 Annual Report on Form 10-K.

Winter Storm Uri

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

Our Utilities submitted Winter Storm Uri cost recovery applications in our state jurisdictions seeking to recover $546 million of these incremental costs through separate tracking mechanisms over a weighted-average recovery period of 3.5 years. These incremental cost estimates are subject to adjustments as final decisions are issued by the respective utility commissions. In these applications, we seek approval to recover carrying costs. For the three months ended March 31, 2022 and 2021, $2.3 million and $0, respectively, of carrying costs were accrued and recorded to a regulatory asset.

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On January 27, 2022, Kansas Gas received approval from the KCC for their 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.

To date, Colorado Electric, Colorado Gas, Iowa Gas, Kansas Gas, Nebraska Gas and South Dakota Electric received commission approval of their Winter Storm Uri cost recovery applications. Additionally, Arkansas Gas and Wyoming Gas received approval for interim cost recovery subject to a final decision on carrying costs and recovery periods at a later date. For the three months ended March 31, 2022, our Utilities collected $73 million of Winter Storm Uri incremental costs and carrying costs from customers. As of March 31, 2022, we estimate that our remaining Winter Storm Uri regulatory asset has a weighted-average recovery period of 3.1 years.

TCJA

As part of Kansas Gas’s 2021 rate review settlement agreement, Kansas Gas will deliver $3.0 million of TCJA and state tax reform benefits to customers, annually, for three years starting in 2022 (approximately $9.1 million of total benefits expected to be delivered). For the three months ended March 31, 2022, Kansas Gas delivered $0.8 million of TCJA-related bill credits to customers.

These bill credits, which resulted in a reduction of revenue, were offset by a reduction in income tax expense and resulted in a minimal impact to Net income for the three months ended March 31, 2022.

Arkansas Gas

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


(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.

Power Sales Agreement

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 Wygen III ownership. This agreement, which has similar terms and conditions as South Dakota Electric’s existing agreement with MDU expiring on December 31, 2023, is effective on January 1, 2024 and will expire on December 31, 2028.

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

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

Power Purchase Agreement

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. This agreement relates to a new solar facility to be constructed and would expire 15 years after construction completion. On January 31, 2022, TC Solar provided notice of its intent to terminate the PPA. We disputed TC Solar's right to termination and, pursuant to the agreement, entered resolution negotiations to amend certain contract terms with TC Solar, which are ongoing.
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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.


(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 months ended March 31, 2022 and 2021. Sales tax and other similar taxes are excluded from revenues.
Three Months Ended March 31, 2022 Electric Utilities  Gas UtilitiesInter-company RevenuesTotal
Customer types:(in thousands)
Retail$172,806 $561,013 $— $733,819 
Transportation— 49,523 (99)49,424 
Wholesale10,275 — — 10,275 
Market - off-system sales7,154 238 — 7,392 
Transmission/Other15,433 9,575 (4,149)20,859 
Revenue from contracts with customers$205,668 $620,349 $(4,248)$821,769 
Other revenues870 1,043 (112)1,801 
Total revenues$206,538 $621,392 $(4,360)$823,570 
Timing of revenue recognition:
Services transferred at a point in time$7,113 $— $— $7,113 
Services transferred over time198,555 620,349 (4,248)814,656 
Revenue from contracts with customers$205,668 $620,349 $(4,248)$821,769 

Three Months Ended March 31, 2021 Electric Utilities  Gas UtilitiesInter-company RevenuesTotal
Customer Types:(in thousands)
Retail$204,280 $341,605 $— $545,885 
Transportation— 47,951 (110)47,841 
Wholesale11,359 — — 11,359 
Market - off-system sales4,772 73 — 4,845 
Transmission/Other14,186 10,390 (4,289)20,287 
Revenue from contracts with customers$234,597 $400,019 $(4,399)$630,217 
Other revenues807 2,500 (92)3,215 
Total Revenues$235,404 $402,519 $(4,491)$633,432 
Timing of Revenue Recognition:
Services transferred at a point in time$6,976 $— $— $6,976 
Services transferred over time227,621 400,019 (4,399)623,241 
Revenue from contracts with customers$234,597 $400,019 $(4,399)$630,217 



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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:

March 31, 2022December 31, 2021
Balance Outstanding
Letters of Credit (a)
Balance Outstanding
Letters of Credit (a)
Revolving Credit Facility— 16,855 — 27,209 
CP Program341,480 — 420,180 — 
Total Notes payable$341,480 $16,855 $420,180 $27,209 
__________
(a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility.

