Docoh
Loading...

BKH Black Hills

Filed: 4 Aug 21, 11:47am
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 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 July 31, 2021
Common stock, $1.00 par value63,480,270 shares




















2



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
4


CVACredit Valuation Adjustment
DthDekatherm. A unit of energy equal to 10 therms or approximately one million British thermal units (MMBtu)
Economy EnergyPurchased energy that costs less than that produced with the utilities’ owned generation.
FASBFinancial Accounting Standards Board
FERCUnited States Federal Energy Regulatory Commission
FitchFitch Ratings Inc.
GAAPAccounting principles generally accepted in the United States of America
GHGGreenhouse Gases
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
IRPIntegrated Resource Plan
IRSUnited States Internal Revenue Service
IUBIowa Utilities Board
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).
Neil Simpson IIA mine-mouth, coal-fired power plant owned and operated by South Dakota Electric with a total capacity of 90 MW located at our Gillette, Wyoming energy complex.
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 19, 2021, and now terminates on July 19, 2026.
SDPUCSouth Dakota Public Utilities Commission
SECUnited States Securities and Exchange Commission
5


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
TCJATax Cuts and Jobs Act
Tech ServicesNon-regulated product lines delivered by our Utilities that 1) provide electrical system construction services to large industrial customers of our electric utilities, and 2) serve gas transportation customers throughout its service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.
UtilitiesBlack Hills’ Electric and Gas Utilities
Wind Capacity FactorMeasures the amount of electricity a wind turbine produces in a given time period relative to its maximum potential.
Winter Storm UriFebruary 2021 winter weather event that caused extremely cold temperatures in the central United States and led to unprecedented fluctuations in customer demand and market pricing for natural gas and energy.
WPSCWyoming Public Service Commission
WRDCWyodak Resources Development Corporation, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, providing coal supply primarily to five on-site, mine-mouth generating facilities (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%.
Wygen IIA mine-mouth, coal-fired power plant owned by Wyoming Electric with a total capacity of 95 MW located at our Gillette, Wyoming energy complex.
Wygen IIIA mine-mouth, coal-fired power plant operated by South Dakota Electric with a total capacity of 110 MW located at our Gillette, Wyoming energy complex. South Dakota Electric owns 52% of the power plant, MDU owns 25% and the City of Gillette owns the remaining 23%.
Wyodak 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.


7


PART I.     FINANCIAL INFORMATION

ITEM 1.        FINANCIAL STATEMENTS



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
(in thousands, except per share amounts)
Revenue$372,572 $326,914 $1,006,004 $863,964 
Operating expenses:
Fuel, purchased power and cost of natural gas sold108,474 71,629 401,621 259,508 
Operations and maintenance123,245 117,308 252,924 242,774 
Depreciation, depletion and amortization58,443 56,663 115,712 113,065 
Taxes - property and production15,144 14,381 30,166 28,499 
Total operating expenses305,306 259,981 800,423 643,846 
Operating income67,266 66,933 205,581 220,118 
Other income (expense):
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)(38,669)(35,765)(76,494)(71,546)
Interest income467 220 692 548 
Impairment of investment(6,859)
Other income (expense), net(191)(1,863)75 490 
Total other income (expense)(38,393)(37,408)(75,727)(77,367)
Income before income taxes28,873 29,525 129,854 142,751 
Income tax (expense)(586)(4,831)(1,080)(20,833)
Net income28,287 24,694 128,774 121,918 
Net income attributable to noncontrolling interest(3,126)(3,728)(7,297)(7,778)
Net income available for common stock$25,161 $20,966 $121,477 $114,140 
Earnings per share of common stock:
Earnings per share, Basic$0.40 $0.34 $1.94 $1.84 
Earnings per share, Diluted$0.40 $0.33 $1.93 $1.83 
Weighted average common shares outstanding:
Basic62,867 62,573 62,751 62,175 
Diluted62,918 62,617 62,817 62,230 

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 June 30,Six Months Ended June 30,
2021202020212020
(in thousands)
Net income$28,287 $24,694 $128,774 $121,918 
Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (net of tax of $0, $0, $0 and $(17), respectively)55 
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $6, $6, $15 and $13, respectively)(18)(19)(34)(42)
Reclassification adjustments of benefit plan liability - net loss (net of tax of $(157), $(182), $(374) and $(277), respectively)440 415 821 917 
Derivative instruments designated as cash flow hedges:
Reclassification of net realized losses on settled/amortized interest rate swaps (net of tax of $(150), $(170), $(340) and $(340), respectively)563 543 1,086 1,086 
Net unrealized gains (losses) on commodity derivatives (net of tax of $(304), $14, $(339) and $68, respectively)939 (45)1,046 (220)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $14, $(16), $6 and $(131), respectively)(42)54 (19)425 
Other comprehensive income, net of tax1,882 948 2,900 2,221 
Comprehensive income30,169 25,642 131,674 124,139 
Less: comprehensive income attributable to noncontrolling interest(3,126)(3,728)(7,297)(7,778)
Comprehensive income available for common stock$27,043 $21,914 $124,377 $116,361 

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
June 30, 2021December 31, 2020
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents$1,175 $6,356 
Restricted cash and equivalents4,559 4,383 
Accounts receivable, net189,437 265,961 
Materials, supplies and fuel114,089 117,400 
Derivative assets, current3,925 1,848 
Income tax receivable, net17,573 19,446 
Regulatory assets, current218,628 51,676 
Other current assets22,353 26,221 
Total current assets571,739 493,291 
Property, plant and equipment7,558,204 7,305,530 
Less: accumulated depreciation and depletion(1,361,453)(1,285,816)
Total property, plant and equipment, net6,196,751 6,019,714 
Other assets:
Goodwill1,299,454 1,299,454 
Intangible assets, net11,356 11,944 
Regulatory assets, non-current617,781 226,582 
Other assets, non-current40,971 37,801 
Total other assets, non-current1,969,562 1,575,781 
TOTAL ASSETS$8,738,052 $8,088,786 

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.
10



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
(unaudited)As of
June 30, 2021December 31, 2020
(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable$133,354 $183,340 
Accrued liabilities219,022 243,612 
Derivative liabilities, current5,178 2,044 
Regulatory liabilities, current36,124 25,061 
Notes payable829,850 234,040 
Current maturities of long-term debt7,000 8,436 
Total current liabilities1,230,528 696,533 
Long-term debt, net of current maturities3,530,216 3,528,100 
Deferred credits and other liabilities:
Deferred income tax liabilities, net436,495 408,624 
Regulatory liabilities, non-current497,608 507,659 
Benefit plan liabilities151,290 150,556 
Other deferred credits and other liabilities133,021 134,667 
Total deferred credits and other liabilities1,218,414 1,201,506 
Commitments, contingencies and guarantees (Note 3)
00
Equity:
Stockholders’ equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 63,526,913 and 62,827,179 shares, respectively63,527 62,827 
Additional paid-in capital1,701,825 1,657,285 
Retained earnings921,122 870,738 
Treasury stock, at cost – 46,528 and 32,492 shares, respectively(2,988)(2,119)
Accumulated other comprehensive income (loss)(24,446)(27,346)
Total stockholders’ equity2,659,040 2,561,385 
Noncontrolling interest99,854 101,262 
Total equity2,758,894 2,662,647 
TOTAL LIABILITIES AND TOTAL EQUITY$8,738,052 $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)Six Months Ended June 30,
20212020
Operating activities:(in thousands)
Net income$128,774 $121,918 
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization115,712 113,065 
Deferred financing cost amortization4,381 4,246 
Impairment of investment6,859 
Stock compensation5,044 1,113 
Deferred income taxes692 26,401 
Employee benefit plans4,934 5,656 
Other adjustments, net10,495 3,679 
Changes in certain operating assets and liabilities:
Materials, supplies and fuel3,974 7,503 
Accounts receivable and other current assets88,513 73,302 
Accounts payable and other current liabilities(59,640)(63,085)
Regulatory assets(540,709)21,887 
Regulatory liabilities(9,509)314 
Contributions to defined benefit pension plans(12,700)
Other operating activities, net(2,834)(1,152)
Net cash provided by (used in) operating activities(250,173)309,006 
Investing activities:
Property, plant and equipment additions(319,476)(348,313)
Other investing activities9,739 (1,412)
Net cash (used in) investing activities(309,737)(349,725)
Financing activities:
Dividends paid on common stock(71,092)(66,440)
Common stock issued40,037 99,435 
Term loan - borrowings800,000 
Term loan - repayments(200,000)
Net payments of Revolving Credit Facility and CP Program(4,190)(349,500)
Long-term debt - issuances400,000 
Long-term debt - repayments(1,436)(5,727)
Distributions to noncontrolling interest(8,705)(8,520)
Other financing activities291 (6,474)
Net cash provided by financing activities554,905 62,774 
Net change in cash, restricted cash and cash equivalents(5,005)22,055 
Cash, restricted cash and cash equivalents at beginning of period10,739 13,658 
Cash, restricted cash and cash equivalents at end of period$5,734 $35,713 
Supplemental cash flow information:
Cash (paid) refunded during the period:
Interest, net of amounts capitalized$(71,825)$(67,449)
Income taxes1,486 1,896 
Non-cash investing and financing activities:
Accrued property, plant and equipment purchases at June 3054,448 59,916 

