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BKH Black Hills

Filed: 5 May 21, 12:00pm
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, 2021
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________.

Commission File Number 001-31303

Black Hills Corporation

Incorporated in South Dakota IRS Identification Number 46-0458824

7001 Mount Rushmore Road
Rapid City, South Dakota 57702
Registrant’s telephone number (605) 721-1700

Former name, former address, and former fiscal year if changed since last report
NONE

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

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

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large Accelerated 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 30, 2021
Common stock, $1.00 par value62,871,727 shares




















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3


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)
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 PowerBlack Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy). Also known as South Dakota Electric.
Black Hills Utility 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.
City of GilletteGillette, Wyoming
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).
Consolidated Indebtedness to Capitalization RatioAny indebtedness outstanding at such time, divided by capital at such time. Capital being consolidated net worth (excluding noncontrolling 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.
CorriedaleThe 52.5 MW wind farm near Cheyenne, Wyoming, jointly owned by South Dakota Electric and Wyoming Electric, serving as the dedicated wind energy supply to the Renewable Ready program.
COVID-19The official name for the 2019 novel coronavirus disease announced on February 11, 2020 by the World Health Organization, that is causing a global pandemic.
CP ProgramCommercial Paper Program
CPUCColorado Public Utilities Commission
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CVACredit Valuation Adjustment
DthDekatherm. A unit of energy equal to 10 therms or approximately one million British thermal units (MMBtu)
FASBFinancial Accounting Standards Board
FERCUnited States Federal Energy Regulatory Commission
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.
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
LIBORLondon Interbank Offered Rate
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)
NOLNet Operating Loss
NPSCNebraska Public Service Commission
OCIOther Comprehensive Income
PPAPower Purchase Agreement
PSAPower Sales Agreement
Pueblo Airport GenerationThe 420 MW combined cycle gas-fired power generation plants jointly owned by Colorado Electric (220 MW) and Black Hills Colorado IPP (200 MW). Black Hills Colorado IPP owns and operates this facility. The plants commenced operation on January 1, 2012.
Renewable AdvantageA 200 MW solar facility project to be constructed in Pueblo County, Colorado. The project aims to lower customer energy costs and provide economic and environmental benefits to Colorado Electric’s customers and communities. This project, which was approved by the CPUC in September 2020, will be owned by a third-party renewable energy developer with Colorado Electric purchasing all of the energy generated at the facility under the terms of a 15-year PPA. The project is expected to be placed in service in 2023.
Renewable 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 30, 2018, and now terminates on July 30, 2023.
SDPUCSouth Dakota Public Utilities Commission
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&PStandard and Poor’s, a division of The McGraw-Hill Companies, 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).
SSIRSystem Safety and Integrity Rider
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TCJATax Cuts and Jobs Act
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 extremely cold temperatures in the central United States and led to unprecedented fluctuations in customer demand and market pricing for natural gas and energy.
WRDCWyodak Resources Development Corporation, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings (doing business as Black Hills Energy)
Wygen IA mine-mouth, coal-fired power plant with a total capacity of 90 MW located at our Gillette, Wyoming energy complex. Black Hills Wyoming owns 76.5% of the facility and Municipal Energy Agency of Nebraska (MEAN) owns the remaining 23.5%.
Wyodak PlantThe 362 MW mine-mouth, coal-fired generation facility near Gillette, Wyoming, jointly owned by PacifiCorp (80%) and South Dakota Electric (20%). Our WRDC mine supplies all of the fuel for the facility.
Wyoming 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).

6


FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains 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. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 2 - Management’s Discussion & Analysis of Financial Condition and Results of Operations.

Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. Nonetheless, the Company’s expectations, beliefs or projections may not be achieved or accomplished.

Any forward-looking statement contained in this document speaks only as of the date the statement was made. The Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement was made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, such as the COVID-19 pandemic or Winter Storm Uri, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements described in our 2020 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our 2020 Annual Report on Form 10-K, Part II, Item 1A of this Quarterly Report on Form 10-Q and other reports that we file with the SEC from time to time.


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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,
20212020
(in thousands, except per share amounts)
Revenue$633,432 $537,050 
Operating expenses:
Fuel, purchased power and cost of natural gas sold293,147 187,879 
Operations and maintenance129,679 125,466 
Depreciation, depletion and amortization57,269 56,402 
Taxes - property and production15,022 14,118 
Total operating expenses495,117 383,865 
Operating income138,315 153,185 
Other income (expense):
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)(37,825)(35,781)
Interest income225 328 
Impairment of investment(6,859)
Other income (expense), net266 2,353 
Total other income (expense)(37,334)(39,959)
Income before income taxes100,981 113,226 
Income tax (expense)(494)(16,002)
Net income100,487 97,224 
Net income attributable to noncontrolling interest(4,171)(4,050)
Net income available for common stock$96,316 $93,174 
Earnings per share of common stock:
Earnings per share, Basic$1.54 $1.51 
Earnings per share, Diluted$1.54 $1.51 
Weighted average common shares outstanding:
Basic62,633 61,778 
Diluted62,691 61,856 

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.
8



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)Three Months Ended
March 31,
20212020
(in thousands)
Net income$100,487 $97,224 
Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (net of tax of $0 and $(17), respectively)55 
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $9 and $7, respectively)(16)(23)
Reclassification adjustments of benefit plan liability - net loss (net of tax of $(217) and $(95), respectively)381 502 
Derivative instruments designated as cash flow hedges:
Reclassification of net realized losses on settled/amortized interest rate swaps (net of tax of $(190) and $(170), respectively)523 543 
Net unrealized gains (losses) on commodity derivatives (net of tax of $(35) and $54, respectively)107 (175)
Reclassification of net realized losses on settled commodity derivatives (net of tax of $(8) and $(115), respectively)23 371 
Other comprehensive income, net of tax1,018 1,273 
Comprehensive income101,505 98,497 
Less: comprehensive income attributable to noncontrolling interest(4,171)(4,050)
Comprehensive income available for common stock$97,334 $94,447 

See Note 9 for additional disclosures.

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.
9



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)As of
March 31, 2021December 31, 2020
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents$13,442 $6,356 
Restricted cash and equivalents4,483 4,383 
Accounts receivable, net282,382 265,961 
Materials, supplies and fuel102,603 117,400 
Derivative assets, current1,917 1,848 
Income tax receivable, net18,115 19,446 
Regulatory assets, current129,951 51,676 
Other current assets25,722 26,221 
Total current assets578,615 493,291 
Property, plant and equipment7,415,818 7,305,530 
Less: accumulated depreciation and depletion(1,320,525)(1,285,816)
Total property, plant and equipment, net6,095,293 6,019,714 
Other assets:
Goodwill1,299,454 1,299,454 
Intangible assets, net11,649 11,944 
Regulatory assets, non-current672,306 226,582 
Other assets, non-current38,882 37,801 
Total other assets, non-current2,022,291 1,575,781 
TOTAL ASSETS$8,696,199 $8,088,786 

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.
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BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
(unaudited)As of
March 31, 2021December 31, 2020
(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable$160,179 $183,340 
Accrued liabilities230,444 243,612 
Derivative liabilities, current2,526 2,044 
Regulatory liabilities, current13,580 25,061 
Notes payable815,870 234,040 
Current maturities of long-term debt7,000 8,436 
Total current liabilities1,229,599 696,533 
Long-term debt, net of current maturities3,529,158 3,528,100 
Deferred credits and other liabilities:
Deferred income tax liabilities, net428,127 408,624 
Regulatory liabilities, non-current497,810 507,659 
Benefit plan liabilities150,979 150,556 
Other deferred credits and other liabilities135,224 134,667 
Total deferred credits and other liabilities1,212,140 1,201,506 
Commitments, contingencies and guarantees (Note 3)
00
Equity:
Stockholders’ equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 62,909,973 and 62,827,179 shares, respectively62,910 62,827 
Additional paid-in capital1,658,957 1,657,285 
Retained earnings931,538 870,738 
Treasury stock, at cost – 39,940 and 32,492 shares, respectively(2,564)(2,119)
Accumulated other comprehensive income (loss)(26,328)(27,346)
Total stockholders’ equity2,624,513 2,561,385 
Noncontrolling interest100,789 101,262 
Total equity2,725,302 2,662,647 
TOTAL LIABILITIES AND TOTAL EQUITY$8,696,199 $8,088,786 

