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Black Hills (BKH)

Filed: 3 Nov 21, 11:48am
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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 October 31, 2021
Common stock, $1.00 par value63,820,271 shares




















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3


GLOSSARY OF TERMS AND ABBREVIATIONS

The following terms and abbreviations appear in the text of this report and have the definitions described below:
AFUDCAllowance for Funds Used During Construction
ALJAdministrative Law Judge
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 non-controlling interest) plus consolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit Facility.
Cooling Degree Day (CDD)A cooling degree day is equivalent to each degree that the average of the high and low temperatures for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
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.
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CP ProgramCommercial Paper Program
CPUCColorado Public Utilities Commission
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
FitchFitch Ratings Inc.
GAAPAccounting principles generally accepted in the United States of America
Global SettlementSettlement with a utility’s commission where the revenue requirement is agreed upon, but the specific adjustments used by each party to arrive at the amount are not specified in public rate orders.
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
MDUMontana-Dakota Utilities Co., a subsidiary of MDU Resources Group, Inc.
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
OSHAOccupational Safety & Health Administration
PPAPower Purchase Agreement
PSAPower Sales Agreement
Pueblo Airport GenerationThe 420 MW combined cycle gas-fired power generating plants jointly owned by Colorado Electric (220 MW) and Black Hills Colorado IPP (200 MW). Black Hills Colorado IPP operates this facility. The plants commenced operation on January 1, 2012.
Ready WyomingA 285-mile, multi-phase transmission expansion project in Wyoming. This transmission project will serve the growing needs of customers by enhancing resiliency of Wyoming Electric’s overall electric system and and expanding access to power markets and renewable resources. The project will help Wyoming Electric maintain top-quartile reliability and enable economic development in the Cheyenne, Wyoming region.
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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
Service Guard Comfort PlanAppliance protection plan that provides home appliance repair services through on-going monthly service agreements to residential utility customers.
S&PS&P Global Ratings, a division of S&P Global Inc.
South Dakota ElectricBlack Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and Wyoming (doing business as Black Hills Energy).
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 extreme cold temperatures in the central United States and led to unprecedented fluctuations in customer demand and market pricing for natural gas and energy.
WPSCWyoming Public Service Commission
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 generating facility near Gillette, Wyoming, jointly owned by PacifiCorp (80%) and South Dakota Electric (20%). Our WRDC mine supplies all of the fuel for the facility.
Wyoming 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).

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FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q includes “forward-looking statements” as defined by the SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation, the risk factors described in Item 1A of Part I of our 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, and the following:

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

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

Our ability to execute on our strategy;

Our ability to successfully execute our financing plans;

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

Board of Directors’ approval of any future quarterly dividends;

The impact of future governmental regulation;

The effects of inflation and volatile energy prices; and

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

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

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PART I.        FINANCIAL INFORMATION

ITEM 1.        FINANCIAL STATEMENTS



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)Three Months Ended September 30,Nine Months Ended September 30,
2021202020212020
(in thousands, except per share amounts)
Revenue$380,590 $346,590 $1,386,594 $1,210,554 
Operating expenses:
Fuel, purchased power and cost of natural gas sold94,057 71,686 495,678 331,194 
Operations and maintenance122,277 122,759 375,201 365,533 
Depreciation, depletion and amortization59,159 56,348 174,871 169,413 
Taxes - property and production15,224 13,563 45,390 42,062 
Total operating expenses290,717 264,356 1,091,140 908,202 
Operating income89,873 82,234 295,454 302,352 
Other income (expense):
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)(38,604)(36,521)(115,098)(108,067)
Interest income586 480 1,278 1,028 
Impairment of investment— — — (6,859)
Other income (expense), net1,560 (1,193)1,635 (703)
Total other income (expense)(36,458)(37,234)(112,185)(114,601)
Income before income taxes53,415 45,000 183,269 187,751 
Income tax (expense)(5,253)(4,651)(6,333)(25,484)
Net income48,162 40,349 176,936 162,267 
Net income attributable to non-controlling interest(4,050)(4,066)(11,347)(11,844)
Net income available for common stock$44,112 $36,283 $165,589 $150,423 
Earnings per share of common stock:
Earnings per share, Basic$0.70 $0.58 $2.63 $2.41 
Earnings per share, Diluted$0.70 $0.58 $2.63 $2.41 
Weighted average common shares outstanding:
Basic63,341 62,575 62,950 62,310 
Diluted63,436 62,630 63,046 62,362 