Revolving Credit Facility and CP Program

Our net short-term repayments related to our Revolving Credit Facility and CP Program during the three months ended March 31, 2022 were $79 million. The weighted average interest rate on short-term borrowings related to our Revolving Credit Facility and CP Program at March 31, 2022 was 0.79%.

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 March 31, 2022 as shown below:

As of March 31, 2022Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio61.0%Less than65%

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 March 31, 2021, we were in compliance with these financial covenants.

Equity

At-the-Market Equity Offering Program

During the three months ended March 31, 2022, we issued a total of 55,707 shares of common stock under the ATM for proceeds of $3.8 million. During the three months ended March 31, 2021, we did not issue any shares of common stock under the ATM.

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(6)    Earnings Per Share

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

Three Months Ended March 31,
20222021
Net income available for common stock$117,526 $96,316 
Weighted average shares - basic64,565 62,633 
Dilutive effect of:
Equity compensation156 58 
Weighted average shares - diluted64,721 62,691 
Earnings per share of common stock:
Earnings per share, Basic$1.82 $1.54 
Earnings per share, Diluted$1.82 $1.54 

The following securities were excluded from the diluted earnings per share computation because of their anti-dilutive nature (in thousands):
Three Months Ended March 31,
20222021
Equity compensation— 14 
Restricted stock— 19 
Anti-dilutive shares— 33 


(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), market speculation, inflation, pipeline constraints, and other factors that may impact natural gas and electric supply and demand; and

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

Credit Risk

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

We attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements and mitigating credit exposure with less creditworthy counterparties through parental guarantees, cash collateral requirements, letters of credit and other security agreements.
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We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customers’ current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience, changes in current market conditions, expected losses and any specific customer collection issue that is identified.

Derivatives and Hedging Activity

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

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

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

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

We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and sales during time frames ranging from April 2022 through December 2024. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price forward contracts to deliver gas to our Choice Gas Program customers. The gain or loss on these designated derivatives is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and reclassified into earnings in the same period that the underlying hedged item is recognized in earnings. Effectiveness of our hedging position is evaluated at least quarterly.

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

March 31, 2022December 31, 2021
Notional
Amounts (MMBtus)
Maximum
Term
(months) (a)
Notional
Amounts (MMBtus)
Maximum
Term
(months) (a)
Natural gas futures purchased— 0590,000 3
Natural gas options purchased, net— 03,100,000 3
Natural gas basis swaps purchased — 0870,000 3
Natural gas over-the-counter swaps, net (b)
2,750,000 334,570,000 34
Natural gas physical contracts, net (c)
4,181,531 2116,416,677 24
__________
(a)    Term reflects the maximum forward period hedged.
(b)    As of March 31, 2022, 410,000 MMBtus of natural gas over-the-counter swaps purchases were designated as cash flow hedges.
(c)     Volumes exclude derivative contracts that qualify for the normal purchases and normal sales exception permitted by GAAP.

We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At March 31, 2022, the Company posted $0.3 million related to such provisions, which is included in Other current assets on the Condensed Consolidated Balance Sheets.

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Derivatives by Balance Sheet Classification

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

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

Balance Sheet LocationMarch 31, 2022December 31, 2021
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivativesDerivative assets, current$1,081 $2,017 
Noncurrent commodity derivativesOther assets, non-current11 18 
Total derivatives designated as hedges$1,092 $2,035 
Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivativesDerivative assets, current$6,301 $2,356 
Noncurrent commodity derivativesOther assets, non-current596 804 
Liability derivative instruments:
Current commodity derivativesDerivative liabilities, current(191)(1,439)
Noncurrent commodity derivativesOther deferred credits and other liabilities(29)(20)
Total derivatives not designated as hedges$6,677 $1,701 

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 months ended March 31, 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 March 31,Three Months Ended March 31,
Three Months Ended March 31,Three Months Ended March 31,
2022202120222021
Derivatives in Cash Flow Hedging RelationshipsAmount of Gain/(Loss) Recognized in OCIIncome Statement LocationAmount of Gain/(Loss) Reclassified from AOCI into Income
(in thousands)(in thousands)
Interest rate swaps$713 $713 Interest expense$(713)$(713)
Commodity derivatives(867)173 Fuel, purchased power and cost of natural gas sold2,254 (31)
Total$(154)$886 $1,541 $(744)

As of March 31, 2022, $1.8 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 months ended March 31, 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 March 31,
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Three Months Ended March 31,
20222021
Derivatives Not Designated as Hedging InstrumentsIncome Statement LocationAmount of Gain/(Loss) on Derivatives Recognized in Income
(in thousands)
Commodity derivatives - Electric Fuel, purchased power and cost of natural gas sold$— $(1,524)
Commodity derivatives - Natural GasFuel, purchased power and cost of natural gas sold3,494 366 
$3,494 $(1,158)