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.
12



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(unaudited)Common StockTreasury Stock
(in thousands except share amounts)SharesValueSharesValueAdditional Paid in CapitalRetained EarningsAOCINon controlling InterestTotal
December 31, 202062,827,179 $62,827 32,492 $(2,119)$1,657,285 $870,738 $(27,346)$101,262 $2,662,647 
Net income— — — — — 96,316 — 4,171 100,487 
Other comprehensive income, net of tax— — — — — — 1,018 — 1,018 
Dividends on common stock ($0.565 per share)— — — — — (35,514)— — (35,514)
Share-based compensation82,794 83 7,448 (445)1,672 — — — 1,310 
Other— — — — — (2)— — (2)
Distributions to 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 
Net income— — — — — 25,161 — 3,126 28,287 
Other comprehensive income, net of tax— — — — — — 1,882 — 1,882 
Dividends on common stock ($0.565 per share)— — — — — (35,578)— — (35,578)
Share-based compensation20,905 21 6,588 (424)3,698 — — — 3,295 
Issuance of common stock596,035 596 — — 39,636 — — — 40,232 
Issuance costs— — — — (466)— — — (466)
Other— — — — — — — 
Distributions to noncontrolling interest— — — — — — — (4,061)(4,061)
June 30, 202163,526,913 $63,527 46,528 $(2,988)$1,701,825 $921,122 $(24,446)$99,854 $2,758,894 

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 
Net income— — — — — 20,966 — 3,728 24,694 
Other comprehensive income (loss), net of tax— — — — — — 948 — 948 
Dividends on common stock ($0.535 per share)— — — — — (33,538)— — (33,538)
Share-based compensation18 1,743 46 1,781 — — — 1,827 
Issuance costs— — — — (79)— — — (79)
Distributions to noncontrolling interest— — — — — — — (3,779)(3,779)
June 30, 202062,772,996 $62,773 26,399 $(1,879)$1,654,563 $826,269 $(28,434)$101,204 $2,614,496 

13


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 June 30, 2021, December 31, 2020 and June 30, 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 and six months ended June 30, 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.



14


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 ofAs of
June 30, 2021December 31, 2020
Regulatory assets
Winter Storm Uri (a)
$541,389 $
Deferred energy and fuel cost adjustments (b)
57,715 39,035 
Deferred gas cost adjustments (b)
676 3,200 
Gas price derivatives (b)
145 2,226 
Deferred taxes on AFUDC (c)
7,479 7,491 
Employee benefit plans and related deferred taxes (d)
116,003 116,598 
Environmental (b)
1,410 1,413 
Loss on reacquired debt (b)
21,914 22,864 
Deferred taxes on flow through accounting (d)
55,034 47,515 
Decommissioning costs (b)
7,205 8,988 
Gas supply contract termination (b)
2,524 
Other regulatory assets (b)
27,439 26,404 
Total regulatory assets836,409 278,258 
   Less current regulatory assets(218,628)(51,676)
Regulatory assets, non-current$617,781 $226,582 
Regulatory liabilities
Deferred energy and gas costs (b)
$28,261 $13,253 
Employee benefit plan costs and related deferred taxes (d)
39,542 40,256 
Cost of removal (b)
179,968 172,902 
Excess deferred income taxes (d)
268,604 285,259 
Other regulatory liabilities (d)
17,357 21,050 
Total regulatory liabilities533,732 532,720 
   Less current regulatory liabilities(36,124)(25,061)
Regulatory liabilities, non-current$497,608 $507,659 
__________
(a)    Timing of Winter Storm Uri incremental cost recovery and associated carrying costs are subject to pending applications with our utility commissions. 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 substantial increase in heating and energy demand and contributed to unforeseeable and unprecedented market prices for natural gas and electricity. As a result of Winter Storm Uri, we incurred significant incremental fuel, purchased power and natural gas costs.

In the first quarter of 2021, $559 million of incremental costs from Winter Storm Uri were recorded to a regulatory asset. Our Utilities submitted cost recovery applications in our state jurisdictions seeking to recover $546 million in total of these incremental costs through separate tracking mechanisms over a weighted-average recovery period of 3.7 years. These incremental cost estimates are subject to adjustments as final decisions are issued by the respective utility commissions. As part of these applications, we seek approval to recover carrying costs. We are also seeking recovery of $13 million of previously disclosed Winter Storm Uri incremental costs through our existing regulatory mechanisms.

In the second quarter of 2021, Nebraska Gas and South Dakota Electric received commission approval on their Winter Storm Uri cost recovery applications. Additionally, Arkansas Gas and Iowa Gas received approval for interim recovery subject to a final decision on carrying costs and recovery periods at a later date. For the three and six months ended June 30, 2021, our Utilities recovered $4.6 million of Winter Storm Uri incremental and carrying costs from customers.

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. The settlement agreement further provided for Colorado Electric to deliver annual bill credits to customers, starting in April 2021, until remaining excess deferred income tax regulatory liabilities associated with the TCJA are fully amortized. In April 2021, Colorado Electric delivered $0.9 million of TCJA-related bill credits to customers.

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, were delivered to customers in June 2021.

These Colorado Electric and Nebraska Gas 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 and six months ended June 30, 2021.

Colorado Gas

Rate Review

On June 1, 2021, Colorado Gas filed a rate review with the CPUC seeking recovery of significant infrastructure investments in its 7,000-mile natural gas pipeline system. The rate review requests $14.6 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 9.95%. The request seeks to implement new rates in the first quarter of 2022.

On September 11, 2020, in accordance with the final Order from an 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. On July 6, 2021, Colorado Gas received approval from the CPUC for its SSIR proposal that will recover safety and integrity focused investments in its system for three years. The return on SSIR investments will be the current weighted-average cost of long-term debt.

Iowa Gas

Rate Review

On June 1, 2021, Iowa Gas filed a rate review with the IUB seeking recovery of significant infrastructure investments in its 5,000-mile natural gas pipeline system. Additionally, Iowa Gas is seeking to implement a five year SSIR that would recover safety and integrity focused investments. The rate review requests shifting $2.2 million of rider revenue to base rates and $8.3 million in additional new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 10.15%. Iowa statute allows implementation of interim rates 10 days after filing a rate review and Iowa Gas implemented interim rates effective on June 11, 2021. The request seeks to finalize rates in the first quarter of 2022.

16


Kansas Gas

Rate Review

On May 7, 2021, Kansas Gas filed a rate review and rider renewal with the KCC seeking recovery of significant infrastructure investments in its 4,600-mile natural gas pipeline system. Additionally, Kansas Gas is seeking renewal of its SSIR. The rate review requests shifting $4.9 million of rider revenue to base rates and $5.3 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 10.15%. The request seeks to implement new rates in the first quarter of 2022.

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.