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

(unaudited)Three Months Ended September 30,Nine Months Ended September 30,
2021202020212020
(in thousands)
Net income$48,162 $40,349 $176,936 $162,267 
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, $21 and $19, respectively)(19)(18)(53)(60)
Reclassification adjustments of benefit plan liability - net loss (net of tax of $(139), $(149), $(513) and $(426), respectively)459 448 1,280 1,365 
Derivative instruments designated as cash flow hedges:
Reclassification of net realized losses on settled/amortized interest rate swaps (net of tax of $(55), $(168), $(395) and $(508), respectively)657 544 1,743 1,630 
Net unrealized gains (losses) on commodity derivatives (net of tax of $(1,437), $(112), $(1,776) and $(44), respectively)4,430 401 5,476 181 
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $81, $(41), $87 and $(172), respectively)(250)137 (269)562 
Other comprehensive income, net of tax5,277 1,512 8,177 3,733 
Comprehensive income53,439 41,861 185,113 166,000 
Less: comprehensive income attributable to non-controlling interest(4,050)(4,066)(11,347)(11,844)
Comprehensive income available for common stock$49,389 $37,795 $173,766 $154,156 

See Note 9 for additional disclosures.

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



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)As of
September 30, 2021December 31, 2020
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents$10,181 $6,356 
Restricted cash and equivalents4,753 4,383 
Accounts receivable, net181,956 265,961 
Materials, supplies and fuel145,743 117,400 
Derivative assets, current12,316 1,848 
Income tax receivable, net17,472 19,446 
Regulatory assets, current213,031 51,676 
Other current assets42,274 26,221 
Total current assets627,726 493,291 
Property, plant and equipment7,697,880 7,305,530 
Less: accumulated depreciation and depletion(1,380,304)(1,285,816)
Total property, plant and equipment, net6,317,576 6,019,714 
Other assets:
Goodwill1,299,454 1,299,454 
Intangible assets, net11,063 11,944 
Regulatory assets, non-current617,024 226,582 
Other assets, non-current37,547 37,801 
Total other assets, non-current1,965,088 1,575,781 
TOTAL ASSETS$8,910,390 $8,088,786 

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.
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BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
(unaudited)As of
September 30, 2021December 31, 2020
(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable$142,130 $183,340 
Accrued liabilities249,835 243,612 
Derivative liabilities, current3,471 2,044 
Regulatory liabilities, current30,156 25,061 
Notes payable332,525 234,040 
Current maturities of long-term debt— 8,436 
Total current liabilities758,117 696,533 
Long-term debt, net of current maturities4,125,571 3,528,100 
Deferred credits and other liabilities:
Deferred income tax liabilities, net445,036 408,624 
Regulatory liabilities, non-current496,261 507,659 
Benefit plan liabilities150,727 150,556 
Other deferred credits and other liabilities134,776 134,667 
Total deferred credits and other liabilities1,226,800 1,201,506 
Commitments, contingencies and guarantees (Note 3)
00
Equity:
Stockholders’ equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 63,865,151 and 62,827,179 shares, respectively63,865 62,827 
Additional paid-in capital1,726,277 1,657,285 
Retained earnings929,369 870,738 
Treasury stock, at cost – 43,885 and 32,492 shares, respectively(2,819)(2,119)
Accumulated other comprehensive income (loss)(19,169)(27,346)
Total stockholders’ equity2,697,523 2,561,385 
Non-controlling interest102,379 101,262 
Total equity2,799,902 2,662,647 
TOTAL LIABILITIES AND TOTAL EQUITY$8,910,390 $8,088,786 