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 $0.2 million and $2.6 million as of March 31, 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 March 31, 2022
Level 1Level 2Level 3
Cash Collateral and Counterparty
Netting (a)
Total
(in thousands)
Assets:
Commodity derivatives — Gas Utilities$— $7,989 $— $— $7,989 
Total$— $7,989 $— $— $7,989 
Liabilities:
Commodity derivatives — Gas Utilities$— $220 $— $— $220 
Total$— $220 $— $— $220 
__________
(a)    As of March 31, 2022, we had no commodity derivative assets or liabilities, or related gross collateral amounts, that were subject to master netting agreements.

As of December 31, 2021
Level 1Level 2Level 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:
March 31, 2022December 31, 2021
Carrying
Amount
Fair ValueCarrying
Amount
Fair Value
Long-term debt, including current maturities (a)
$4,128,291 $4,201,135 $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 IncomeAmount Reclassified from AOCI
Three Months Ended March 31,
20222021
Gains and (losses) on cash flow hedges:
Interest rate swapsInterest expense$(713)$(713)
Commodity contractsFuel, purchased power and cost of natural gas sold2,254 (31)
1,541 (744)
Income taxIncome tax expense(375)198 
Total reclassification adjustments related to cash flow hedges, net of tax$1,166 $(546)
Amortization of components of defined benefit plans:
Prior service costOperations and maintenance$24 $25 
Actuarial gain (loss)Operations and maintenance(188)(598)
(164)(573)
Income taxIncome tax expense39 208 
Total reclassification adjustments related to defined benefit plans, net of tax$(125)$(365)
Total reclassifications$1,041 $(911)

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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 SwapsCommodity DerivativesEmployee Benefit PlansTotal
As of December 31, 2021$(10,384)$1,476 $(11,176)$(20,084)
Other comprehensive income (loss)
before reclassifications— 1,047 — 1,047 
Amounts reclassified from AOCI536 (1,702)125 (1,041)
As of March 31, 2022$(9,848)$821 $(11,051)$(20,078)
Derivatives Designated as Cash Flow Hedges
Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
As of December 31, 2020$(12,558)$$(14,790)$(27,346)
Other comprehensive income (loss)
before reclassifications— 107 — 107 
Amounts reclassified from AOCI523 23 365 911 
As of March 31, 2021$(12,035)$132 $(14,425)$(26,328)


(10)    Employee Benefit Plans

Components of Net Periodic Expense

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

Defined Benefit Pension PlanSupplemental Non-qualified Defined Benefit PlansNon-pension Defined Benefit Postretirement Healthcare Plan
Three Months Ended March 31,202220212022202120222021
Service cost$982 $1,259 $(392)$693 $492 $559 
Interest cost2,705 2,328 208 177 321 265 
Expected return on plan assets(4,631)(5,219)— — (31)(34)
Net amortization of prior service costs(17)— — — (72)(109)
Recognized net actuarial loss1,523 1,829 69 439 16 117 
Net periodic expense (benefit)$562 $197 $(115)$1,309 $726 $798 
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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 three months of 2022 and anticipated contributions for 2022 and 2023 are as follows (in thousands):

Contributions MadeAdditional ContributionsContributions
Three Months Ended March 31, 2022Anticipated for 2022Anticipated for 2023
Defined Benefit Pension Plan$— $3,900 $3,200 
Non-pension Defined Benefit Postretirement Healthcare Plan$1,276 $3,828 $4,761 
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans$539 $1,617 $2,215 


(11)    Income Taxes

Income Tax Expense and Effective Tax Rates

Three Months Ended March 31, 2022 Compared to the Three Months Ended March 31, 2021

Income tax expense for the three months ended March 31, 2022 was $14.5 million compared to $0.5 million reported for the same period in 2021. For the three months ended March 31, 2022, the effective tax rate was 10.7% compared to 0.5% for the same period in 2021. The higher effective tax rate is primarily due to $7.6 million of prior year tax benefits from Colorado Electric TCJA-related bill credits to customers (which were offset by reduced revenue).


(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 changed our operating segments to align with the revised manner in which our CODM reviews our financial performance and allocates resources. Our power generation and mining businesses, which were previously presented as separate operating segments, are now part of our Electric Utilities segment. This change aligns with our vertically integrated business model for our Electric Utilities. Comparative periods presented reflect this change.

Our operating segments are equivalent to our reportable segments.