(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 and six months ended June 30, 2021 and 2020. Sales tax and other similar taxes are excluded from revenues.
17


Three Months Ended June 30, 2021 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer types:(in thousands)
Retail$158,470 $143,845 $$13,854 $(7,140)$309,029 
Transportation31,649 (109)31,540 
Wholesale3,010 24,912 (23,480)4,442 
Market - off-system sales8,941 87 (1,675)7,353 
Transmission/Other12,233 9,125 (5,299)16,059 
Revenue from contracts with customers$182,654 $184,706 $24,912 $13,854 $(37,703)$368,423 
Other revenues2,279 1,344 436 575 (485)4,149 
Total revenues$184,933 $186,050 $25,348 $14,429 $(38,188)$372,572 
Timing of revenue recognition:
Services transferred at a point in time$$$$13,854 $(7,140)$6,714 
Services transferred over time182,654 184,706 24,912 (30,563)361,709 
Revenue from contracts with customers$182,654 $184,706 $24,912 $13,854 $(37,703)$368,423 

Three Months Ended June 30, 2020 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer Types:(in thousands)
Retail$141,804 $120,594 $$14,846 $(7,916)$269,328 
Transportation30,792 (138)30,654 
Wholesale3,470 25,718 (24,476)4,712 
Market - off-system sales3,538 23 (1,580)1,981 
Transmission/Other12,761 9,189 (4,432)17,518 
Revenue from contracts with customers$161,573 $160,598 $25,718 $14,846 $(38,542)$324,193 
Other revenues1,627 512 404 570 (392)2,721 
Total Revenues$163,200 $161,110 $26,122 $15,416 $(38,934)$326,914 
Timing of Revenue Recognition:
Services transferred at a point in time$$$$14,846 $(7,916)$6,930 
Services transferred over time161,573 160,598 25,718 (30,626)317,263 
Revenue from contracts with customers$161,573 $160,598 $25,718 $14,846 $(38,542)$324,193 
18


Six Months Ended June 30, 2021 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer types:(in thousands)
Retail$356,970 $485,450 $$27,937 $(14,247)$856,110 
Transportation79,600 (219)79,381 
Wholesale8,932 53,604 (47,931)14,605 
Market - off-system sales16,597 160 (4,559)12,198 
Transmission/Other27,426 19,515 (10,595)36,346 
Revenue from contracts with customers$409,925 $584,725 $53,604 $27,937 $(77,551)$998,640 
Other revenues2,416 3,844 907 1,164 (967)7,364 
Total revenues$412,341 $588,569 $54,511 $29,101 $(78,518)$1,006,004 
Timing of revenue recognition:
Services transferred at a point in time$$$$27,937 $(14,247)$13,690 
Services transferred over time409,925 584,725 53,604 (63,304)984,950 
Revenue from contracts with customers$409,925 $584,725 $53,604 $27,937 $(77,551)$998,640 

Six Months Ended June 30, 2020 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer Types:(in thousands)
Retail$290,444 $418,841 $$29,249 $(15,755)$722,779 
Transportation74,900 (277)74,623 
Wholesale9,022 51,185 (48,088)12,119 
Market - off-system sales8,405 161 (4,219)4,347 
Transmission/Other27,618 21,761 (8,845)40,534 
Revenue from contracts with customers$335,489 $515,663 $51,185 $29,249 $(77,184)$854,402 
Other revenues1,850 6,220 903 1,372 (783)9,562 
Total Revenues$337,339 $521,883 $52,088 $30,621 $(77,967)$863,964 
Timing of Revenue Recognition:
Services transferred at a point in time$$$$29,249 $(15,755)$13,494 
Services transferred over time335,489 515,663 51,185 (61,429)840,908 
Revenue from contracts with customers$335,489 $515,663 $51,185 $29,249 $(77,184)$854,402 

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.


19


(5)    Financing

Short-term debt

We had the following Notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
June 30, 2021December 31, 2020
Balance Outstanding
Letters of Credit (a)
Balance Outstanding
Letters of Credit (a)
Term Loan$600,000 $$$
Revolving Credit Facility13,049 24,730 
CP Program229,850 234,040 
Total Notes payable$829,850 $13,049 $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 June 30, 2021 was 0.85%.

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

On July 19, 2021, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 19, 2026 with 2 one year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. Based on our current credit ratings, the margins for base rate borrowings, Eurodollar borrowings and letters of credit will be 0.125%, 1.125% and 1.125%, respectively, and a 0.175% commitment fee will be charged on unused amounts.

Our net short-term borrowings related to our Revolving Credit Facility and CP Program during the six months ended June 30, 2021 decreased by $4.2 million. The weighted average interest rate on short-term borrowings related to our Revolving Credit Facility and CP Program at June 30, 2021 was 0.19%.

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 June 30, 2021:
As of June 30, 2021Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio62.3%Less than65%

20


Equity

At-the-Market Equity Offering Program

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


(6)    Earnings Per Share

A reconciliation of share amounts used to compute earnings per share in the accompanying Condensed Consolidated Statements of Income was as follows (in thousands, except per share amounts):
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
Net income available for common stock$25,161 $20,966 $121,477 $114,140 
Weighted average shares - basic62,867 62,573 62,751 62,175 
Dilutive effect of:
Equity compensation51 44 66 55 
Weighted average shares - diluted62,918 62,617 62,817 62,230 
Earnings per share of common stock:
Earnings per share, Basic$0.40 $0.34 $1.94 $1.84 
Earnings per share, Diluted$0.40 $0.33 $1.93 $1.83 

The following securities were excluded from the diluted earnings per share computation because of their anti-dilutive nature (in thousands):
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
Equity compensation13 29 12 26 
Restricted stock76 36 
Anti-dilutive shares13 105 13 62 


(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 weather (Winter Storm Uri), 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.

21


Credit Risk

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

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

We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the 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 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 July 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.

22


The contract or notional amounts and terms of the electric and natural gas derivative commodity instruments held at our Utilities are composed of both long and short positions. We had the following net long positions as of:
June 30, 2021December 31, 2020
UnitsNotional
Amounts
Maximum
Term
(months) (a)
Notional
Amounts
Maximum
Term
(months) (a)
Natural gas futures purchasedMMBtus100,000 9620,000 3
Natural gas options purchased, netMMBtus970,000 93,160,000 3
Natural gas basis swaps purchasedMMBtus9900,000 3
Natural gas over-the-counter swaps, net (b)
MMBtus6,660,000 263,850,000 17
Natural gas physical contracts, net (c)
MMBtus4,902,179 917,513,061 22
Electric wholesale contracts (c)
MWh110,425 6219,000 12
__________
(a)    Term reflects the maximum forward period hedged.
(b)    As of June 30, 2021, 3,030,000 MMBtus of natural gas over-the-counter swaps purchases were designated as cash flow hedges.
(c)     Volumes exclude derivative contracts that qualify for the normal purchases and normal sales exception permitted by GAAP.

We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At June 30, 2021, the Company posted $1.0 million related to such provisions, which is included in Other current assets on the Condensed Consolidated Balance Sheets.

Derivatives by Balance Sheet Classification

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

The following table presents the fair value and balance sheet classification of our derivative instruments (in thousands) as of:
Balance Sheet LocationJune 30, 2021December 31, 2020
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivativesDerivative assets, current$1,549 $181 
Noncurrent commodity derivativesOther assets, non-current43 
Liability derivative instruments:
Current commodity derivativesDerivative liabilities, current(108)
Total derivatives designated as hedges$1,554 $116 
Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivativesDerivative assets, current$2,376 $1,667 
Noncurrent commodity derivativesOther assets, non-current375 151 
Liability derivative instruments:
Current commodity derivativesDerivative liabilities, current(5,178)(1,936)
Total derivatives not designated as hedges$(2,427)$(118)

23


Derivatives Designated as Hedge Instruments

The impacts of cash flow hedges on our Condensed Consolidated Statements of Comprehensive Income and Condensed Consolidated Statements of Income are presented below for the three and six months ended June 30, 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 June 30,Three Months Ended June 30,
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 $713 Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)$(713)$(713)
Commodity derivatives1,187 11 Fuel, purchased power and cost of natural gas sold56 (70)
Total$1,900 $724 $(657)$(783)

Six Months Ended June 30,Six Months Ended June 30,
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$1,426 $1,426 Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)$(1,426)$(1,426)
Commodity derivatives1,360 268 Fuel, purchased power and cost of natural gas sold25 (556)
Total$2,786 $1,694 $(1,401)$(1,982)

As of June 30, 2021, $2.8 million of net losses related to our interest rate swaps and commodity derivatives are expected to be reclassified from AOCI into earnings as losses within the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

Derivatives Not Designated as Hedge Instruments

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Condensed Consolidated Statements of Income for the three and six months ended June 30, 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 June 30,
20212020
Derivatives Not Designated as Hedging InstrumentsLocation of Gain/(Loss) on Derivatives Recognized in IncomeAmount of Gain/(Loss) on Derivatives Recognized in Income
(in thousands)
Commodity derivatives - ElectricFuel, purchased power and cost of natural gas sold$(3,598)$(204)
Commodity derivatives - Natural GasFuel, purchased power and cost of natural gas sold1,816 449 
$(1,782)$245 
24



Six Months Ended June 30,
20212020
Derivatives Not Designated as Hedging InstrumentsLocation of Gain/(Loss) on Derivatives Recognized in IncomeAmount of Gain/(Loss) on Derivatives Recognized in Income
(in thousands)
Commodity derivatives - ElectricFuel, purchased power and cost of natural gas sold$(5,122)$1,158 
Commodity derivatives - Natural GasFuel, purchased power and cost of natural gas sold2,182 1,215 
$(2,940)$2,373 

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 $0.1 million and $2.2 million as of June 30, 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.