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.
11



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)Three Months Ended March 31,
20212020
Operating activities:(in thousands)
Net income$100,487 $97,224 
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization57,269 56,402 
Deferred financing cost amortization2,214 2,237 
Impairment of investment6,859 
Stock compensation3,257 291 
Deferred income taxes153 21,876 
Employee benefit plans2,304 1,235 
Other adjustments, net6,151 892 
Changes in certain operating assets and liabilities:
Materials, supplies and fuel15,932 19,222 
Accounts receivable and other current assets(11,599)8,171 
Accounts payable and other current liabilities(23,602)(43,297)
Regulatory assets(533,006)20,679 
Regulatory liabilities(5,291)1,316 
Other operating activities, net(355)(1,138)
Net cash provided by (used in) operating activities(386,086)191,969 
Investing activities:
Property, plant and equipment additions(146,302)(171,882)
Other investing activities78 (1,202)
Net cash (used in) investing activities(146,224)(173,084)
Financing activities:
Dividends paid on common stock(35,514)(32,902)
Common stock issued99,321 
Term loan - borrowings800,000 
Term loan - repayments(200,000)
Net (payments) borrowings of Revolving Credit Facility and CP Program(18,170)(30,375)
Long-term debt - repayments(1,436)(4,291)
Distributions to noncontrolling interest(4,644)(4,741)
Other financing activities(740)(1,391)
Net cash provided by financing activities539,496 25,621 
Net change in cash, restricted cash and cash equivalents7,186 44,506 
Cash, restricted cash and cash equivalents at beginning of period10,739 13,658 
Cash, restricted cash and cash equivalents at end of period$17,925 $58,164 
Supplemental cash flow information:
Cash (paid) refunded during the period:
Interest, net of amounts capitalized$(21,232)$(21,776)
Income taxes990 
Non-cash investing and financing activities:
Accrued property, plant and equipment purchases at March 3151,914 53,011 

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, 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 (loss), 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 noncontrolling 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 

Common StockTreasury Stock
(in thousands except share amounts)SharesValueSharesValueAdditional Paid in CapitalRetained EarningsAOCINon controlling InterestTotal
December 31, 201961,480,658 $61,481 3,956 $(267)$1,552,788 $778,776 $(30,655)$101,946 $2,464,069 
Net income— — — — — 93,174 — 4,050 97,224 
Other comprehensive income (loss), net of tax— — — — — — 1,273 — 1,273 
Dividends on common stock ($0.535 per share)— — — — — (32,902)— — (32,902)
Share-based compensation69,378 69 20,700 (1,658)2,263 — — — 674 
Issuance of common stock1,222,942 1,223 — — 98,777 — — — 100,000 
Issuance costs— — — — (967)— — — (967)
Implementation of ASU 2016-13 Financial Instruments -- Credit Losses— — — — — (207)— — (207)
Distributions to noncontrolling interest— — — — — — — (4,741)(4,741)
March 31, 202062,772,978 $62,773 24,656 $(1,925)$1,652,861 $838,841 $(29,382)$101,255 $2,624,423 

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BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 2020 Annual Report on Form 10-K)


(1)    Management’s Statement

The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company”, “us”, “we” or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Condensed Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes included in our 2020 Annual Report on Form 10-K.

Segment Reporting

We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States.

Use of Estimates and Basis of Presentation

The information furnished in the accompanying Condensed Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the March 31, 2021, December 31, 2020 and March 31, 2020 financial information. Certain lines of business in which we operate are highly seasonal, and our interim results of operations are not necessarily indicative of the results of operations to be expected for an entire year.

COVID-19 Pandemic

In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the outbreak a national emergency. The U.S. government has deemed the electric and natural gas utilities to be critical infrastructure sectors that provide essential services during this emergency. As a provider of essential services, the Company has an obligation to provide services to our customers. The Company remains focused on protecting the health of our customers, employees and the communities in which we operate while assuring the continuity of our business operations.

The Company’s Condensed Consolidated Financial Statements reflect estimates and assumptions made by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Condensed Consolidated Financial Statements and reported amounts of revenue and expenses during the reporting periods presented. The Company considered the impacts of COVID-19 on the assumptions and estimates used and determined that for the three months ended March 31, 2021, there were no material adverse impacts on the Company’s results of operations.

Recently Issued Accounting Standards

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

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which was subsequently amended by ASU 2021-01. The standard provides relief for companies preparing for discontinuation of interest rates, such as LIBOR, and allows optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The amendments in this update are elective and are effective upon the ASU issuance through December 31, 2022. We are currently evaluating whether we will apply the optional guidance as we assess the impact of the discontinuance of LIBOR on our current arrangements and the potential impact on our financial position, results of operations and cash flows.



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Recently Adopted Accounting Standards

Simplifying the Accounting for Income Taxes, ASU 2019-12

In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes as part of its overall simplification initiative to reduce costs and complexity in applying accounting standards while maintaining or improving the usefulness of the information provided to users of the financial statements. Amendments include removal of certain exceptions to the general principles of ASC 740, Income Taxes, and simplification in several other areas such as accounting for a franchise tax (or similar tax) that is partially based on income. We adopted this standard prospectively on January 1, 2021. Adoption of this standard did not have an impact on our financial position, results of operations or cash flows.


(2)    Regulatory Matters

We had the following regulatory assets and liabilities (in thousands) as of:
As ofAs of
March 31, 2021December 31, 2020
Regulatory assets
Winter Storm Uri (a)
$480,842 $
Deferred energy and fuel cost adjustments (a) (b)
68,402 39,035 
Deferred gas cost adjustments (a) (b)
17,066 3,200 
Gas price derivatives (b)
324 2,226 
Deferred taxes on AFUDC (c)
7,469 7,491 
Employee benefit plans and related deferred taxes (d)
117,886 116,598 
Environmental (b)
1,413 1,413 
Loss on reacquired debt (b)
22,386 22,864 
Deferred taxes on flow through accounting (d)
51,823 47,515 
Decommissioning costs (c)
7,827 8,988 
Gas supply contract termination (b)
1,013 2,524 
Other regulatory assets (b)
25,806 26,404 
Total regulatory assets802,257 278,258 
   Less current regulatory assets(129,951)(51,676)
Regulatory assets, non-current$672,306 $226,582 
Regulatory liabilities
Deferred energy and gas costs (b)
$426 $13,253 
Employee benefit plan costs and related deferred taxes (d)
40,471 40,256 
Cost of removal (b)
177,003 172,902 
Excess deferred income taxes (d)
271,492 285,259 
Other regulatory liabilities (d)
21,998 21,050 
Total regulatory liabilities511,390 532,720 
   Less current regulatory liabilities(13,580)(25,061)
Regulatory liabilities, non-current$497,810 $507,659 
__________
(a)    We are in discussions with our regulators regarding the timing of Winter Storm Uri incremental cost recovery. See further information below.
(b)    Recovery of costs, but we are not allowed a rate of return.
(c)    In addition to recovery of costs, we are allowed a rate of return.
(d)    In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base.

Regulatory Activity

Except as discussed below, there have been no other significant changes to our Regulatory Matters from those previously disclosed in Note 2 of the Notes to the Consolidated Financial Statements in our 2020 Annual Report on Form 10-K.
15


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 significant 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, our net pre-tax incremental fuel, purchased power and natural gas costs during the three months ended March 31, 2021 were approximately $571 million. This amount does not include potential pipeline transportation charges for certain suppliers who have requested and received approval from FERC to delay billings.

Our Utilities have regulatory mechanisms to recover approximately $559 million of incremental costs from Winter Storm Uri. However, given the extraordinary impact of these higher costs to our customers, our regulators are performing a heightened review. We are engaged with our regulators to identify appropriate periods over which to recover incremental costs with consideration of the impacts to our customers’ bills. We expect to recover most of the Winter Storm Uri incremental costs through a separately tracked regulatory mechanism but we also anticipate recovery of a portion of the costs through existing mechanisms.

For the three months ended March 31, 2021, we expensed $12.5 million of Winter Storm Uri net incremental costs as a result of negative impacts to our Utilities and financing costs partially offset by favorable impacts to our Power Generation segment. Our Electric Utilities 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. Black Hills Energy Services offers fixed contract pricing for non-regulated gas supply services to our regulated natural gas customers and the $8.2 million increase in cost of natural gas sold during Winter Storm Uri is not recoverable through the regulatory construct. Additionally, we incurred $0.7 million of interest expense for the three months ended March 31, 2021, related to our $800 million term loan which is discussed in Note 5. Our non-regulated Power Generation segment benefited from a $1.7 million favorable impact to operating income from Winter Storm Uri.

Winter Storm Uri Costs by Jurisdiction

As of March 31, 2021, our estimate of incremental costs from Winter Storm Uri which was recorded to a regulatory asset is shown below by jurisdiction. This information is based on anticipated filings that we expect to complete in the second quarter of 2021 and is subject to adjustments as applications are submitted and final decisions are issued.