Segment information was as follows (in thousands):

Total assets (net of intercompany eliminations) as of:March 31, 2022December 31, 2021
Electric Utilities$3,804,335 $3,796,662 
Gas Utilities5,232,594 5,246,370 
Corporate and Other93,725 88,864 
Total assets$9,130,654 $9,131,896 
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Three Months Ended March 31, 2022External Operating RevenueInter-company Operating RevenueTotal Revenues
 Contract Customers Other Revenues  Contract Customers Other Revenues
Segment:
Electric Utilities$202,739 $870 $2,929 $— $206,538 
Gas Utilities619,030 931 1,319 112 621,392 
Inter-company eliminations— — (4,248)(112)(4,360)
Total$821,769 $1,801 $— $— $823,570 

Three Months Ended March 31, 2021External Operating RevenueInter-company Operating Revenue Total Revenues
 Contract Customers Other Revenues  Contract Customers Other Revenues
Segment:
Electric Utilities$231,718 $807 $2,879 $— $235,404 
Gas Utilities398,499 2,408 1,520 92 402,519 
Inter-company eliminations— — (4,399)(92)(4,491)
Total$630,217 $3,215 $— $— $633,432 

Three Months Ended March 31,
20222021
Operating income (loss):
Electric Utilities$50,746 $39,343 
Gas Utilities123,540 102,094 
Corporate and Other(933)(3,122)
Operating income173,353 138,315 
Interest expense, net(38,545)(37,600)
Other income, net704 266 
Income tax expense(14,488)(494)
Net income 121,024 100,487 
Net income attributable to non-controlling interest(3,498)(4,171)
Net income available for common stock$117,526 $96,316 


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(13)    Selected Balance Sheet Information

Accounts Receivable and Allowance for Credit Losses

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

March 31, 2022December 31, 2021
Billed Accounts Receivable$257,982 $181,027 
Unbilled Revenue130,294 142,738 
Less: Allowance for Credit Losses(4,486)(2,113)
Accounts Receivable, net$383,790 $321,652 

Changes to allowance for credit losses for the three months ended March 31, 2022 and 2021, respectively, were as follows (in thousands):

Balance at Beginning of YearAdditions Charged to Costs and ExpensesRecoveries and Other AdditionsWrite-offs and Other Deductions
Balance at March 31,
2022$2,113 $3,416 $655 $(1,698)$4,486 
2021$7,003 $1,877 $1,014 $(1,643)$8,251 

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:

March 31, 2022December 31, 2021
Materials and supplies$92,224 $86,400 
Fuel - Electric Utilities1,459 1,267 
Natural gas in storage14,549 63,312 
Total materials, supplies and fuel$108,232 $150,979 

Accrued Liabilities

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

March 31, 2022December 31, 2021
Accrued employee compensation, benefits and withholdings$51,032 $74,387 
Accrued property taxes53,389 50,874 
Customer deposits and prepayments39,543 48,814 
Accrued interest46,396 33,680 
Other (none of which is individually significant)36,849 37,004 
Total accrued liabilities$227,209 $244,759 


(14)    Subsequent Events

Except as described in Note 3, there have been no events subsequent to March 31, 2022, which would require recognition in the condensed consolidated financial statements or disclosures.

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

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


Executive Summary

We are a customer-focused energy solutions provider that invests in our communities’ safety, sustainability and growth with a mission of Improving Life with Energy and a vision to be the Energy Partner of Choice. The Company’s core mission— and our primary focus — is to provide safe, reliable and cost-effective electric and natural gas service to 1.3 million utility customers in over 800 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming.


Recent Developments

Winter Storm Uri

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

In 2021, our Utilities submitted cost recovery applications with the utility commissions in our state jurisdictions to recover incremental costs associated with Winter Storm Uri. To date, we have received final commission approval for all of our Winter Storm Uri cost recovery applications with the exception of Arkansas Gas and Wyoming Gas (which are both approved for interim cost recovery). See Note 2 of the Notes to Condensed Consolidated Financial Statements for further information.

Macroeconomic Trends

We are monitoring emerging macroeconomic trends including inflationary pressures on the prices of commodities, materials, outside services and employee costs; supply chain constraints; and a competitive and tightening labor market. To date, we have experienced limited net impacts from these trends. However, the situation remains fluid and it is difficult to predict.

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

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

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

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

Business Segment Recent Developments

Electric Utilities

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

On February 15, 2022, Wyoming Electric submitted a request to the WPSC seeking approval for a CPCN to construct an estimated 260-mile transmission expansion project. As proposed, the approximately $260 million transmission expansion project, known as Ready Wyoming, would provide customers long-term price stability and greater flexibility as power markets develop in the Western States. If approved, construction of the project would take place in multiple phases or segments spanning 2023 through 2025 and would interconnect South Dakota Electric’s and Wyoming Electric’s transmission systems.
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On January 26, 2022, Colorado Electric agreed to join SPP’s Western Energy Imbalance Service Market. Colorado Electric will join the market in April 2023 and will continue to study long-term solutions for joining or developing an organized wholesale market. The expansion allows the utilities to participate in a real-time market to dispatch energy at lower costs.