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.
25


As of June 30, 2021
Level 1Level 2Level 3Cash Collateral and Counterparty
Netting
Total
(in thousands)
Assets:
Commodity derivatives — Gas Utilities$$4,895 $$(590)$4,305 
Commodity derivatives — Electric Utilities$$$$$
Total$$4,895 $$(590)$4,305 
Liabilities:
Commodity derivatives — Gas Utilities$$200 $$$200 
Commodity derivatives — Electric Utilities$$4,978 $$$4,978 
Total$$5,178 $$$5,178 

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.

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:
June 30, 2021December 31, 2020
Carrying
Amount
Fair ValueCarrying
Amount
Fair Value
Long-term debt, including current maturities (a)
$3,537,216 $4,035,612 $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.


26


(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 June 30,Six Months Ended June 30,
2021202020212020
Gains and (losses) on cash flow hedges:
Interest rate swapsInterest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)$(713)$(713)$(1,426)$(1,426)
Commodity contractsFuel, purchased power and cost of natural gas sold56 (70)25 (556)
(657)(783)(1,401)(1,982)
Income taxIncome tax (expense)136 186 334 471 
Total reclassification adjustments related to cash flow hedges, net of tax$(521)$(597)$(1,067)$(1,511)
Amortization of components of defined benefit plans:
Prior service costOperations and maintenance$24 $25 $49 $55 
Actuarial gain (loss)Operations and maintenance(597)(597)(1,195)(1,194)
(573)(572)(1,146)(1,139)
Income taxIncome tax (expense)151 176 359 264 
Total reclassification adjustments related to defined benefit plans, net of tax$(422)$(396)$(787)$(875)
Total reclassifications$(943)$(993)$(1,854)$(2,386)
27



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)$(27,346)
Other comprehensive income (loss)
before reclassifications1,046 1,046 
Amounts reclassified from AOCI1,086 (19)787 1,854 
As of June 30, 2021$(11,472)$1,029 $(14,003)$(24,446)
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(220)55 (165)
Amounts reclassified from AOCI1,087 424 875 2,386 
As of June 30, 2020$(14,035)$(252)$(14,147)$(28,434)


(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 June 30,Six Months Ended June 30,
2021202020212020
Service cost$1,260 $1,353 $2,519 $2,706 
Interest cost2,328 3,356 4,656 6,713 
Expected return on plan assets(5,219)(5,648)(10,438)(11,296)
Net loss1,829 2,093 3,658 4,186 
Net periodic benefit cost$198 $1,154 $395 $2,309 

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 June 30,Six Months Ended June 30,
2021202020212020
Service cost$559 $514 $1,118 $1,028 
Interest cost264 413 529 825 
Expected return on plan assets(34)(46)(68)(91)
Prior service cost (benefit)(109)(137)(218)(274)
Net loss117 234 10 
Net periodic benefit cost$797 $749 $1,595 $1,498 

28


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 June 30,Six Months Ended June 30,
2021202020212020
Service cost$1,020 $1,817 $1,713 $447 
Interest cost177 275 354 550 
Net loss438 426 877 852 
Net periodic benefit cost$1,635 $2,518 $2,944 $1,849 

Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made in the first six months of 2021 and anticipated contributions for 2021 and 2022 are as follows (in thousands):
Contributions MadeAdditional ContributionsContributions
Six Months Ended June 30, 2021Anticipated for 2021Anticipated for 2022
Defined Benefit Pension Plan$$$3,788 
Non-pension Defined Benefit Postretirement Healthcare Plan$2,763 $2,763 $5,241 
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans$964 $964 $1,967 


(11)    Income Taxes

Winter Storm Uri

As discussed in Note 2 above, our Utilities submitted cost recovery applications which seek to recover incremental costs from Winter Storm Uri through a regulatory mechanism. 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. 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 a 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 June 30, 2021.

Income Tax (Expense) and Effective Tax Rates

Three Months Ended June 30, 2021 Compared to the Three Months Ended June 30, 2020

Income tax (expense) for the three months ended June 30, 2021 was $(0.6) million compared to $(4.8) million reported for the same period in 2020. For the three months ended June 30, 2021 the effective tax rate was 2.0% compared to 16.4% for the same period in 2020. The lower effective tax rate is primarily due to $2.2 million of increased tax benefits from Nebraska Gas TCJA-related bill credits to customers (which is offset by reduced revenue) and $1.9 million of increased flow-through tax benefits related to repairs and certain indirect costs.

Six Months Ended June 30, 2021 Compared to the Six Months Ended June 30, 2020

Income tax (expense) for the six months ended June 30, 2021 was $(1.1) million compared to $(21) million reported for the same period in 2020. For the six months ended June 30, 2021, the effective tax rate was 0.8% compared to 14.6% for the same period in 2020. The lower effective tax rate is primarily due to $10 million of increased tax benefits from Colorado Electric and Nebraska Gas TCJA-related bill credits to customers (which is offset by reduced revenue), $3.0 million of increased flow-through tax benefits related to repairs and certain indirect costs, $1.6 million of increased tax benefits from federal production tax credits associated with new wind assets and $1.4 million of increased tax benefits from amortization of excess deferred income taxes.

29


(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:June 30, 2021December 31, 2020
Electric Utilities$3,239,628 $3,120,928 
Gas Utilities4,935,784 4,376,204 
Power Generation394,213 404,220 
Mining75,109 77,085 
Corporate and Other93,318 110,349 
Total assets$8,738,052 $8,088,786 

Three Months Ended June 30, 2021External Operating RevenueInter-company Operating Revenue Total Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities$177,092 $2,279 $5,562 $$184,933 
Gas Utilities183,187 1,250 1,519 94 186,050 
Power Generation1,432 386 23,480 50 25,348 
Mining6,712 234 7,142 341 14,429 
Inter-company eliminations— — (37,703)(485)(38,188)
Total$368,423 $4,149 $$$372,572 

Three Months Ended June 30, 2020External Operating RevenueInter-company Operating Revenue Total Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities$156,197 $1,627 $5,376 $$163,200 
Gas Utilities159,824 512 774 161,110 
Power Generation1,242 349 24,476 55 26,122 
Mining6,930 233 7,916 337 15,416 
Inter-company eliminations— — (38,542)(392)(38,934)
Total$324,193 $2,721 $$$326,914 

30


Six Months Ended June 30, 2021External Operating RevenueInter-company Operating RevenueTotal Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities$397,592 $2,416 $12,333 $$412,341 
Gas Utilities581,686 3,658 3,039 186 588,569 
Power Generation5,673 807 47,931 100 54,511 
Mining13,689 483 14,248 681 29,101 
Inter-company eliminations— — (77,551)(967)(78,518)
Total$998,640 $7,364 $$$1,006,004 

Six Months Ended June 30, 2020External Operating RevenueInter-company Operating Revenue Total Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities$323,700 $1,850 $11,789 $$337,339 
Gas Utilities514,111 6,220 1,552 521,883 
Power Generation3,097 792 48,088 111 52,088 
Mining13,494 700 15,755 672 30,621 
Inter-company eliminations— — (77,184)(783)(77,967)
Total$854,402 $9,562 $$$863,964 

Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
Adjusted operating income:
Electric Utilities$35,568 $33,993 $57,381 $69,643 
Gas Utilities19,985 18,209 122,079 121,106 
Power Generation8,250 11,402 22,519 22,751 
Mining3,644 3,358 6,905 6,487 
Corporate and Other(181)(29)(3,303)131 
Operating income67,266 66,933 205,581 220,118 
Interest expense, net(38,202)(35,545)(75,802)(70,998)
Impairment of investment(6,859)
Other income (expense), net(191)(1,863)75 490 
Income tax (expense)(586)(4,831)(1,080)(20,833)
Net income28,287 24,694 128,774 121,918 
Net income attributable to noncontrolling interest(3,126)(3,728)(7,297)(7,778)
Net income available for common stock$25,161 $20,966 $121,477 $114,140 


31


(13)    Selected Balance Sheet Information

Accounts Receivable and Allowance for Credit Losses

Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
June 30, 2021December 31, 2020
Accounts receivable, trade$132,400 $146,899 
Unbilled revenue63,066 126,065 
Less: Allowance for credit losses(6,029)(7,003)
Accounts receivable, net$189,437 $265,961 

Changes to allowance for credit losses for the six months ended June 30, 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 June 30,
2021$7,003 $1,510 $1,786 $(4,270)$6,029 
2020$2,444 $6,715 $2,203 $(3,777)$7,585 

Materials, Supplies and Fuel

The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
June 30, 2021December 31, 2020
Materials and supplies$85,277 $85,250 
Fuel - Electric Utilities2,310 1,531 
Natural gas in storage26,502 30,619 
Total materials, supplies and fuel$114,089 $117,400 

Accrued Liabilities

The following amounts by major classification are included in Accrued liabilities on the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
June 30, 2021December 31, 2020
Accrued employee compensation, benefits and withholdings$69,067 $77,806 
Accrued property taxes39,416 47,105 
Customer deposits and prepayments47,583 52,185 
Accrued interest31,762 31,520 
Other (none of which is individually significant)31,194 34,996 
Total accrued liabilities$219,022 $243,612 


(14)    Subsequent Events

We evaluated all subsequent event activity and concluded that no subsequent events have occurred that would require recognition in the condensed consolidated financial statements or disclosures, with the exception of Colorado Gas regulatory activity disclosed in Note 2 and our amended and restated corporate Revolving Credit Facility disclosed in Note 5.