Costs by Jurisdiction(in thousands)
Gas Utilities:
Arkansas Gas$137,500 
Colorado Gas77,850 
Iowa Gas95,450 
Kansas Gas87,900 
Nebraska Gas79,750 
Wyoming Gas29,409 
Gas Utilities Total$507,859 
Electric Utilities:
Colorado Electric$25,500 
South Dakota Electric22,200 
Wyoming Electric3,266 
Electric Utilities Total$50,966 
Total Winter Storm Uri Incremental Costs Recorded to Regulatory Asset$558,825 
Costs by Regulatory Asset
Winter Storm Uri (a)
$480,842 
Deferred energy and fuel cost adjustments27,166 
Deferred gas cost adjustments (b)
50,817 
$558,825 
__________
(a)    We expect to recover most of the Winter Storm Uri incremental costs through a separately tracked regulatory mechanism but also expect to recover a portion through our existing mechanisms.
(b)    Incremental natural gas costs from Winter Storm Uri are reflected as an increase in the Deferred gas cost adjustments regulatory asset, net of existing Deferred energy and gas cost regulatory liabilities, for the three months ended March 31, 2021.
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TCJA

On December 30, 2020, an administrative law judge approved a settlement of Colorado Electric’s plan to provide $9.3 million of TCJA-related bill credits to its customers. The bill credits, which represent a disposition of excess deferred income tax benefits resulting from the TCJA, were delivered to customers in February 2021. These bill credits, which resulted in a reduction in revenue, were offset by a reduction in income tax expense and resulted in a minimal impact to Net Income for the three months ended March 31, 2021.

On January 26, 2021, the NPSC approved Nebraska Gas’s plan to provide $2.9 million of TCJA-related bill credits to its customers. The bill credits, which represent a disposition of excess deferred income tax benefits resulting from the TCJA, are expected to be delivered to customers in the second quarter of 2021. These bill credits, which will result in a reduction in revenue, will be offset by a reduction in income tax expense and will result in a minimal impact to Net income.

Colorado Gas

Rate Review

On September 11, 2020, Colorado Gas filed a rate review with the CPUC seeking recovery on significant infrastructure investments in its 7,000-mile natural gas pipeline system. On January 6, 2021, the CPUC issued an Order dismissing the rate review. Colorado Gas plans to file a rate review in the second quarter of 2021.

On September 11, 2020, in accordance with the final order from the earlier rate review filed February 1, 2019, Colorado Gas filed a SSIR proposal with the CPUC that would recover safety and integrity focused investments in its system for five years. A decision from the CPUC is expected by mid-2021.

Nebraska Gas

Jurisdictional Consolidation and Rate Review

On January 26, 2021, Nebraska Gas received approval from the NPSC to consolidate rate schedules into a new, single statewide structure and recover infrastructure investments in its 13,000-mile natural gas pipeline system. Final rates were enacted on March 1, 2021, which replaced interim rates effective September 1, 2020. The approval shifted $4.6 million of SSIR revenue to base rates and is expected to generate $6.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and an authorized return on equity of 9.5%. The approval also includes an extension of the SSIR for five years and an expansion of this mechanism across the consolidated jurisdictions.


(3)    Commitments, Contingencies and Guarantees

There have been no significant changes to commitments, contingencies and guarantees from those previously disclosed in Note 3 of our Notes to the Consolidated Financial Statements in our 2020 Annual Report on Form 10-K except for those described below.

Power Purchase Agreement - Colorado Electric Renewable Advantage

On February 19, 2021, Colorado Electric entered into a PPA with TC Colorado Solar, LLC to purchase up to 200 MW of renewable energy upon construction of a new solar facility, to be owned by TC Colorado Solar, LLC, which is expected to be completed by the end of 2023. This agreement will expire 15 years after construction completion. The solar project represents Colorado Electric’s preferred bid in a competitive solicitation process completed in September 2020 through its Renewable Advantage plan.


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(4)    Revenue

Our revenue contracts generally provide for performance obligations that are: fulfilled and transfer control to customers over time; represent a series of distinct services that are substantially the same; involve the same pattern of transfer to the customer; and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice. The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reportable segments for the three months ended March 31, 2021 and 2020. Sales tax and other similar taxes are excluded from revenues.
Three Months Ended March 31, 2021 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer types:(in thousands)
Retail$198,500 $341,605 $$14,083 $(7,107)$547,081 
Transportation47,951 (110)47,841 
Wholesale5,922 28,692 (24,451)10,163 
Market - off-system sales7,656 73 (2,884)4,845 
Transmission/Other15,193 10,390 (5,296)20,287 
Revenue from contracts with customers$227,271 $400,019 $28,692 $14,083 $(39,848)$630,217 
Other revenues137 2,500 471 589 (482)3,215 
Total revenues$227,408 $402,519 $29,163 $14,672 $(40,330)$633,432 
Timing of revenue recognition:
Services transferred at a point in time$$$$14,083 $(7,107)$6,976 
Services transferred over time227,271 400,019 28,692 (32,741)623,241 
Revenue from contracts with customers$227,271 $400,019 $28,692 $14,083 $(39,848)$630,217 

Three Months Ended March 31, 2020 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer Types:
Retail$148,640 $298,247 $$14,403 $(7,839)$453,451 
Transportation44,108 (139)43,969 
Wholesale5,552 25,467 (23,612)7,407 
Market - off-system sales4,867 138 (2,639)2,366 
Transmission/Other14,857 12,572 (4,413)23,016 
Revenue from contracts with customers$173,916 $355,065 $25,467 $14,403 $(38,642)$530,209 
Other revenues223 5,708 499 802 (391)6,841 
Total Revenues$174,139 $360,773 $25,966 $15,205 $(39,033)$537,050 
Timing of Revenue Recognition:
Services transferred at a point in time$$$$14,403 $(7,839)$6,564 
Services transferred over time173,916 355,065 25,467 (30,803)523,645 
Revenue from contracts with customers$173,916 $355,065 $25,467 $14,403 $(38,642)$530,209 

Contract Balances

The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable further discussed in Note 13.

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(5)    Financing

Short-term debt

We had the following Notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
March 31, 2021December 31, 2020
Balance Outstanding
Letters of Credit (a)
Balance Outstanding
Letters of Credit (a)
Term Loan$600,000 $$$
Revolving Credit Facility16,629 24,730 
CP Program215,870 234,040 
Total Notes payable$815,870 $16,629 $234,040 $24,730 
_______________
(a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility.

Term Loan

On February 24, 2021, we entered into a nine-month, $800 million unsecured term loan to provide additional liquidity and meet our cash needs related to the incremental fuel, purchased power and natural gas costs from Winter Storm Uri. The term loan, which matures on November 24, 2021, has an interest rate based on LIBOR plus 75 basis points, carries 0 prepayment penalty and is subject to the same covenant requirements as our Revolving Credit Facility. We repaid $200 million of this term loan in the first quarter of 2021. The interest rate on term loan borrowings on March 31, 2021 was 0.86%.

We expect to refinance a portion of the term loan with longer-term debt prior to maturity. In the event we are unable to refinance the remaining obligation, we believe it is probable that our current plans to manage liquidity would be sufficient to meet our obligations.

Revolving Credit Facility and CP Program

Our net short-term borrowings related to our Revolving Credit Facility and CP Program during the three months ended March 31, 2021 decreased by $18 million. The weighted average interest rate on short-term borrowings related to our Revolving Credit Facility and CP Program at March 31, 2021 was 0.23%.

Debt Covenants

Under our Revolving Credit Facility and term loan agreements, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Our Consolidated Indebtedness to Capitalization Ratio was calculated by dividing (i) consolidated indebtedness, which includes letters of credit and certain guarantees issued, by (ii) capital, which includes consolidated indebtedness plus consolidated net worth, which excludes noncontrolling interest in subsidiaries. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding.

Our Revolving Credit Facility and term loans require compliance with the following financial covenant, which we were in compliance with at March 31, 2021:
As of March 31, 2021Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio62.6%Less than65%



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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):
Three Months Ended March 31,
20212020
Net income available for common stock$96,316 $93,174 
Weighted average shares - basic62,633 61,778 
Dilutive effect of:
Equity compensation58 78 
Weighted average shares - diluted62,691 61,856 
Earnings per share of common stock:
Earnings per share, Basic$1.54 $1.51 
Earnings per share, Diluted$1.54 $1.51 

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,
20212020
Equity compensation14 12 
Restricted stock19 26 
Anti-dilutive shares33 38 


(7)    Risk Management and Derivatives

Market and Credit Risk Disclosures

Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk.

Market Risk

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

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

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

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 customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience, changes in current market conditions, expected losses and any specific customer collection issue that is identified.