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

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

Gas Utilities

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

Corporate and Other

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


Results of Operations

Certain lines of business in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements. In particular, the normal peak usage season for our Electric Utilities is June through August while the normal peak usage season for our Gas Utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three months ended March 31, 2022 and 2021, and our financial condition as of March 31, 2022 and December 31, 2021, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period or for the entire year.

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

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


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Consolidated Summary and Overview

Three Months Ended March 31,
20222021
(in thousands, except per share amounts)
Operating income (loss):
Electric Utilities$50,746 $39,343 
Gas Utilities123,540 102,094 
Corporate and Other(933)(3,122)
Operating income173,353 138,315 
Interest expense, net(38,545)(37,600)
Other income, net704 266 
Income tax expense(14,488)(494)
Net income121,024 100,487 
Net income attributable to non-controlling interest(3,498)(4,171)
Net income available for common stock$117,526 $96,316 
Total earnings per share of common stock, Diluted$1.82 $1.54 

Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021

The variance to the prior year included the following:

Electric Utilities’ operating income increased $11 million primarily due to prior year impacts related to Colorado Electric’s TCJA-related bill credits to customers (which were offset by reduced income tax expense), increased off-system energy sales, and prior year impacts related to Winter Storm Uri partially offset by higher operating expenses;
Gas Utilities’ operating income increased $21 million primarily due to new rates and rider recovery, prior year impacts from Winter Storm Uri, favorable mark-to-market adjustments on wholesale commodity contracts and customer growth partially offset by higher operating expenses;
Corporate and Other expenses decreased $2.2 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 $0.9 million due to higher debt balances; and
Income tax expense increased $14 million driven by higher pre-tax income and a higher effective tax rate due to prior year tax benefits from Colorado Electric TCJA-related bill credits.

Segment Operating Results

A discussion of operating results from our business segments follows.


Non-GAAP Financial Measure

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

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

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


Electric Utilities

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

Three Months Ended March 31,
20222021Variance
Revenue:
Electric - regulated$195,725 $223,096 $(27,371)
Other - non-regulated10,813 12,308 (1,495)
Total revenue206,538 235,404 (28,866)
Cost of fuel and purchased power:
Electric - regulated51,479 99,469 (47,990)
Other - non-regulated931 830 101 
Total cost of fuel and purchased power52,410 100,299 (47,889)
Electric Utility margin (non-GAAP)154,128 135,105 19,023 
Operations and maintenance69,669 63,734 5,935 
Depreciation and amortization33,713 32,028 1,685 
Total operating expenses103,382 95,762 7,620 
Operating income$50,746 $39,343 $11,403 

Three Months Ended March 31, 2022 Compared to the Three Months Ended March 31, 2021:

Electric Utility margin increased as a result of the following:

(in millions)
Prior year TCJA-related bill credits (a)
$9.3 
Off-system energy sales and transmission services3.7 
Prior year Winter Storm Uri impacts (b)
3.6 
New rates and rider recovery1.7 
Mark-to-market on wholesale energy contracts1.5 
Customer load growth1.3 
Lower pricing on new Wygen I PPA(2.5)
Weather(0.2)
Other0.6 
Total increase in Electric Utility margin$19.0 
__________
(a)    In February 2021, Colorado Electric delivered TCJA-related bill credits to its customers. These bill credits were offset by a reduction in income tax expense and resulted in a minimal impact to Net income.
(b)    As a result of Winter Storm Uri, we incurred a $3.2 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.
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Operations and maintenance expense increased primarily due to higher cloud computing licensing costs and higher maintenance costs related to planned spring outages at the Gillette, Wyoming energy complex.