32


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

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

During the second quarter, our Utilities submitted cost recovery applications with the utility commissions in our state jurisdictions to recover incremental costs associated with Winter Storm Uri. See Note 2 of the Notes to Condensed Consolidated Financial Statements for further information on our regulatory activity.

COVID-19 Update

For the six months ended June 30, 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

On July 28, 2021, Wyoming Electric set a new all-time and summer peak load of 274 MW, exceeding the previous peak of 271 MW set in July 2020.

On July 27, 2021, South Dakota Electric set a new all-time and summer peak load of 397 MW, exceeding the previous peak of 378 MW set in August 2020.

On June 30, 2021, South Dakota Electric and Wyoming Electric submitted an IRP to the SDPUC and WPSC. The IRP outlines a range of options for the two electric utilities to meet long-term forecasted energy needs over a 20-year planning horizon while strengthening reliability and resiliency of the grid. The analysis focused on the least-cost resource needs to best meet customers’ future peak energy needs while maintaining system flexibility and achieving the Company’s generation emissions reduction goals. The IRP’s preferred options for the near-term planning period through 2026 propose the addition of 100 MW of renewable generation, the conversion of Neil Simpson II to natural gas in 2025 and consideration of up to 20 MW of battery storage.

33


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 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

See Note 2 for recent regulatory activity for our Gas Utilities in Colorado, Iowa, Kansas and Nebraska.

Corporate and Other

On July 19, 2021, we amended and restated our corporate Revolving Credit Facility. See Note 5 for further information.


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 and six months ended June 30, 2021 and 2020, and our financial condition as of June 30, 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 June 30,Six Months Ended June 30,
2021202020212020
(in thousands, except per share amounts)
Adjusted operating income (a):
Electric Utilities$35,568 $33,993 $57,381 $69,643 
Gas Utilities19,985 18,209 122,079 121,106 
Power Generation8,250 11,402 22,519 22,751 
Mining3,644 3,358 6,905 6,487 
Corporate and Other(181)(29)(3,303)131 
Operating income67,266 66,933 205,581 220,118 
Interest expense, net(38,202)(35,545)(75,802)(70,998)
Impairment of investment— — — (6,859)
Other income (expense), net(191)(1,863)75 490 
Income tax (expense)(586)(4,831)(1,080)(20,833)
Net income28,287 24,694 128,774 121,918 
Net income attributable to noncontrolling interest(3,126)(3,728)(7,297)(7,778)
Net income available for common stock$25,161 $20,966 121,477 114,140 
Total earnings per share of common stock, Diluted$0.40 $0.33 $1.93 $1.83 
__________
(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.
34



Three Months Ended June 30, 2021 Compared to Three Months Ended June 30, 2020

The variance to the prior year included the following:

Electric Utilities’ adjusted operating income increased $1.6 million primarily due to increased wholesale, power marketing and Tech Services revenues, increased rider revenues, regulatory actions reducing certain Winter Storm Uri impacts, and prior year COVID-19 impacts which were partially offset by unfavorable mark-to-market adjustments on wholesale energy contacts and higher operating expenses;
Gas Utilities’ adjusted operating income increased $1.8 million primarily due to new rates, favorable market-to-market adjustments on wholesale commodity contracts and prior year COVID-19 impacts partially offset by Nebraska Gas’s TCJA-related bill credits to customers and higher operating expenses;
Power Generation’s adjusted operating income decreased $3.2 million primarily driven by current year planned outages;
A $2.7 million increase in interest expense due to higher debt balances partially offset by lower rates;
A $1.7 million increase in other income primarily due to lower non-service pension costs driven by a lower discount rate and lower costs for our non-qualified benefit plans which were driven by market performance; and
A $4.2 million decrease in income tax expense due to a lower effective tax rate driven primarily by tax benefits from Nebraska Gas’s TCJA-related bill credits and flow-through tax benefits related to repairs and certain indirect costs.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020

The variance to the prior year included the following:

Electric Utilities’ adjusted operating income decreased $12 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, increased wholesale, power marketing and Tech Services revenues and prior year COVID-19 impacts;
Gas Utilities’ adjusted operating income increased $1.0 million primarily due to new rates and higher heating demand from colder weather mostly offset by Winter Storm Uri costs incurred by Black Hills Energy Services, Nebraska Gas TCJA-related bill credits to customers, and higher operating expenses;
Corporate and Other expenses increased $3.4 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 business segments;
A $4.8 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;
A $19.8 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 and Nebraska Gas TCJA-related bill credits, flow-through tax benefits related to repairs and certain indirect costs, 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.


35


Electric Utilities

Operating results for the Electric Utilities were as follows (in thousands):
Three Months Ended June 30,Six Months Ended June 30,
20212020Variance20212020Variance
Revenue$184,933 $163,200 $21,733 $412,341 $337,339 $75,002 
Total fuel and purchased power75,238 59,053 16,185 207,307 123,513 83,794 
Gross margin (non-GAAP)109,695 104,147 5,548 205,034 213,826 (8,792)
Operations and maintenance48,962 47,031 1,931 97,539 97,530 
Depreciation and amortization25,165 23,123 2,042 50,114 46,653 3,461 
Total operating expenses74,127 70,154 3,973 147,653 144,183 3,470 
Adjusted operating income$35,568 $33,993 $1,575 $57,381 $69,643 $(12,262)

Three Months Ended June 30, 2021 Compared to the Three Months Ended June 30, 2020:

Gross margin for the three months ended June 30, 2021 increased as a result of the following:
(in millions)
Rider recovery2.7 
Winter Storm Uri impacts (a)
2.4 
Wholesale, Power Marketing and Tech Services2.2 
Prior year COVID-19 impacts1.5 
Residential customer growth0.4 
Mark-to-market on wholesale energy contracts (b)
(3.4)
TCJA-related bill credits (c)
(0.9)
Weather(0.7)
Other1.3 
Total change in Gross margin (non-GAAP)$5.5 
________________
(a)    In the first quarter 2021,our Electric Utilities accrued $3.2 million of negative impacts to our regulated wholesale power margins due to the higher fuel costs associated with Winter Storm Uri. Through regulatory actions in the second quarter of 2021, our Electric Utilities were able to reduce $2.4 million of that negative impact.
(b)    Mark-to-market losses of $3.6 million for the three months ended June 30, 2021 will reverse in the second half of 2021 as these fixed price wholesale energy contracts are settled.
(c)    In April 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.

Operations and maintenance expense increased primarily due to higher maintenance costs related to planned and unplanned outages at the Gillette, Wyoming energy complex and higher operating expenses associated with Corriedale which was placed in service November 30, 2020.

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

36


Six Months Ended June 30, 2021 Compared to the Six Months Ended June 30, 2020:

Gross margin for the six months ended June 30, 2021 decreased as a result of the following:
(in millions)
TCJA-related bill credits (a)
$(10.2)
Mark-to-market on wholesale energy contracts (b)
(6.3)
Winter Storm Uri impacts (c)
(2.9)
Rider recovery4.0 
Wholesale, Power Marketing and Tech Services2.7 
Prior year COVID-19 impacts1.5 
Residential customer growth0.7 
Weather0.4 
Other1.3 
Total change in Gross margin (non-GAAP)$(8.8)
________________
(a)    In February and April 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)    Mark-to-market losses of $5.1 million for the six months ended June 30, 2021 will reverse in the second half of 2021 as these fixed price wholesale energy contracts are settled.
(c)    As a result of Winter Storm Uri, our Electric Utilities incurred a $0.8 million negative impact to our regulated wholesale power margins due to higher fuel costs and $2.1 million of incremental fuel costs that are not recoverable through our fuel cost recovery mechanisms.