Derivatives and Hedging Activity

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

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

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

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

We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risk using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and sales during time frames ranging from April 2021 through August 2023. 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, 2021December 31, 2020
UnitsNotional
Amounts
Maximum
Term
(months) (a)
Notional
Amounts
Maximum
Term
(months) (a)
Natural gas futures purchasedMMBtus0620,000 3
Natural gas options purchased, netMMBtus03,160,000 3
Natural gas basis swaps purchasedMMBtus0900,000 3
Natural gas over-the-counter swaps, net (b)
MMBtus3,590,000 293,850,000 17
Natural gas physical contracts, net (c)
MMBtus3,107,817 1217,513,061 22
Electric wholesale contracts (c)
MWh183,025 9219,000 12
__________
(a)    Term reflects the maximum forward period hedged.
(b)    As of March 31, 2021, 442,900 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, 2021, the Company posted $1.4 million related to such provisions, which is included in Other current assets on the Condensed Consolidated Balance Sheets.

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Derivatives by Balance Sheet Classification

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

The following table presents the fair value and balance sheet classification of our derivative instruments (in thousands) as of:
Balance Sheet LocationMarch 31, 2021December 31, 2020
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivativesDerivative assets, current$285 $181 
Noncurrent commodity derivativesOther assets, non-current43 
Liability derivative instruments:
Current commodity derivativesDerivative liabilities, current(108)
Noncurrent commodity derivativesOther deferred credits and other liabilities
Total derivatives designated as hedges$289 $116 
Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivativesDerivative assets, current$1,632 $1,667 
Noncurrent commodity derivativesOther assets, non-current32 151 
Liability derivative instruments:
Current commodity derivativesDerivative liabilities, current(2,526)(1,936)
Noncurrent commodity derivativesOther deferred credits and other liabilities(43)
Total derivatives not designated as hedges$(905)$(118)

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, 2021 and 2020. Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.
Three Months Ended March 31,Three Months Ended March 31,
2021202020212020
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 derivatives173 257 Fuel, purchased power and cost of natural gas sold(31)(486)
Total$886 $970 $(744)$(1,199)

As of March 31, 2021, $0.9 million of net losses related to our interest rate swaps and commodity derivatives are expected to be reclassified from AOCI into earnings within the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

22


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, 2021 and 2020. Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.
Three Months Ended March 31,
20212020
Derivatives Not Designated as Hedging InstrumentsIncome Statement LocationAmount of Gain/(Loss) on Derivatives Recognized in Income
(in thousands)
Commodity derivatives - ElectricFuel, purchased power and cost of natural gas sold$(1,524)$1,362 
Commodity derivatives - Natural GasFuel, purchased power and cost of natural gas sold366 766 
$(1,158)$2,128 

As discussed above, financial instruments used in our regulated Gas Utilities are not designated as cash flow hedges. There is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory asset or Regulatory liability related to the hedges in our Gas Utilities were $0.3 million and $2.2 million as of March 31, 2021 and December 31, 2020, respectively. For our Electric Utilities, the unrealized gains and losses arising from these derivatives are recognized in the Condensed Consolidated Statements of Income.


(8)    Fair Value Measurements

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

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

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

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

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

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

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Recurring Fair Value Measurements

Derivatives

The commodity contracts for our Utilities segments are valued using the market approach and include forward strip pricing at liquid delivery points, exchange-traded futures, options, basis swaps and over-the-counter swaps and options (Level 2) for wholesale electric energy and natural gas contracts. For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable contract. For over-the-counter instruments, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a CVA based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position. For additional information, see Note 1 of our Notes to the Consolidated Financial Statements in our 2020 Annual Report on Form 10-K.
As of March 31, 2021
Level 1Level 2Level 3Cash Collateral and Counterparty
Netting
Total
(in thousands)
Assets:
Commodity derivatives — Gas Utilities$$1,389 $$$1,389 
Commodity derivatives — Electric Utilities$$564 $$$564 
Total$$1,953 $$$1,953 
Liabilities:
Commodity derivatives — Gas Utilities$$625 $$$625 
Commodity derivatives — Electric Utilities$$1,944 $$$1,944 
Total$$2,569 $$$2,569 

As of December 31, 2020
Level 1Level 2Level 3Cash Collateral and Counterparty
Netting
Total
(in thousands)
Assets:
Commodity derivatives — Gas Utilities$$2,504 $$(1,527)$977 
Commodity derivatives — Electric Utilities$$1,065 $$$1,065 
Total$$3,569 $$(1,527)$2,042 
Liabilities:
Commodity derivatives — Gas Utilities$$2,675 $$(1,552)$1,123 
Commodity derivatives — Electric Utilities$$921 $$$921 
Total$$3,596 $$(1,552)$2,044 

Pension and Postretirement Plan Assets

Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about the fair value measurements of their assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 15 to the Consolidated Financial Statements included in our 2020 Annual Report on Form 10-K.

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Other fair value measures

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

The following table presents the carrying amounts and fair values of financial instruments not recorded at fair value on the Condensed Consolidated Balance Sheets (in thousands) as of:
March 31, 2021December 31, 2020
Carrying
Amount
Fair ValueCarrying
Amount
Fair Value
Long-term debt, including current maturities (a)
$3,536,158 $3,938,977 $3,536,536 $4,208,167 
__________
(a)    Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified as Level 2 in the fair value hierarchy. Carrying amount of long-term debt is net of deferred financing costs.


(9)    Other Comprehensive Income

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

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

Location on the Condensed Consolidated Statements of IncomeAmount Reclassified from AOCI
Three Months Ended March 31,
20212020
Gains and (losses) on cash flow hedges:
Interest rate swapsInterest expense$(713)$(713)
Commodity contractsFuel, purchased power and cost of natural gas sold(31)(486)
(744)(1,199)
Income taxIncome tax benefit198 285 
Total reclassification adjustments related to cash flow hedges, net of tax$(546)$(914)
Amortization of components of defined benefit plans:
Prior service costOperations and maintenance$25 $30 
Actuarial gain (loss)Operations and maintenance(598)(597)
(573)(567)
Income taxIncome tax benefit208 88 
Total reclassification adjustments related to defined benefit plans, net of tax$(365)$(479)
Total reclassifications$(911)$(1,393)
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Balances by classification included within AOCI, net of tax on the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):
Derivatives Designated as Cash Flow Hedges
Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
As of December 31, 2020$(12,558)$$(14,790)$(27,346)
Other comprehensive income (loss)
before reclassifications107 107 
Amounts reclassified from AOCI523 23 365 911 
As of March 31, 2021$(12,035)$132 $(14,425)$(26,328)
Derivatives Designated as Cash Flow Hedges
Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
As of December 31, 2019$(15,122)$(456)$(15,077)$(30,655)
Other comprehensive income (loss)
before reclassifications(175)55 (120)
Amounts reclassified from AOCI543 371 479 1,393 
As of March 31, 2020$(14,579)$(260)$(14,543)$(29,382)


(10)    Employee Benefit Plans

Defined Benefit Pension Plan

The components of net periodic benefit cost for the Defined Benefit Pension Plan were as follows (in thousands):
Three Months Ended March 31,
20212020
Service cost$1,259 $1,353 
Interest cost2,328 3,357 
Expected return on plan assets(5,219)(5,648)
Net loss (gain)1,829 2,093 
Net periodic benefit cost$197 $1,155 

Defined Benefit Postretirement Healthcare Plan

The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plan were as follows (in thousands):
Three Months Ended March 31,
20212020
Service cost$559 $514 
Interest cost265 412 
Expected return on plan assets(34)(45)
Prior service cost (benefit)(109)(137)
Net loss (gain)117 
Net periodic benefit cost$798 $749 

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Supplemental Non-qualified Defined Benefit and Defined Contribution Plans

The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands):
Three Months Ended March 31,
20212020
Service cost$693 $(1,370)
Interest cost177 275 
Net loss (gain)439 426 
Net periodic benefit cost$1,309 $(669)

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 quarter of 2021 and anticipated contributions for 2021 and 2022 are as follows (in thousands):
Contributions MadeAdditional ContributionsContributions
Three Months Ended March 31, 2021Anticipated for 2021Anticipated for 2022
Defined Benefit Pension Plan$$$3,788 
Non-pension Defined Benefit Postretirement Healthcare Plan$1,382 $4,145 $5,241 
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans$482 $1,445 $1,967 


(11)    Income Taxes

Winter Storm Uri

As discussed in Note 2 above, $559 million of the incremental costs from Winter Storm Uri are recoverable through our Utilities’ regulatory mechanisms, and we recorded these costs as regulatory assets at March 31, 2021. We expect to recover these costs from customers over several years. Winter Storm Uri costs, which will be deductible in our 2021 tax return, created a net deferred tax liability of approximately $132 million at March 31, 2021. The deferred tax liability will reverse with the same timing as the costs are recovered from our customers.