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
March 31,
Three Months Ended
March 31,
2022202120222021
Residential$62,249 $72,760 391,582 396,086 
Commercial64,353 77,007 490,418 492,955 
Industrial35,408 43,009 463,768 415,191 
Municipal4,575 5,020 35,305 36,242 
Subtotal Retail Revenue - Electric166,585 197,796 1,381,073 1,340,474 
Contract Wholesale5,923 5,922 182,207 156,995 
Off-system/Power Marketing Wholesale7,154 4,772 160,441 60,221 
Other (a)
16,063 14,606 — — 
Total Regulated195,725 223,096 1,723,721 1,557,690 
Non-Regulated (b)
10,813 12,308 89,094 79,515 
Total Revenue and Quantities Sold$206,538 $235,404 1,812,815 1,637,205 
Other Uses, Losses or Generation, net (c)
113,286 132,748 
Total Energy1,926,101 1,769,953 
__________
(a)    Primarily related to transmission revenues from the Common Use System.
(b)    Includes Integrated Generation and non-regulated services to our retail customers under the Service Guard Comfort Plan and Tech Services.
(c)    Includes company uses and line losses.
Revenue (in thousands)Quantities Sold (MWh)
Three Months Ended March 31,Three Months Ended March 31,
2022202120222021
Colorado Electric$75,445 $79,437 619,588 553,980 
South Dakota Electric78,597 94,129 644,223 581,848 
Wyoming Electric42,089 49,950 459,910 421,862 
Integrated Generation10,407 11,888 89,094 79,515 
Total Revenue and Quantities Sold$206,538 $235,404 1,812,815 1,637,205 

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Three Months Ended March 31,
Quantities Generated and Purchased by Fuel Type (MWh)20222021
Generated:
Coal663,438 618,134 
Natural Gas and Oil296,422 373,786 
Wind253,568 213,847 
Total Generated1,213,428 1,205,767 
Purchased:
Coal, Natural Gas, Oil and Other Market Purchases588,160 464,541 
Wind124,513 99,645 
Total Purchased712,673 564,186 
Total Generated and Purchased1,926,101 1,769,953 

Three Months Ended March 31,
Quantities Generated and Purchased (MWh)20222021
Generated:
Colorado Electric85,431 90,256 
South Dakota Electric455,605 468,816 
Wyoming Electric204,598 173,990 
Integrated Generation467,794 472,704 
Total Generated1,213,428 1,205,766 
Purchased:
Colorado Electric300,397 220,245 
South Dakota Electric197,063 142,002 
Wyoming Electric190,805 172,425 
Integrated Generation24,408 29,515 
Total Purchased712,673 564,187 
Total Generated and Purchased1,926,101 1,769,953 
Three Months Ended March 31,
Three Months Ended March 31,
20222021
Degree DaysActualVariance from
Normal
ActualVariance from
Normal
Heating Degree Days
Colorado Electric2,715 %2,731 %
South Dakota Electric3,248 (1)%3,324 %
Wyoming Electric3,132 %3,261 %
Combined (a)
2,981 %3,040 %
__________
(a)    Degree days are calculated based on a weighted average of total customers by state.

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Three Months Ended March 31,
Contracted generating facilities Availability by fuel type (a)
20222021
Coal (b)
90.6 %86.2 %
Natural gas and diesel oil (b)
95.3 %90.0 %
Wind95.6 %93.8 %
Total Availability94.1 %89.8 %
Wind Capacity Factor42.0 %37.2 %
__________
(a)    Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.
(b)     2021 included a planned outage at Wygen II and unplanned outages at Neil Simpson II and Pueblo Airport Generation.


Gas Utilities

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

Three Months Ended March 31,
20222021Variance
Revenue:
Natural gas - regulated$596,458 $378,077 $218,381 
Other - non-regulated24,934 24,442 492 
Total revenue621,392 402,519 218,873 
Cost of natural gas sold:
Natural gas - regulated383,712 182,967 200,745 
Other - non-regulated1,015 10,083 (9,068)
Total cost of natural gas sold384,727 193,050 191,677 
Gas Utility margin (non-GAAP)236,665 209,469 27,196 
Operations and maintenance86,441 82,200 4,241 
Depreciation and amortization26,684 25,175 1,509 
Total operating expenses113,125 107,375 5,750 
Operating income$123,540 $102,094 $21,446 

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Three Months Ended March 31, 2022 Compared to the Three Months Ended March 31, 2021:

Gas Utility margin increased as a result of the following:
(in millions)
New rates and rider recovery$11.9 
Prior year Black Hills Energy Services Winter Storm Uri costs (a)
8.2 
Mark-to-market on non-utility natural gas commodity contracts3.4 
Residential customer growth and increased usage per customer2.7 
Winter Storm Uri carrying costs (b)
2.3 
Weather(0.8)
Other(0.5)
Total increase in Gas Utility margin$27.2 
__________
(a)    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.
(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 higher cloud computing licensing costs and increased property taxes due to a higher asset base.