Operations and maintenance expense remained constant primarily due to higher maintenance costs related to planned and unplanned outages at the Gillette, Wyoming energy complex and higher operating expenses associated with Corriedale which was placed in service November 30, 2020, offset by 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 and current year capital expenditures.

Operating Statistics
Revenue (in thousands)Quantities Sold (MWh)
Three Months Ended
June 30,
Six Months Ended
June 30,
Three Months Ended
June 30,
Six Months Ended
June 30,
20212020202120202021202020212020
Residential$53,451 $50,148 $126,211 $104,653 335,063 334,682 731,149 707,832 
Commercial66,809 56,400 143,816 114,223 501,463 459,632 994,418 953,940 
Industrial35,186 31,896 78,195 64,065 441,793 459,533 856,984 920,165 
Municipal4,382 4,020 9,402 7,898 39,863 38,372 76,105 74,771 
Subtotal Retail Revenue - Electric159,828 142,464 357,624 290,839 1,318,182 1,292,219 2,658,656 2,656,708 
Contract Wholesale5,751 3,470 14,216 9,023 129,763 87,253 286,758 219,031 
Off-system/Power Marketing Wholesale6,200 3,537 11,313 8,404 188,607 136,311 316,190 302,096 
Other13,154 13,729 29,188 29,073 — — — — 
Total Revenue and Energy Sold184,933 163,200 412,341 337,339 1,636,552 1,515,783 3,261,604 3,177,835 
Other Uses, Losses or Generation, net— — — — 93,747 85,185 224,722 176,056 
Total Revenue and Energy184,933 163,200 412,341 337,339 1,730,299 1,600,968 3,486,326 3,353,891 
Less cost of fuel and purchased power75,238 59,053 207,307 123,513 
Gross Margin (non-GAAP)$109,695 $104,147 $205,034 $213,826 

37


Three Months Ended June 30,Revenue
(in thousands)
Gross Margin (non-GAAP) (in thousands)
Quantities Sold (MWh)(a)
202120202021202020212020
Colorado Electric$64,313 $57,897 $34,409 $32,455 618,806 547,814 
South Dakota Electric73,494 62,587 51,892 49,973 630,055 570,528 
Wyoming Electric47,126 42,716 23,394 21,719 481,438 482,626 
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold$184,933 $163,200 $109,695 $104,147 1,730,299 1,600,968 

Six Months Ended June 30,Revenue
(in thousands)
Gross Margin (non-GAAP) (in thousands)
Quantities Sold (MWh)(a)
202120202021202020212020
Colorado Electric$144,054 $116,455 $58,500 $64,725 1,225,149 1,098,585 
South Dakota Electric168,830 134,198 101,442 105,597 1,287,834 1,255,752 
Wyoming Electric99,457 86,686 45,092 43,504 973,343 999,554 
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold$412,341 $337,339 $205,034 $213,826 3,486,326 3,353,891 
________________
(a)    Includes company uses, line losses, and excess exchange production.

Three Months Ended June 30,Six Months Ended June 30,
Quantities Generated and Purchased (MWh)2021202020212020
Generated:
Coal497,238 572,030 980,216 1,119,859 
Natural Gas and Oil171,610 86,798 303,715 254,542 
Wind107,178 63,628 225,157 137,178 
Total Generated776,026 722,456 1,509,088 1,511,579 
Purchased954,273 878,512 1,977,238 1,842,312 
Total Generated and Purchased1,730,299 1,600,968 3,486,326 3,353,891 

Three Months Ended June 30,Six Months Ended June 30,
Quantities Generated and Purchased (MWh)2021202020212020
Generated:
Colorado Electric110,821 80,456 201,077 174,507 
South Dakota Electric442,665 442,566 911,481 915,532 
Wyoming Electric222,540 199,434 396,530 421,540 
Total Generated776,026 722,456 1,509,088 1,511,579 
Purchased:
Colorado Electric507,985 467,358 1,024,072 924,078 
South Dakota Electric187,389 127,962 376,353 340,220 
Wyoming Electric258,899 283,192 576,813 578,014 
Total Purchased954,273 878,512 1,977,238 1,842,312 
Total Generated and Purchased1,730,299 1,600,968 3,486,326 3,353,891 

38


Three Months Ended June 30,
20212020
Degree DaysActualVariance from
Normal
ActualVariance from
Normal
Heating Degree Days:
Colorado Electric595 (6)%518 (18)%
South Dakota Electric1,048 %1,127 10 %
Wyoming Electric1,221 %1,149 (4)%
Combined (a)
875 — %853 (3)%
Cooling Degree Days:
Colorado Electric300 44 %382 83 %
South Dakota Electric167 69 %120 21 %
Wyoming Electric117 134 %101 102 %
Combined (a)
218 56 %236 69 %

Six Months Ended June 30,
20212020
Degree DaysActualVariance from
Normal
ActualVariance from
Normal
Heating Degree Days
Colorado Electric3,326 %2,974 (9)%
South Dakota Electric4,372 %4,238 — %
Wyoming Electric4,482 %4,148 (1)%
Combined (a)
3,915 %3,642 (4)%
Cooling Degree Days:
Colorado Electric300 44 %382 83 %
South Dakota Electric167 69 %120 21 %
Wyoming Electric117 134 %101 102 %
Combined (a)
218 56 %236 69 %
____________________
(a)    Combined actuals are calculated based on the weighted average number of total customers by state.

Three Months Ended June 30,Six Months Ended June 30,
Contracted generating facilities availability by fuel type (a)
2021202020212020
Coal (b)
85.4 %94.1 %84.6 %92.5 %
Natural Gas and diesel oil (b) (c)
97.2 %78.3 %92.4 %80.9 %
Wind96.4 %98.1 %94.9 %98.6 %
Total availability93.4 %85.0 %90.3 %86.0 %
Wind capacity factor36.9 %39.0 %40.0 %42.3 %
____________________
(a)    Availability and wind capacity factor are calculated using a weighted average based on capacity of our generating fleet.
(b)     2021 included planned outages at Neil Simpson II, Wygen II, Wygen III and Pueblo Airport Generation and unplanned outages at Neil Simpson II and Wyodak Plant.
(c)    2020 included an unplanned outage at Pueblo Airport Generation.


39


Gas Utilities

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

Three Months Ended June 30,Six Months Ended June 30,
20212020Variance20212020Variance
Revenue:
Natural gas - regulated$172,465 $148,432 $24,033 $550,542 $484,329 $66,213 
Other - non-regulated services13,585 12,678 907 38,027 37,554 473 
Total revenue186,050 161,110 24,940 588,569 521,883 66,686 
Cost of sales:
Natural gas - regulated62,317 42,910 19,407 245,284 196,909 48,375 
Other - non-regulated services798 1,712 (914)10,881 3,074 7,807 
Total cost of sales63,115 44,622 18,493 256,165 199,983 56,182 
Gross margin (non-GAAP)122,935 116,488 6,447 332,404 321,900 10,504 
Operations and maintenance77,263 72,415 4,848 159,463 149,709 9,754 
Depreciation and amortization25,687 25,864 (177)50,862 51,085 (223)
Total operating expenses102,950 98,279 4,671 210,325 200,794 9,531 
Adjusted operating income$19,985 $18,209 $1,776 $122,079 $121,106 $973 

Three Months Ended June 30, 2021 Compared to the Three Months Ended June 30, 2020:

Gross margin for the three months ended June 30, 2021 increased as a result of:
(in millions)
New rates$5.5 
Mark-to-market on non-utility natural gas commodity contracts1.6 
Prior year COVID-19 impacts0.9 
Weather0.1 
TCJA-related bill credits (a)
(2.9)
Other1.2 
Total increase in Gross margin (non-GAAP)$6.4 
__________
(a)    In June 2021, Nebraska Gas provided 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.

Operations and maintenance expense increased due to $4.4 million of higher employee costs and outside services driven by higher headcount and higher stock compensation expense related to market performance, $1.6 million of increased facilities and office expenses, and $1.0 million of increased property taxes due to a higher asset base partially offset by $3.2 million of decreased bad debt expense associated with lower expected credit losses. Other expenses, none of which were individually significant, comprised the remainder of the difference when compared to the same period in the prior year.

Depreciation and amortization 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 and current year capital expenditures.