The income tax deduction recognized from Winter Storm Uri will create an NOL in our 2021 federal and state income tax returns. Our federal NOL carryforwards no longer expire due to the TCJA; however, our state NOL carryforwards expire at various dates from 2021 to 2040. We do not anticipate material changes to our valuation allowance against the state NOL carryforwards from Winter Storm Uri. Therefore, we did not record an additional valuation allowance against the state NOL carryforwards as of March 31, 2021.

Income Tax Benefit (Expense) and Effective Tax Rates

Three Months Ended March 31, 2021 Compared to the Three Months Ended March 31, 2020

Income tax (expense) for the three months ended March 31, 2021 was $(0.5) million compared to $(16) million reported for the same period in 2020. For the three months ended March 31, 2021 the effective tax rate was 0.5% compared to 14.1% for the same period in 2020. The lower effective tax rate is primarily due to $7.6 million of increased tax benefits from Colorado Electric’s TCJA-related bill credits to customers (which is offset by reduced revenue), $1.5 million of increased tax benefits from amortization of excess deferred income taxes and $1.3 million of increased tax benefits from federal production tax credits associated with new wind assets.


27


(12)    Business Segment Information

Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States.

Accounting standards for presentation of segments require an approach based on the way we organize the segments for making operating decisions and how the Chief Operating Decision Maker (CODM) assesses performance. The CODM assesses the performance of our segments using adjusted operating income, which recognizes intersegment revenues, costs, and assets for Colorado Electric’s PPA with Black Hills Colorado IPP on an accrual basis rather than as a finance lease. This presentation of segment information does not impact consolidated financial results.

Segment information was as follows (in thousands):
Total assets (net of intercompany eliminations) as of:March 31, 2021December 31, 2020
Electric Utilities$3,217,474 $3,120,928 
Gas Utilities4,900,939 4,376,204 
Power Generation406,742 404,220 
Mining76,097 77,085 
Corporate and Other94,947 110,349 
Total assets$8,696,199 $8,088,786 

Three Months Ended March 31, 2021External Operating RevenueInter-company Operating RevenueTotal Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities$220,500 $137 $6,771 $$227,408 
Gas Utilities398,499 2,408 1,520 92 402,519 
Power Generation4,241 421 24,451 50 29,163 
Mining6,977 249 7,106 340 14,672 
Inter-company eliminations— — (39,848)(482)(40,330)
Total$630,217 $3,215 $$$633,432 

Three Months Ended March 31, 2020External Operating RevenueInter-company Operating Revenue Total Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities$167,503 $223 $6,413 $$174,139 
Gas Utilities354,287 5,708 778 360,773 
Power Generation1,855 443 23,612 56 25,966 
Mining6,564 467 7,839 335 15,205 
Inter-company eliminations— — (38,642)(391)(39,033)
Total$530,209 $6,841 $$$537,050 
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Three Months Ended March 31,
20212020
Adjusted operating income:
Electric Utilities$21,813 $35,650 
Gas Utilities102,094 102,897 
Power Generation14,269 11,349 
Mining3,261 3,129 
Corporate and Other(3,122)160 
Operating income138,315 153,185 
Interest expense, net(37,600)(35,453)
Impairment of investment(6,859)
Other income (expense), net266 2,353 
Income tax (expense)(494)(16,002)
Net income100,487 97,224 
Net income attributable to noncontrolling interest(4,171)(4,050)
Net income available for common stock$96,316 $93,174 


(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, 2021December 31, 2020
Accounts receivable, trade$199,548 $146,899 
Unbilled revenue91,085 126,065 
Less: Allowance for credit losses(8,251)(7,003)
Accounts receivable, net$282,382 $265,961 

Changes to allowance for credit losses for the three months ended March 31, 2021 and 2020, respectively, were as follows (in thousands):

Balance at Beginning of YearAdditions Charged to Costs and ExpensesRecoveries and Other AdditionsWrite-offs and Other DeductionsBalance at March 31,
2021$7,003 $1,877 $1,014 $(1,643)$8,251 
2020$2,444 $3,519 $922 $(1,723)$5,162 

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, 2021December 31, 2020
Materials and supplies$88,088 $85,250 
Fuel - Electric Utilities1,590 1,531 
Natural gas in storage12,925 30,619 
Total materials, supplies and fuel$102,603 $117,400 

29


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, 2021December 31, 2020
Accrued employee compensation, benefits and withholdings$57,347 $77,806 
Accrued property taxes49,267 47,105 
Customer deposits and prepayments50,194 52,185 
Accrued interest45,896 31,520 
Other (none of which is individually significant)27,740 34,996 
Total accrued liabilities$230,444 $243,612 


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

The following discussions should be read in conjunction with the Notes contained herein and Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in the 2020 Form 10-K.


Executive Summary

We are a customer-focused, growth-oriented electric and natural gas utility company with a mission of Improving Life with Energy and a vision to be the Energy Partner of Choice. The Company provides electric and natural gas utility service to 1.3 million customers over 800 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming.

Recent Developments

Winter Storm Uri

In February 2021, a prolonged period of historic cold temperatures across the central United States, which covered all of our Utilities’ service territories, caused a significant 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, our net pre-tax incremental fuel, purchased power and natural gas costs during the three months ended March 31, 2021 were approximately $571 million. This amount does not include potential pipeline transportation charges from certain suppliers who have requested and received approval from the FERC to delay billings. The pre-tax incremental costs for the three months ended March 31, 2021 from Winter Storm Uri were as follows:
(in millions)
Incremental fuel, purchased power and natural gas costs recorded to regulatory assets$558.8 
Electric Utilities wholesale power margin sharing$3.2 
Electric Utilities non-recoverable fuel costs2.1 
Black Hills Energy Services non-recoverable natural gas costs8.2 
Interest expense from $800 million term loan0.7 
Less Power Generation favorable net impact(1.7)
Incremental costs recorded as expenses, net$12.5 
Total incremental costs related to Winter Storm Uri, net$571.3 

On February 24, 2021, we entered into a nine-month, $800 million unsecured term loan to provide additional liquidity and meet our cash needs related to the incremental fuel, purchased power and natural gas costs from Winter Storm Uri. The nine-month term loan has no prepayment penalty and is subject to the same covenants as our Revolving Credit Facility. As of March 31, 2021, we have repaid $200 million of this term loan and expect to refinance a portion with longer-term debt later in 2021. See Note 5 of the Notes to Condensed Consolidated Financial Statements for additional term loan information.

30


Our Utilities have regulatory mechanisms to recover approximately $559 million of incremental costs from Winter Storm Uri. However, given the extraordinary impact of these higher costs to our customers, our regulators are performing a heightened review. We are engaged with our regulators to determine appropriate recovery periods for Winter Storm Uri incremental costs with consideration of the impacts to our customers’ bills. Our estimate of the recoverable incremental costs is based on anticipated filings that we expect to complete in the second quarter of 2021 and is subject to adjustments as applications are submitted and final decisions are issued. See Note 2 of the Notes to Condensed Consolidated Financial Statements for information regarding estimated Winter Storm Uri incremental costs by jurisdiction.

For the three months ended March 31, 2021, we expensed $12.5 million of Winter Storm Uri net incremental costs as a result of negative impacts to our Utilities and financing costs partially offset by favorable impacts to our Power Generation segment. Our Electric Utilities incurred a $3.2 million negative impact to 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. Black Hills Energy Services offers fixed contract pricing for non-regulated gas supply services to our regulated natural gas customers and $8.2 million of increased cost of natural gas sold during Winter Storm Uri is not recoverable through the regulatory construct. Additionally, we incurred $0.7 million of interest expense for the three months ended March 31, 2021, related to our $800 million term loan. Our non-regulated Power Generation segment benefited from a $1.7 million favorable impact to operating income from Winter Storm Uri. We expect opportunities in 2021 to mitigate these negative impacts through cost management and regulatory actions.

COVID-19 Update

For the three months ended March 31, 2021, we did not experience significant impacts to our financial results, liquidity or operational activities due to COVID-19. We continue to monitor loads, customers’ ability to pay, the potential for supply chain disruption that may impact our capital and maintenance project plans, the availability of third-party resources to execute our business plans and the capital markets to ensure we have the liquidity necessary to support our financial needs. State orders lifting temporarily suspended disconnections have been issued in all of our jurisdictions.

We continue to provide periodic status updates and maintain ongoing dialogue with the regulatory commissions in our jurisdictions regarding our right to preserve deferred regulatory treatment for certain COVID-19 related costs and to seek recovery of these costs at a later date.

As we look forward, our operating results from COVID-19 could be affected as discussed in the “Risk Factors” section in Part I, Item 1A of our 2020 Annual Report on Form 10-K.