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

Operating Statistics
Revenue (in thousands)Quantities Sold and Transported (Dth)
Three Months Ended March 31,Three Months Ended March 31,
2022202120222021
Residential$376,044 $234,397 31,814,250 30,568,738 
Commercial158,642 91,089 14,631,703 13,812,321 
Industrial9,238 4,902 1,164,583 898,289 
Other2,772 (472)— — 
Total Distribution546,696 329,916 47,610,536 45,279,348 
Transportation and Transmission49,762 48,161 45,045,203 45,314,438 
Total Regulated596,458 378,077 92,655,739 90,593,786 
Non-regulated Services24,934 24,442 — — 
Total Revenue and Quantities Sold$621,392 $402,519 92,655,739 90,593,786 
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Revenue (in thousands)Quantities Sold and Transported (Dth)
Three Months Ended March 31,Three Months Ended March 31,
2022202120222021
Arkansas Gas$127,809 $86,994 12,927,736 13,306,734 
Colorado Gas120,053 79,122 13,418,684 13,366,015 
Iowa Gas120,579 56,754 15,376,182 14,313,973 
Kansas Gas58,851 40,063 10,989,067 10,462,797 
Nebraska Gas134,234 93,098 27,335,774 27,284,101 
Wyoming Gas59,866 46,488 12,608,296 11,860,166 
Total Revenue and Quantities Sold$621,392 $402,519 92,655,739 90,593,786 
Three Months Ended March 31,
20222021
Heating Degree Days:ActualVariance
from Normal
ActualVariance
from Normal
Arkansas Gas (a)
2,099—%2,1211%
Colorado Gas2,9461%2,9651%
Iowa Gas3,5796%3,4221%
Kansas Gas (a)
2,5845%2,5765%
Nebraska Gas3,041—%3,0972%
Wyoming Gas3,2723%3,4257%
Combined Gas (b)
3,1652%3,1863%
__________
(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 March 31,
20222021Variance
Operating (loss)$(933)$(3,122)$2,189 

Three Months Ended March 31, 2022 Compared to the Three Months Ended March 31, 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 March 31,
20222021Variance
(in thousands)
Interest expense, net$(38,545)$(37,600)$(945)
Other income, net$704 $266 $438 
Income tax expense$(14,488)$(494)$(13,994)

Three Months Ended March 31, 2022 Compared to the Three Months Ended March 31, 2021:

Interest Expense, net

The increase in Interest expense, net was due to higher debt balances primarily driven by the August 2021 senior unsecured notes.

Other Income, net

Other income, net was comparable to the same period in the prior year.

Income Tax Expense

For the three months ended March 31, 2022, the effective tax rate was 10.7% compared to 0.5% 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 three months ended March 31, (in thousands):
Cash provided by (used in):20222021Variance
Operating activities$264,121 $(386,086)$650,207 
Investing activities$(137,844)$(146,224)$8,380 
Financing activities$(118,740)$539,496 $(658,236)

Three Months Ended March 31, 2022 Compared to the Three Months Ended March 31, 2021

Operating Activities:

Net cash provided by (used in) operating activities was $650 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 $37 million higher for the three months ended March 31, 2022 compared to the same period in the prior year primarily due to increased Electric and Gas Utility margins driven by new rates and rider recovery and prior year impacts from Winter Storm Uri.

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Net inflows from changes in certain operating assets and liabilities were $611 million higher, primarily attributable to:

Cash inflows increased by $637 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, current year recovery of a portion of Winter Storm Uri incremental and carrying costs from customers, and higher recoveries of gas and fuel cost adjustments driven by higher commodity prices;

Cash inflows decreased by $41 million as a result of changes in accounts receivable and other current assets primarily driven by higher pass-through revenues reflecting higher commodity prices partially offset by lower natural gas in storage inventories; and

Cash outflows decreased by $15 million as a result of decreases in accounts payable and accrued liabilities primarily driven by payment timing of natural gas and power purchases and other working capital requirements.

Cash inflows increased by $2.0 million for other operating activities.

Investing Activities:

Net cash used in investing activities was $8 million lower than the same period in 2021. The variance to the prior year was primarily attributable to:

Capital expenditures of $137 million for the three months ended March 31, 2022 compared to $146 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 outflows increased by $1.1 million for other investing activities.

Financing Activities:

Net cash 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 $659 million due to short-term and long-term repayments in excess of borrowings. This decrease was primarily driven by $600 million of net borrowings from our term loan in the prior year;

Cash inflows increased $3.8 million due to higher issuances of common stock; and

Cash outflows increased $3.0 million due to increased dividends paid on common stock.