40


Six Months Ended June 30, 2021 Compared to the Six Months Ended June 30, 2020:

Gross margin for the six months ended June 30, 2021 increased as a result of the following:
(in millions)
New rates$14.7 
Weather7.6 
Mark-to-market on non-utility natural gas commodity contracts1.2 
Prior year COVID-19 impacts0.9 
Black Hills Energy Services Winter Storm Uri costs (a)
(8.2)
TCJA-related bill credits (b)
(2.9)
Non-utility - Service Guard Comfort Plan and Gas Supply Services(2.3)
Other(0.5)
Total increase in Gross margin (non-GAAP)$10.5 
__________
(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.
(b)    In June 2021, Nebraska Gas 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.

Operations and maintenance expense increased primarily due to $9.6 million of higher employee costs and outside services driven by higher headcount and higher stock compensation expense related to market performance, $2.2 million of higher facilities and office related expenses, and $1.6 million of increased property taxes due to a higher asset base partially offset by $3.4 million of decreased bad debt expense associated with lower expected credit losses.

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 and current year capital expenditures.

Operating Statistics
Revenue (in thousands)
Gross Margin (non-GAAP) (in thousands)
Gas Utilities Quantities Sold & Transported (Dth)
Three Months Ended
June 30,
Three Months Ended
June 30,
Three Months Ended
June 30,
202120202021202020212020
Residential$98,370 $83,240 $60,388 $56,368 8,575,051 8,501,835 
Commercial36,888 27,441 16,964 15,336 4,493,931 3,965,529 
Industrial5,811 6,059 1,400 2,140 1,337,672 2,036,553 
Other(418)828 (418)827 — — 
Total Distribution140,651 117,568 78,334 74,671 14,406,654 14,503,917 
Transportation and Transmission31,814 30,864 31,814 30,851 34,074,214 30,243,501 
Total Regulated172,465 148,432 110,148 105,522 48,480,868 44,747,418 
Non-regulated Services13,585 12,678 12,787 10,966 
Total Gas Revenue & Gross Margin (non-GAAP)$186,050 $161,110 $122,935 $116,488 
41


Revenue (in thousands)Gross Margin (non-GAAP) (in thousands)Gas Utilities Quantities Sold & Transported (Dth)
Six Months Ended
June 30,
Six Months Ended
June 30,
Six Months Ended
June 30,
202120202021202020212020
Residential$332,767 $290,471 $170,536 $159,489 39,143,789 36,732,630 
Commercial127,977 107,677 52,448 48,855 18,306,252 16,800,332 
Industrial10,713 11,259 3,189 4,183 2,235,961 3,097,605 
Other(890)(415)(890)(415)— — 
Total Distribution470,567 408,992 225,283 212,112 59,686,002 56,630,567 
Transportation and Transmission79,975 75,337 79,975 75,308 79,388,652 75,299,008 
Total Regulated550,542 484,329 305,258 287,420 139,074,654 131,929,575 
Non-regulated Services38,027 37,554 27,146 34,480 
Total Gas Revenue & Gross Margin (non-GAAP)$588,569 $521,883 $332,404 $321,900 

Revenue (in thousands)Gross Margin (non-GAAP) (in thousands)Gas Utilities Quantities Sold & Transported (Dth)
Three Months Ended
June 30,
Three Months Ended
June 30,
Three Months Ended
June 30,
202120202021202020212020
Arkansas Gas$32,994 $28,733 $22,902 $21,906 5,718,417 4,906,236 
Colorado Gas34,190 28,613 20,610 18,807 5,957,285 5,046,844 
Iowa Gas29,831 21,407 16,009 14,355 7,016,613 5,521,119 
Kansas Gas21,163 18,486 12,744 12,460 7,155,427 6,722,914 
Nebraska Gas43,037 40,466 32,095 30,719 15,822,880 13,822,478 
Wyoming Gas24,835 23,405 18,575 18,241 6,810,246 8,727,827 
Total Gas Revenue & Gross Margin (non-GAAP)$186,050 $161,110 $122,935 $116,488 48,480,868 44,747,418 

Revenue (in thousands)Gross Margin (non-GAAP) (in thousands)Gas Utilities Quantities Sold & Transported (Dth)
Six Months Ended
June 30,
Six Months Ended
June 30,
Six Months Ended
June 30,
202120202021202020212020
Arkansas Gas$119,988 $103,578 $74,851 $70,761 19,025,151 15,869,184 
Colorado Gas113,312 101,219 58,822 56,813 19,323,300 18,143,249 
Iowa Gas86,585 76,231 38,640 35,683 21,330,586 19,801,392 
Kansas Gas61,226 51,980 31,510 31,063 17,618,224 16,637,772 
Nebraska Gas136,135 124,132 82,027 82,385 43,106,981 40,331,514 
Wyoming Gas71,323 64,743 46,554 45,195 18,670,412 21,146,464 
Total Gas Revenue & Gross Margin (non-GAAP)$588,569 $521,883 $332,404 $321,900 139,074,654 131,929,575 


42



Three Months Ended June 30,
20212020
Heating Degree DaysActualVariance
from Normal
ActualVariance
from Normal
Arkansas Gas (a)
38316%3537%
Colorado Gas865(9)%809(15)%
Iowa Gas6911%78314%
Kansas Gas (a)
49310%4777%
Nebraska Gas624(1)%6929%
Wyoming Gas1,200(1)%1,216—%
Combined Gas (b)
7391%6882%

Six Months Ended June 30,
20212020
Heating Degree Days:ActualVariance
from Normal
ActualVariance
from Normal
Arkansas Gas (a)
2,5043%2,012(17)%
Colorado Gas3,830(1)%3,638(6)%
Iowa Gas4,1131%3,964(2)%
Kansas Gas (a)
3,0695%2,781(4)%
Nebraska Gas3,7211%3,527(4)%
Wyoming Gas4,6255%4,4331%
Combined Gas (b)
3,9252%3,606(4)%
__________
(a)    Arkansas Gas and Kansas Gas have weather normalization mechanisms that mitigate the weather impact on gross margins.
(b)    The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to its weather normalization mechanism. Arkansas Gas is partially excluded based on the weather normalization mechanism in effect from November through April.


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.


43


Power Generation

Our Power Generation segment operating results were as follows (in thousands):
Three Months Ended June 30,Six Months Ended June 30,
20212020Variance20212020Variance
Revenue$25,348 $26,122 $(774)$54,511 $52,088 $2,423 
Fuel expense2,621 2,087 534 5,292 4,372 920 
Operations and maintenance9,322 7,350 1,972 16,680 14,347 2,333 
Depreciation and amortization5,155 5,283 (128)10,020 10,618 (598)
Total operating expense17,098 14,720 2,378 31,992 29,337 2,655 
Adjusted operating income$8,250 $11,402 $(3,152)$22,519 $22,751 $(232)

Three Months Ended June 30, 2021 Compared to the Three Months Ended June 30, 2020:

The decrease in current year operating income was primarily driven by a current year planned outage at Pueblo Airport Generation and the timing of current year and prior year planned outages at the Gillette, Wyoming energy complex.

Six Months Ended June 30, 2021 Compared to the Six Months Ended June 30, 2020:

Operating income was comparable to the same period in the prior year due to negative impacts of a current year planned outage at Pueblo Airport Generation mostly offset by $1.7 million of favorable Winter Storm Uri impacts realized under Black Hills Wyoming’s Economy Energy PSA.

Operating Statistics

Revenue (in thousands)
Quantities Sold (MWh) (a)
Revenue (in thousands)
Quantities Sold (MWh) (a)
Three Months Ended June 30,Six Months Ended June 30,
20212020202120202021202020212020
Black Hills Colorado IPP$13,981 $14,211 204,065 263,701 $28,235 $28,390 443,259 528,926 
Black Hills Wyoming (b)
10,141 10,488 141,809 156,866 23,574 20,646 306,766 313,218 
Black Hills Electric Generation1,226 1,423 88,724 92,629 2,702 3,052 185,018 189,908 
Total Power Generation Revenue and Quantities Sold$25,348 $26,122 434,598 513,196 $54,511 $52,088 935,043 1,032,052 

44


Three Months Ended June 30,Six Months Ended June 30,
Quantities Generated and Purchased (MWh) (a)
Fuel Type2021202020212020
Generated
Black Hills Colorado IPPNatural Gas204,065 263,701 443,259 528,926 
Black Hills Wyoming (b)
Coal128,270 142,747 264,374 269,232 
Black Hills Electric GenerationWind88,724 92,629 185,018 189,908 
Total Generated421,059 499,077 892,651 988,066 
Purchased
Black Hills Wyoming (b)
Various15,102 14,160 44,616 44,093 
Total Purchased15,102 14,160 44,616 44,093 
____________
(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.