Business Segment Highlights and Corporate Activity

Electric Utilities Segment

On February 19, 2021, Colorado Electric entered into a PPA with TC Colorado Solar, LLC to purchase up to 200 MW of renewable energy upon construction of a new solar facility, to be owned by TC Colorado Solar, LLC, which is expected to be completed by the end of 2023. This agreement will expire 15 years after construction completion. The utility-scale solar project represents Colorado Electric’s preferred bid in a competitive solicitation process completed in September 2020 through its Renewable Advantage plan. With the addition of 200 MW of solar energy on its system, more than half of the Colorado Electric’s generation is forecasted to be sourced from renewable energy resources by 2023, leading to a 70% reduction in carbon emissions by 2024 compared to the 2005 base year.

On February 11, 2021, South Dakota Electric set a new winter peak load of 326 MW, surpassing the previous winter peak of 320 MW set in February 2019.

Gas Utilities Segment

On January 26, 2021, Nebraska Gas received approval from the NPSC to consolidate rate schedules into a new, single statewide structure and recover infrastructure investments in its 13,000-mile natural gas pipeline system. Final rates were enacted on March 1, 2021 and are expected to generate $6.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and an authorized return on equity of 9.5%. The approval also includes an extension of the SSIR for five years and an expansion of this mechanism across the consolidated jurisdictions.

On September 11, 2020, Colorado Gas filed a rate review with the CPUC seeking recovery on infrastructure investments in its 7,000-mile natural gas pipeline system. On January 6, 2021, the CPUC issued an Order dismissing the rate review. Colorado Gas plans to file a rate review in the second quarter of 2021.

On September 11, 2020, in accordance with the final order from the earlier rate review filed February 1, 2019, Colorado Gas filed a SSIR proposal with the CPUC that would recover safety and integrity focused investments in its system for five years. A decision from the CPUC is expected by mid-2021.


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Results of Operations

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

Certain lines of business in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements. In particular, the normal peak usage season for our Electric Utilities is June through August while the normal peak usage season for our Gas Utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three months ended March 31, 2021 and 2020, and our financial condition as of March 31, 2021 and December 31, 2020, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period or for the entire year.

Consolidated Summary and Overview
Three Months Ended March 31,
20212020
(in thousands except per share amounts)
Adjusted operating income (a)
Electric Utilities$21,813 $35,650 
Gas Utilities102,094 102,897 
Power Generation14,269 11,349 
Mining3,261 3,129 
Corporate and Other(3,122)160 
Operating income138,315 153,185 
Interest expense, net(37,600)(35,453)
Impairment of investment— (6,859)
Other income (expense), net266 2,353 
Income tax (expense)(494)(16,002)
Net income100,487 97,224 
Net income attributable to noncontrolling interest(4,171)(4,050)
Net income available for common stock96,316 93,174 
Total earnings per share of common stock, Diluted$1.54 $1.51 
__________
(a)    Adjusted operating income recognizes intersegment revenues and costs for Colorado Electric’s PPA with Black Hills Colorado IPP on an accrual basis rather than as a finance lease. This presentation of segment information does not impact consolidated financial results.

Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020

The variance to the prior year included the following:

Electric Utilities’ adjusted operating income decreased $14 million primarily due to Colorado Electric’s TCJA-related bill credits to customers, impacts from Winter Storm Uri and unfavorable mark-to-market adjustments on wholesale energy contracts partially offset by increased rider revenues and lower operating expenses;
Gas Utilities’ adjusted operating income decreased $0.8 million primarily due to Winter Storm Uri costs incurred by Black Hills Energy Services and higher operating expenses mostly offset by new rates and higher heating demand from colder winter weather;
Power Generation’s adjusted operating income increased $2.9 million primarily due to favorable impacts from Winter Storm Uri;
Corporate and Other expenses increased $3.3 million primarily due to a prior year favorable true-up of employee costs allocated to our subsidiaries in the current year, which is offset in our reportable segments;
A $2.1 million increase in interest expense due to higher debt balances partially offset by lower rates;
A prior year $6.9 million pre-tax non-cash impairment of our investment in equity securities of a privately held oil and gas company;
32


A $2.1 million decrease in other income primarily due to prior year credits for our non-qualified benefit plan driven by market performance on plan assets; and
A $15.5 million decrease in income tax expense due to lower pre-tax income and a lower effective tax rate driven primarily by tax benefits from Colorado Electric’s TCJA-related bill credits, amortization of excess deferred income taxes and federal production tax credits associated with new wind assets.

Segment Operating Results

A discussion of operating results from our business segments follows.


Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, gross margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of depreciation and amortization from the measure. The presentation of gross margin is intended to supplement investors’ understanding of our operating performance.

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

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


Electric Utilities

Operating results for the Electric Utilities were as follows (in thousands):
Three Months Ended March 31,
20212020Variance
Revenue$227,408 $174,139 $53,269 
Total fuel and purchased power132,069 64,460 67,609 
Gross margin (non-GAAP)95,339 109,679 (14,340)
Operations and maintenance48,577 50,499 (1,922)
Depreciation and amortization24,949 23,530 1,419 
Total operating expenses73,526 74,029 (503)
Adjusted operating income$21,813 $35,650 $(13,837)

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Three Months Ended March 31, 2021 Compared to the Three Months Ended March 31, 2020:

Gross margin for the three months ended March 31, 2021 decreased as a result of the following:
(in millions)
TCJA-related bill credits (a)
$(9.3)
Winter Storm Uri impacts (b)
(5.3)
Mark-to-market on wholesale energy contracts(2.9)
Rider recovery1.3 
Weather1.1 
Residential customer growth0.3 
Other0.5 
Total change in Gross margin (non-GAAP)$(14.3)
________________
(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, our Electric Utilities 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.

Operations and maintenance expense decreased primarily due to prior year expenses related to the municipalization efforts in Pueblo, Colorado.

Depreciation and amortization increased primarily due to a higher asset base driven by prior year capital expenditures.
Operating Statistics
Revenue (in thousands)Quantities Sold (MWh)
Three Months Ended
March 31,
Three Months Ended
March 31,
2021202020212020
Residential$72,760 $54,505 396,086 373,150 
Commercial77,007 57,823 492,955 494,308 
Industrial43,009 32,169 415,191 460,632 
Municipal5,020 3,878 36,242 36,399 
Subtotal Retail Revenue - Electric197,796 148,375 1,340,474 1,364,489 
Contract Wholesale (a)
8,465 5,553 156,995 131,778 
Off-system/Power Marketing Wholesale5,113 4,867 127,583 165,785 
Other16,034 15,344 — — 
Total Revenue and Energy Sold227,408 174,139 1,625,052 1,662,052 
Other Uses, Losses or Generation, net— — 130,975 90,871 
Total Revenue and Energy227,408 174,139 1,756,027 1,752,923 
Less cost of fuel and purchased power132,069 64,460 
Gross Margin (non-GAAP)$95,339 $109,679 
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Three Months Ended March 31,Revenue
(in thousands)
Gross Margin (non-GAAP) (in thousands)
Quantities Sold (MWh)(a)
202120202021202020212020
Colorado Electric$79,741 $58,558 $24,091 $32,270 606,343 550,771 
South Dakota Electric95,336 71,611 49,550 55,624 657,779 685,224 
Wyoming Electric52,331 43,970 21,698 21,785 491,905 516,928 
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold$227,408 $174,139 $95,339 $109,679 1,756,027 1,752,923 
________________
(a)    Includes company uses, line losses, and excess exchange production.
Three Months Ended
March 31,
Quantities Generated and Purchased (MWh)20212020
Generated:
Coal482,978 547,829 
Natural Gas and Oil132,105 167,744 
Wind62,295 73,550 
Total Generated677,378 789,123 
Purchased1,078,649 963,800 
Total Generated and Purchased1,756,027 1,752,923 

Three Months Ended
March 31,
Quantities Generated and Purchased (MWh)20212020
Generated:
Colorado Electric90,256 94,051 
South Dakota Electric434,322 472,966 
Wyoming Electric152,800 222,106 
Total Generated677,378 789,123 
Purchased:
Colorado Electric516,087 456,720 
South Dakota Electric223,457 212,258 
Wyoming Electric339,105 294,822 
Total Purchased1,078,649 963,800 
Total Generated and Purchased1,756,027 1,752,923 
Three Months Ended March 31,
20212020
Heating Degree DaysActualVariance from
Normal
ActualVariance from
Normal
Colorado Electric2,731 %2,456 (7)%
South Dakota Electric3,324 %3,111 (3)%
Wyoming Electric3,261 %2,999 (1)%
Combined (a)
3,040 %2,789 (4)%
____________________
(a)    Combined actuals are calculated based on the weighted average number of total customers by state.
35



Three Months Ended March 31,
Contracted generating facilities availability by fuel type (a)
20212020
Coal (b)
83.7 %90.8 %
Natural Gas and diesel oil (b) (c)
87.6 %83.5 %
Wind93.5 %99.0 %
Total availability87.2 %87.1 %
Wind capacity factor43.1 %45.6 %
____________________
(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.
(c)    2020 included an unplanned outage at Pueblo Airport Generation.