Capital Resources

Short-term Debt

Revolving Credit Facility and CP Program

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

CurrentShort-term borrowings at
Letters of Credit (a) at
Available Capacity at
Credit FacilityExpirationCapacityMarch 31, 2022March 31, 2022March 31, 2022
Revolving Credit Facility and CP ProgramJuly 19, 2026$750 $341 $17 $392 
__________
(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.
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The weighted average interest rate on short-term borrowings at March 31, 2022 was 0.79%. Short-term borrowing activity for the three months ended March 31, 2022 was:

(dollars in millions)
Maximum amount outstanding (based on daily outstanding balances)$429 
Average amount outstanding (based on daily outstanding balances) $361 
Weighted average interest rates0.44 %

Covenant Requirements

The Revolving Credit Facility and Wyoming Electric’s financing agreements contain covenant requirements. We were in compliance with these covenants as of March 31, 2022. See Note 5 of the Notes to Condensed Consolidated Financial Statements for more information.

Equity

During the three months ended March 31, 2022, we issued a total of 55,707 shares of common stock under the ATM for $3.8 million.

Future Financing Plans

We will continue to assess debt and equity needs to support our capital investment plans and other strategic objectives. In the remaining months of 2022, we plan to fund our capital plan and strategic objectives by using cash generated from operating activities, our Revolving Credit Facility and CP Program and issuing $100 million to $120 million of common stock under the ATM.


Credit Ratings

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

The following table represents the credit ratings and outlook and risk profile of BHC at March 31, 2022:

Rating AgencySenior Unsecured RatingOutlook
S&P (a)
BBB+Stable
Moody’s (b)
Baa2Stable
Fitch (c)
BBB+Stable
__________
(a)    On October 20, 2021, S&P reported BBB+ rating and maintained a Stable outlook.
(b)    On December 20, 2021, Moody’s reported Baa2 rating and maintained a Stable outlook.
(c)    On September 17, 2021, Fitch reported BBB+ rating and maintained a Stable outlook.

The following table represents the credit ratings of South Dakota Electric at March 31, 2022:

Rating AgencySenior Secured Rating
S&P (a)
A
Fitch (b)
A
__________
(a)    On July 1, 2021, S&P reported A rating.
(b)    On September 17, 2021, Fitch reported A rating.


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Capital Requirements

Capital Expenditures

ActualForecasted
Capital Expenditures by Segment
Three Months Ended March 31, 2022 (a)
2022 (b)
2023202420252026
(in millions)
Electric Utilities$48 $239 $205 $285 $231 $155 
Gas Utilities57 363 383 386 349 346 
Corporate and Other12 13 13 13 
Incremental Projects (c)
— — — — 60 140 
$108 $611 $600 $684 $653 $654 
__________
(a)    Includes accruals for property, plant and equipment as disclosed in supplemental cash flow information in the Condensed Consolidated Statements of Cash Flows in the Condensed Consolidated Financial Statements.
(b)    Includes actual capital expenditures for the three months ended March 31, 2022.
(c)    These represent projects that are being evaluated by our segments for timing, cost and other factors.

Dividends

Dividends paid on our common stock totaled $39 million for the three months ended March 31, 2022, or $0.595 per share per quarter. On April 25, 2022, our board of directors declared a quarterly dividend of $0.595 per share payable June 1, 2022, equivalent to an annual dividend of $2.38 per share. The amount of any future cash dividends to be declared and paid, if any, will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our Revolving Credit Facility and our future business prospects.

Unconditional Purchase Obligations

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


Critical Accounting Estimates

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


New Accounting Pronouncements

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


ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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


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 March 31, 2022. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at March 31, 2022.

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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 March 31, 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 March 31, 2022:

Period
Total Number of Shares Purchased (a)
Average Price Paid per ShareTotal Number of Shares Purchased as Part of Publicly Announced Plans or ProgramsMaximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
January 1, 2021 - January 31, 2022111$70.57 — — 
February 1, 2022 - February 28, 202212,916$66.73 — — 
March 1, 2022 - March 31, 20223$68.49 — — 
Total13,030 $66.76 — — 
__________
(a)    Shares were acquired under the share withholding provisions of the Omnibus Incentive Plan for payment of taxes associated with the vesting of various equity compensation plans.


ITEM 4.    MINE SAFETY DISCLOSURES

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

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ITEM 6.        EXHIBITS

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

Exhibit NumberDescription
31.1*
31.2*
32.1*
32.2*
95*
101.INS*XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*XBRL Taxonomy Extension Schema Document
101.CAL*XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*XBRL Taxonomy Extension Label Linkbase Document
101.PRE*XBRL Taxonomy Extension Presentation Linkbase Document
104*Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)

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SIGNATURES


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

BLACK HILLS CORPORATION
/s/ Linden R. Evans
Linden R. Evans, President and
  Chief Executive Officer
/s/ Richard W. Kinzley
Richard W. Kinzley, Senior Vice President and
  Chief Financial Officer
Dated:May 5, 2022

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