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

(unaudited)Nine Months Ended September 30,
20212020
Operating activities:(in thousands)
Net income$176,936 $162,267 
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization174,871 169,413 
Deferred financing cost amortization3,892 5,523 
Impairment of investment— 6,859 
Stock compensation7,245 2,696 
Deferred income taxes5,844 28,502 
Employee benefit plans6,779 9,294 
Other adjustments, net2,708 7,910 
Changes in certain operating assets and liabilities:
Materials, supplies and fuel(29,948)(10,905)
Accounts receivable and other current assets97,348 75,960 
Accounts payable and other current liabilities(20,094)(11,136)
Regulatory assets(559,389)1,954 
Regulatory liabilities(9,533)(17,686)
Contributions to defined benefit pension plans— (12,700)
Other operating activities, net(1,419)1,508 
Net cash provided by (used in) operating activities(144,760)419,459 
Investing activities:
Property, plant and equipment additions(497,849)(535,993)
Other investing activities13,743 6,269 
Net cash (used in) investing activities(484,106)(529,724)
Financing activities:
Dividends paid on common stock(106,957)(99,999)
Common stock issued62,977 99,316 
Term loan - borrowings800,000 — 
Term loan - repayments(800,000)— 
Net borrowings (payments) of Revolving Credit Facility and CP Program98,485 (265,180)
Long-term debt - issuances600,000 400,000 
Long-term debt - repayments(8,436)(7,163)
Distributions to non-controlling interest(10,230)(12,636)
Other financing activities(2,778)(6,519)
Net cash provided by financing activities633,061 107,819 
Net change in cash, restricted cash and cash equivalents4,195 (2,446)
Cash, restricted cash and cash equivalents at beginning of period10,739 13,658 
Cash, restricted cash and cash equivalents at end of period$14,934 $11,212 
Supplemental cash flow information:
Cash (paid) refunded during the period:
Interest, net of amounts capitalized$(93,325)$(87,453)
Income taxes1,486 1,256 
Non-cash investing and financing activities:
Accrued property, plant and equipment purchases at September 3055,619 86,474 

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

(unaudited)Common StockTreasury Stock
(in thousands except share amounts)SharesValueSharesValueAdditional Paid in CapitalRetained EarningsAOCINon-controlling InterestTotal
December 31, 202062,827,179 $62,827 32,492 $(2,119)$1,657,285 $870,738 $(27,346)$101,262 $2,662,647 
Net income— — — — — 96,316 — 4,171 100,487 
Other comprehensive income, net of tax— — — — — — 1,018 — 1,018 
Dividends on common stock ($0.565 per share)— — — — — (35,514)— — (35,514)
Share-based compensation82,794 83 7,448 (445)1,672 — — — 1,310 
Other— — — — — (2)— — (2)
Distributions to non-controlling interest— — — — — — — (4,644)(4,644)
March 31, 202162,909,973 $62,910 39,940 $(2,564)$1,658,957 $931,538 $(26,328)$100,789 $2,725,302 
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 non-controlling 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 
Net income— — — — — 44,112 — 4,050 48,162 
Other comprehensive income, net of tax— — — — — — 5,277 — 5,277 
Dividends on common stock ($0.565 per share)— — — — — (35,865)— — (35,865)
Share-based compensation17 — (2,643)169 1,849 — — — 2,018 
Issuance of common stock338,221 338 — — 22,834 — — — 23,172 
Issuance costs— — — — (231)— — — (231)
Distributions to non-controlling interest— — — — — — — (1,525)(1,525)
September 30, 202163,865,151 $63,865 43,885 $(2,819)$1,726,277 $929,369 $(19,169)$102,379 $2,799,902 

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(unaudited)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 non-controlling 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 non-controlling 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 
Net income— — — — — 36,283 — 4,066 40,349 
Other comprehensive income (loss), net of tax— — — — — — 1,512 — 1,512 
Dividends on common stock ($0.535 per share)— — — — — (33,559)— — (33,559)
Share-based compensation19 — (1,502)169 1,468 — — — 1,637 
Issuance costs— — — — (119)— — — (119)
Distributions to non-controlling interest— — — — — — — (4,116)(4,116)
September 30, 202062,773,015 $62,773 24,897 $(1,710)$1,655,912 $828,993 $(26,922)$101,154 $2,620,200 

14


BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 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 September 30, 2021, December 31, 2020 and September 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 nine months ended September 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.