Gas Utilities

Operating results for the Gas Utilities were as follows (in thousands):
Three Months Ended March 31,
20212020Variance
Revenue:
Natural gas - regulated$378,077 $335,897 $42,180 
Other - non-regulated services24,442 24,876 (434)
Total revenue402,519 360,773 41,746 
Cost of sales:
Natural gas - regulated182,967 153,999 28,968 
Other - non-regulated services10,083 1,363 8,720 
Total cost of sales193,050 155,362 37,688 
Gross margin (non-GAAP)209,469 205,411 4,058 
Operations and maintenance82,200 77,293 4,907 
Depreciation and amortization25,175 25,221 (46)
Total operating expenses107,375 102,514 4,861 
Adjusted operating income$102,094 $102,897 $(803)

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Three Months Ended March 31, 2021 Compared to the Three Months Ended March 31, 2020

Gross margin for the three months ended March 31, 2021 increased as a result of:
(in millions)
New rates$9.2 
Weather7.5 
Black Hills Energy Services Winter Storm Uri costs (a)
(8.2)
Non-utility Gas Supply Services(1.2)
Mark-to-market on non-utility natural gas commodity contracts(0.4)
Other(2.8)
Total increase in Gross margin (non-GAAP)$4.1 
__________
(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 is not recoverable through a regulatory mechanism.

Operations and maintenance expense increased primarily due to $5.5 million of higher employee related costs and outside services expenses driven by higher headcount and higher stock compensation expense related to market performance partially offset by $1.0 million of lower travel and training expenses.

Depreciation and amortization was comparable to the same period in the prior year due to lower depreciation rates approved in the Nebraska Gas and Colorado Gas rate reviews mostly offset by increased depreciation due to a higher asset base driven by prior year capital expenditures.
Operating Statistics
Revenue
(in thousands)
Gross Margin (non-GAAP)
(in thousands)
Quantities Sold & Transported (Dth)
Three Months Ended
March 31,
Three Months Ended
March 31,
Three Months Ended
March 31,
202120202021202020212020
Residential$234,397 $207,231 $110,148 $103,121 30,568,738 28,230,795 
Commercial91,089 80,236 35,484 33,519 13,812,321 12,834,803 
Industrial4,902 5,200 1,789 2,043 898,289 1,061,052 
Other(472)(1,242)(472)(1,242)— — 
Total Distribution329,916 291,425 146,949 137,441 45,279,348 42,126,650 
Transportation and Transmission48,161 44,472 48,161 44,457 45,314,438 45,055,507 
Total Regulated378,077 335,897 195,110 181,898 90,593,786 87,182,157 
Non-regulated Services24,442 24,876 14,359 23,513 
Total Gas Revenue & Gross Margin (non-GAAP)$402,519 $360,773 $209,469 $205,411 
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Revenue
(in thousands)
Gross Margin (non-GAAP)
(in thousands)
Gas Utilities Quantities Sold & Transported (Dth)
Three Months Ended
March 31,
Three Months Ended
March 31,
Three Months Ended
March 31,
202120202021202020212020
Arkansas Gas$86,994 $74,845 $51,949 $48,855 13,306,734 10,962,948 
Colorado Gas79,122 72,606 38,212 38,006 13,366,015 13,096,405 
Iowa Gas56,754 54,824 22,631 21,328 14,313,973 14,280,273 
Kansas Gas40,063 33,494 18,766 18,603 10,462,797 9,914,858 
Nebraska Gas93,098 83,666 49,932 51,666 27,284,101 26,509,036 
Wyoming Gas46,488 41,338 27,979 26,953 11,860,166 12,418,637 
Total Gas Revenue & Gross Margin (non-GAAP)$402,519 $360,773 $209,469 $205,411 90,593,786 87,182,157 
Three Months Ended March 31,
20212020
Heating Degree Days:ActualVariance
from Normal
ActualVariance
from Normal
Arkansas Gas (a)
2,1211%1,659(21)%
Colorado Gas2,9651%2,829(3)%
Iowa Gas3,4221%3,181(6)%
Kansas Gas (a)
2,5765%2,304(7)%
Nebraska Gas3,0972%2,835(7)%
Wyoming Gas3,4257%3,2171%
Combined Gas (b)
3,1863%2,918(6)%
__________
(a)    Arkansas and Kansas 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 due to its weather normalization mechanism. Arkansas is partially excluded based on the weather normalization mechanism in effect from November through April.


Regulatory Matters

For more information on recent regulatory activity and enacted regulatory provisions with respect to the states in which our Utilities operate, see Note 2 of the Notes to Condensed Consolidated Financial Statements and Part I, Items 1 and 2 and Part II, Item 8 of our 2020 Annual Report on Form 10-K.


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Power Generation

Our Power Generation segment operating results were as follows (in thousands):
Three Months Ended March 31,
20212020Variance
Revenue$29,163 $25,966 $3,197 
Fuel expense2,671 2,285 386 
Operations and maintenance7,358 6,997 361 
Depreciation and amortization4,865 5,335 (470)
Total operating expense14,894 14,617 277 
Adjusted operating income$14,269 $11,349 $2,920 

Three Months Ended March 31, 2021 Compared to the Three Months Ended March 31, 2020:

Operating income increased $1.7 million due to Winter Storm Uri’s favorable impact to Black Hills Wyoming under the economy energy PSA. Revenue also increased due to higher Wygen I MWh sold driven by a prior year planned outage.

Operating Statistics
Revenue (in thousands)
Quantities Sold (MWh) (a)
Three Months Ended March 31,2021202020212020
Black Hills Colorado IPP$14,254 $14,179 239,194 265,225 
Black Hills Wyoming (b)
13,433 10,158 164,957 156,352 
Black Hills Electric Generation1,476 1,629 96,294 97,279 
Total Power Generation Revenue and Quantities Sold$29,163 $25,966 500,445 518,856 
Three Months Ended March 31,
Quantities Generated and Purchased (MWh) (a)
Fuel Type20212020
Generated
Black Hills Colorado IPPNatural Gas239,194 265,225 
Black Hills Wyoming (b)
Coal136,104 126,485 
Black Hills Electric GenerationWind96,294 97,279 
Total Generated471,592 488,989 
Purchased
Black Hills Wyoming (b)
Various29,567 29,856 
Total Purchased29,567 29,856 
____________
(a)    Company uses and losses are not included in the quantities sold, generated, and purchased.
(b)    Under the 20-year economy energy PSA with the City of Gillette effective September 2014, Black Hills Wyoming purchases energy on behalf of the City of Gillette and sells that energy to the City of Gillette. MWh sold may not equal MWh generated and purchased due to a dispatch agreement that Black Hills Wyoming has with South Dakota Electric to cover energy imbalances.
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Three Months Ended March 31,
Contracted generating facilities availability by fuel type (a)
20212020
Coal (b)
97.0 %89.3 %
Natural gas98.6 %99.5 %
Wind94.2 %99.3 %
Total availability96.7 %97.8 %
Wind capacity factor32.6 %30.4 %
____________________
(a)    Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.
(b)     2020 included a planned outage at Wygen I.


Mining

Our Mining segment operating results were as follows (in thousands):
Three Months Ended March 31,
20212020Variance
Revenue$14,672 $15,205 $(533)
Operations and maintenance9,197 9,826 (629)
Depreciation, depletion and amortization2,214 2,250 (36)
Total operating expenses11,411 12,076 (665)
Adjusted operating income$3,261 $3,129 $132 

Three Months Ended March 31, 2021 Compared to the Three Months Ended March 31, 2020:

Adjusted operating income was comparable to the same period in the prior year.

Operating Statistics

The following table provides certain operating statistics for our Mining segment (in thousands, except for Revenue per ton):
Three Months Ended March 31,
20212020
Tons of coal sold875 896 
Cubic yards of overburden moved1,822 2,267 
Revenue per ton$16.09 $16.08 


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Corporate and Other

Corporate and Other operating results were as follows (in thousands):
Three Months Ended March 31,
20212020Variance
Adjusted operating income (loss)$(3,122)$160 $(3,282)

Three Months Ended March 31, 2021 Compared to the Three Months Ended March 31, 2020:

The variance in Adjusted operating income (loss) was primarily due to a prior year favorable true-up of employee costs which was allocated to our subsidiaries in the current year. This allocation was offset in our reportable segments and had no impact to consolidated results.


Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax (Expense)

Three Months Ended March 31,
20212020Variance
(in thousands)
Interest expense, net$(37,600)$(35,453)$(2,147)
Impairment of investment— (6,859)$6,859 
Other income (expense), net266 2,353 $(2,087)
Income tax (expense)(494)(16,002)$15,508 

Three Months Ended March 31, 2021 Compared to the Three Months Ended March 31, 2020.