Three Months Ended June 30,Six Months Ended June 30,
Contracted generating facilities availability by fuel type (a)
2021202020212020
Coal (b)
89.3 %98.2 %93.1 %93.7 %
Natural gas (b)
87.6 %99.7 %93.1 %99.6 %
Wind97.2 %93.1 %95.7 %94.0 %
Total availability91.4 %97.0 %94.1 %96.6 %
Wind capacity factor26.5 %27.5 %27.7 %28.9 %
____________________
(a)    Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.
(b)     2021 included planned outages at Wygen I and Pueblo Airport Generation.


Mining

Our Mining segment operating results were as follows (in thousands):
Three Months Ended June 30,Six Months Ended June 30,
20212020Variance20212020Variance
Revenue$14,429 $15,416 $(987)$29,101 $30,621 $(1,520)
Operations and maintenance8,415 9,732 (1,317)17,612 19,558 (1,946)
Depreciation, depletion and amortization2,370 2,326 44 4,584 4,576 
Total operating expenses10,785 12,058 (1,273)22,196 24,134 (1,938)
Adjusted operating income$3,644 $3,358 $286 $6,905 $6,487 $418 

Three and Six Months Ended June 30, 2021 Compared to the Three and Six Months Ended June 30, 2020:

Current year revenue decreased due to fewer tons sold driven primarily by planned and unplanned outages at the Gillette, Wyoming energy complex. Operating expenses decreased primarily due to lower overburden costs, royalties and production taxes on decreased revenues.

45


Operating Statistics

The following table provides certain operating statistics for our Mining segment (in thousands, except for Revenue per ton):
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
Tons of coal sold856 972 1,731 1,868 
Cubic yards of overburden moved1,609 2,211 3,431 4,478 
Revenue per ton$16.18 $15.27 $16.14 $15.66 


Corporate and Other

Corporate and Other operating results were as follows (in thousands):
Three Months Ended June 30,Six Months Ended June 30,
20212020Variance20212020Variance
Adjusted operating income (loss)$(181)$(29)$(152)$(3,303)$131 $(3,434)

Three Months Ended June 30, 2021 Compared to the Three Months Ended June 30, 2020:

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

Six Months Ended June 30, 2021 Compared to the Six Months Ended June 30, 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 business segments and had no impact to consolidated results.


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

Three Months Ended June 30,Six Months Ended June 30,
20212020Variance20212020Variance
(in thousands)
Interest expense, net$(38,202)$(35,545)$(2,657)$(75,802)$(70,998)$(4,804)
Impairment of investment— — $— $— $(6,859)$6,859 
Other income (expense), net(191)(1,863)$1,672 $75 $490 $(415)
Income tax (expense)(586)(4,831)$4,245 $(1,080)$(20,833)$19,753 

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

Other Income (Expense)

The decrease in Other (expense) was primarily due to lower non-service pension costs driven by a lower discount rate and lower costs for our non-qualified benefit plans which were driven by market performance.

46


Income Tax (Expense)

For the three months ended June 30, 2021, the effective tax rate was 2.0% compared to 16.4% for the same period in 2020. See Note 11 of the Notes to Condensed Consolidated Financial Statements for discussion of effective tax rate variances.

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

Income Tax (Expense)

For the six months ended June 30, 2021, the effective tax rate was 0.8% compared to 14.6% for the same period in 2020. See Note 11 of the Notes to Condensed Consolidated Financial Statements for discussion of effective tax rate variances.


Liquidity and Capital Resources

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

For the six months ended June 30, 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 six months ended June 30, (in thousands):
Cash provided by (used in):20212020Variance
Operating activities$(250,173)$309,006 $(559,179)
Investing activities$(309,737)$(349,725)$39,988 
Financing activities$554,905 $62,774 $492,131 

Six Months Ended June 30, 2021 Compared to the Six Months Ended June 30, 2020

Operating Activities:

Net cash provided by operating activities was $559 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 $13 million lower for the six months ended June 30, 2021 compared to the same period in the prior year primarily driven by higher operating expenses and higher interest expenses;

47


Net inflows from changes in certain operating assets and liabilities were $556 million lower, primarily attributable to:

Cash outflows increased by $572 million as a result of changes in our regulatory assets and liabilities primarily driven by incremental costs from Winter Storm Uri;

Cash inflows increased by $12 million as a result of changes in accounts receivable and other current assets primarily driven by higher collections of accounts receivable; and

Cash outflows decreased by $3.4 million as a result of increases in accounts payable and accrued liabilities primarily driven by working capital requirements.

Cash outflows decreased by $13 million due to pension contributions made in the prior year.

Cash outflows increased by $1.7 million for other operating activities.

Investing Activities:

Net cash used in investing activities was $40 million lower than the same period in 2020. The variance to the prior year was primarily attributable to:

Capital expenditures of $319 million for the six months ended June 30, 2021 compared to $348 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 inflows increased by $11 million for other investing activities which was primarily driven by the sales of transmission assets and facilities, none of which were individually significant.

Financing Activities:

Net cash provided by financing activities was $492 million higher than the same period in 2020. The variance to the prior year was primarily attributable to:

Cash inflows increased $550 million due to short-term and long-term borrowings in excess of repayments. This increase was primarily driven by $600 million net borrowings from our term loan partially offset by prior year net proceeds from the June 17, 2020 debt transaction;

Cash inflows decreased $59 million due to lower issuances of common stock;

Cash outflows increased $4.7 million due to increased dividends paid on common stock; and

Cash inflows increased by $6.8 million for other financing activities driven by the prior year financing costs incurred in the June 17, 2020 debt transaction.


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

On July 19, 2021, we amended and restated our corporate Revolving Credit Facility under similar terms and conditions, See Note 5 of the Notes to Condensed Consolidated Financial Statements for more information.
48



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 FacilityExpirationCapacityJune 30, 2021June 30, 2021June 30, 2021
Revolving Credit Facility and CP ProgramJuly 19, 2026$750 $230 $13 $507 
__________
(a)    Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit

The weighted average interest rate on short-term borrowings related to our Revolving Credit Facility and CP Program at June 30, 2021 was 0.19%. Short-term borrowing activity related to our Revolving Credit Facility and CP Program for the six months ended June 30, 2021 was:
(dollars in millions)
Maximum amount outstanding (based on daily outstanding balances)$311 
Average amount outstanding (based on daily outstanding balances)$200 
Weighted average interest rates0.23 %

Covenant Requirements

The Revolving Credit Facility and Wyoming Electric’s financing agreements contain covenant requirements. We were in compliance with these covenants as of June 30, 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 the second half of 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 an additional $60 million to $80 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 repaid $200 million of this term loan in the first quarter of 2021. We expect to refinance a portion of the term loan with longer-term debt.


Credit Ratings

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

The following table represents the credit ratings and outlook and risk profile of BHC at June 30, 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.
49



The following table represents the credit ratings of South Dakota Electric at June 30, 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
Six Months Ended June 30, 2021 (a)
2021 (b)
2022202320242025
(in millions)
Electric Utilities$114 $240 $180 $143 $156 $154 
Gas Utilities179 377 347 339 330 326 
Power Generation10 
Mining10 
Corporate and Other11 13 13 13 
Incremental Projects (c)
— — 50 100 100 100 
$305 $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 six months ended June 30, 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 $71 million for the six months ended June 30, 2021, or $0.565 per share per quarter. On July 26, 2021, our board of directors declared a quarterly dividend of $0.565 per share payable September 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.

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, cost recoverability through regulatory assets, impairment risk of goodwill and long-lived assets, valuation of pension assets and liabilities and contingent liabilities. For more information on our critical accounting estimates, see Part II, Item 7 of our 2020 Annual Report on Form 10-K.


50


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 June 30, 2021. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at June 30, 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 June 30, 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.


51


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 June 30, 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
April 1, 2021 - April 30, 20212$66.69 — — 
May 1, 2021 - May 31, 2021805$68.43 — — 
June 1, 2021 - June 30, 20211$65.97 — — 
Total808 $68.42 — — 
_____________
(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.

52


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
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)

53


SIGNATURES


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

BLACK HILLS CORPORATION
/s/ Linden R. Evans
Linden R. Evans, President and
  Chief Executive Officer
/s/ Richard W. Kinzley
Richard W. Kinzley, Senior Vice President and
  Chief Financial Officer
Dated:August 4, 2021

54