Interest Expense

The increase in Interest expense, net was due to higher debt balances driven by the February 2021 term loan and the June 2020 senior unsecured notes partially offset by lower interest rates.

Impairment of Investment

In the prior year, we recorded a pre-tax non-cash write-down of $6.9 million in our investment in equity securities of a privately held oil and gas company. The impairment was triggered by continued adverse changes in future natural gas prices and liquidity concerns at the privately held oil and gas company.

Other Income (Expense)

The decrease in Other income was primarily due to prior year credits for our non-qualified benefit plan driven by market performance on plan assets.

Income Tax (Expense)

For the three months ended March 31, 2021, the effective tax rate was 0.5% compared to 14.1% for the same period in 2020. The lower effective tax rate is primarily due to $7.6 million of increased tax benefits from Colorado Electric’s TCJA-related bill credits to customers (which is offset by reduced revenue), $1.5 million of increased tax benefits from amortization of excess deferred income taxes and $1.3 million of increased tax benefits from federal production tax credits associated with new wind assets.


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Liquidity and Capital Resources

There have been no material changes in Liquidity and Capital Resources from those reported in Item 7 of our 2020 Annual Report on Form 10-K except as described below.

For the three months ended March 31, 2021, we did not experience significant impacts to our liquidity or financial condition due to the COVID-19 pandemic.

In response to the February 2021 Winter Storm Uri, we took steps to maintain adequate liquidity to operate our businesses and fund our capital investment program as discussed in the Recent Developments above and in further detail in Note 5 of the Notes to Condensed Consolidated Financial Statements.


Cash Flow Activities

The following table summarizes our cash flows for the three months ended March 31, (in thousands):
Cash provided by (used in):20212020Variance
Operating activities$(386,086)$191,969 $(578,055)
Investing activities$(146,224)$(173,084)$26,860 
Financing activities$539,496 $25,621 $513,875 

Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020

Operating Activities:

Net cash provided by operating activities was $578 million lower than the same period in 2020. The variance to the prior year was primarily attributable to:

Cash earnings (net income plus non-cash adjustments) were $15 million lower for the three months ended March 31, 2021 compared to the same period in the prior year primarily driven by lower operating income at our Electric Utilities;

Net inflows from changes in certain operating assets and liabilities were $563 million lower, primarily attributable to:

Cash outflows increased by $560 million as a result of changes in our regulatory assets and liabilities primarily driven by incremental costs from Winter Storm Uri;

Cash inflows decreased by $23 million primarily as a result of changes in natural gas in storage and lower collections of accounts receivable; and

Cash outflows decreased by $20 million as a result of increases 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 $0.8 million for other operating activities.

Investing Activities:

Net cash used in investing activities was $27 million lower than the same period in 2020. The variance to the prior year was primarily attributable to:

Capital expenditures of $146 million for the three months ended March 31, 2021 compared to $172 million for the same period in the prior year. Lower current year expenditures are driven by lower programmatic safety, reliability and integrity spending at our Gas Utilities and Electric Utilities segments and the prior year Corriedale wind project at our Electric Utilities segment.

Cash outflows decreased by $1.3 million for other investing activities.

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Financing Activities:

Net cash provided by financing activities was $514 million higher than the same period in 2020. The variance to the prior year was primarily attributable to:

Cash inflows increased $615 million due to borrowings of short-term debt in excess of short-term and long-term debt repayments. This increase was primarily driven by $600 million net borrowings from our term loan;

Cash inflows decreased $99 million due to the prior year issuance of common stock;

Cash outflows increased $2.6 million due to increased dividends paid on common stock; and

Cash outflows decreased by $0.7 million for other financing activities.


Capital Sources

Term Loan

See Note 5 of the Notes to Condensed Consolidated Financial Statements for information relating to our term loan.

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, 2021March 31, 2021March 31, 2021
Revolving Credit Facility and CP ProgramJuly 30, 2023$750 $216 $17 $517 
__________
(a)    Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility.

The weighted average interest rate on short-term borrowings related to our Revolving Credit Facility and CP Program at March 31, 2021 was 0.23%. Short-term borrowing activity related to our Revolving Credit Facility and CP Program for the three months ended March 31, 2021 was:
(dollars in millions)
Maximum amount outstanding (based on daily outstanding balances)$311 
Average amount outstanding (based on daily outstanding balances)$199 
Weighted average interest rates0.24 %

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, 2021 See Note 5 of the Notes to Condensed Consolidated Financial Statements for more information.

Future Financing Plans

We will continue to assess debt and equity needs to support our capital investment plans and other key strategic objectives. In 2021, we expect 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. As discussed in the Recent Developments above and in further detail in Note 5 of the Notes to Condensed Consolidated Financial Statements, on February 24, 2021, we entered into an $800 million term loan maturing on November 24, 2021. We expect to refinance a portion of the term loan with longer-term debt.


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Credit Ratings

After assessing the current operating performance, liquidity and the 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, 2021:
Rating AgencySenior Unsecured RatingOutlook
S&P (a)
BBB+Stable
Moody’s (b)
Baa2Stable
Fitch (c)
BBB+Stable
__________
(a)    On April 10, 2020, S&P reported BBB+ rating and maintained a Stable outlook.
(b)    On December 21, 2020, Moody’s reported Baa2 rating and maintained a Stable outlook.
(c)    On August 20, 2020, Fitch reported BBB+ rating and maintained a Stable outlook.

The following table represents the credit ratings of South Dakota Electric at March 31, 2021:
Rating AgencySenior Secured Rating
S&P (a)
A
Moody’s (b)
A1
Fitch (c)
A
__________
(a)    On April 16, 2020, S&P reported A rating.
(b)    On December 21, 2020, Moody’s reported A1 rating.
(c)    On August 20, 2020, Fitch reported A rating.


Capital Requirements

Capital Expenditures
ActualForecasted
Capital Expenditures by Segment
Three Months Ended March 31, 2021 (a)
2021 (b)
2022202320242025
(in millions)
Electric Utilities$52 $240 $180 $143 $156 $154 
Gas Utilities73 377 347 339 330 326 
Power Generation10 
Mining10 
Corporate and Other11 13 13 13 
Incremental Projects (c)
— — 50 100 100 100 
$132 $647 $600 $610 $612 $608 
__________
(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, 2021.
(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 $36 million for the three months ended March 31, 2021, or $0.565 per share per quarter. On April 26, 2021, our board of directors declared a quarterly dividend of $0.565 per share payable June 1, 2021, equivalent to an annual dividend of $2.26 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.
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Unconditional Purchase Obligations

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


Critical Accounting Policies Involving Significant Estimates

There have been no material changes in our critical accounting estimates from those reported in our 2020 Annual Report on Form 10-K. We continue to closely monitor the impacts of COVID-19 and Winter Storm Uri on our critical accounting estimates including, but not limited to, collectibility of customer receivables, recoverability through regulatory assets, impairment risk of goodwill and long-lived assets, valuation of pension assets and liabilities, and contingent liabilities. For more information on our critical accounting estimates, see Part II, Item 7 of our 2020 Annual Report on Form 10-K.


New Accounting Pronouncements

Other than the pronouncements reported in our 2020 Annual Report on Form 10-K and those discussed in Note 1 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements that are expected to have a material effect on our financial position, results of operations, or cash flows.


ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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


ITEM 4.    CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of March 31, 2021. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at March 31, 2021.

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

Changes in Internal Control over Financial Reporting

During the quarter ended March 31, 2021, there have been no changes in our internal controls over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.


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PART II.    OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS

For information regarding legal proceedings, see Note 3 in Item 8 of our 2020 Annual Report on Form 10-K and Note 3 in Item 1 of Part I of this Quarterly Report on Form 10-Q.

ITEM 1A.RISK FACTORS

There are no material changes to the risk factors previously disclosed in Item 1A of Part I in our 2020 Annual Report on Form 10-K.

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

The following table contains monthly information about our acquisitions of equity securities for the three months ended March 31, 2021:
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, 2021116.0$60.06 — — 
February 1, 2021 - February 28, 202111,696.061.92 — — 
March 1, 2021 - March 31, 20211.459.86 — — 
Total11,813 $61.90 — — 
_____________
(a)    Shares were acquired under the share withholding provisions of the Omnibus Incentive Plan for payment of taxes associated with the vesting of various equity compensation plans.


ITEM 4.        MINE SAFETY DISCLOSURES

Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 95 of this Quarterly Report on Form 10-Q.

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.

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4.1.4
4.1.5
4.1.6
4.1.7
4.1.8
4.2
4.2.1
4.2.2
4.2.3
4.3
4.3.1
4.3.2
4.4
10.1
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, 2021

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