15


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
September 30, 2021December 31, 2020
Regulatory assets
Winter Storm Uri (a)
$532,766 $— 
Deferred energy and fuel cost adjustments (b)
59,741 39,035 
Deferred gas cost adjustments (b)
6,076 3,200 
Gas price derivatives (b)
— 2,226 
Deferred taxes on AFUDC (c)
7,537 7,491 
Employee benefit plans and related deferred taxes (d)
114,234 116,598 
Environmental (b)
1,395 1,413 
Loss on reacquired debt (b)
21,460 22,864 
Deferred taxes on flow through accounting (d)
54,199 47,515 
Decommissioning costs (b)
6,583 8,988 
Gas supply contract termination (b)
— 2,524 
Other regulatory assets (b)
26,064 26,404 
Total regulatory assets830,055 278,258 
   Less current regulatory assets(213,031)(51,676)
Regulatory assets, non-current$617,024 $226,582 
Regulatory liabilities
Deferred energy and gas costs (b)
$9,408 $13,253 
Gas price derivatives (b)
13,234 — 
Employee benefit plan costs and related deferred taxes (d)
39,203 40,256 
Cost of removal (b)
181,180 172,902 
Excess deferred income taxes (d)
266,477 285,259 
Other regulatory liabilities (d)
16,915 21,050 
Total regulatory liabilities526,417 532,720 
   Less current regulatory liabilities(30,156)(25,061)
Regulatory liabilities, non-current$496,261 $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.

16


Winter Storm Uri

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

Our Utilities submitted Winter Storm Uri cost recovery applications in our state jurisdictions seeking to recover $546 million of these incremental costs through separate tracking mechanisms over a weighted-average recovery period of 3.7 years. These incremental cost estimates are subject to adjustments as final decisions are issued by the respective utility commissions. In these applications, we seek approval to recover carrying costs. For the nine months ended September 30, 2021, $1.8 million of carrying costs were accrued and recorded to a regulatory asset. We are also seeking recovery of $13 million of previously disclosed Winter Storm Uri incremental costs through our existing regulatory mechanisms.

To date, Nebraska Gas and South Dakota Electric received commission approval of their Winter Storm Uri cost recovery applications. Additionally, Arkansas Gas, Iowa Gas and Wyoming Gas received approval for interim cost recovery subject to a final decision on carrying costs and recovery periods at a later date. In October 2021, Wyoming Gas filed a settlement agreement for their application with final rates to be implemented January 1, 2022. The settlement is subject to final approval by the commission. For the nine months ended September 30, 2021, our Utilities collected $15 million of Winter Storm Uri incremental costs 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 nine months ended September 30, 2021.

As part of the settlement agreement discussed further below, Kansas Gas will deliver $3.0 million of TCJA and state tax reform benefits to customers, annually, for each of the next three years starting in 2022 (approximately $9.1 million of total benefits expected to be delivered).

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. On October 5, 2021, Colorado Gas reached a settlement agreement with the CPUC Staff and various intervenors for a general rate increase. The settlement agreement is subject to review and approval by an ALJ and the CPUC. If approved, the settlement is expected to generate $6.5 million of new annual revenue with new rates effective January 1, 2022. The new revenue is based on a return on equity of 9.2% and a capital structure of 50.3% equity and 49.7% debt.

SSIR

On September 11, 2020, in accordance with the final Order from an earlier rate review filed on 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 system investments for three years effective January 1, 2022. The return on SSIR investments will be the current weighted-average cost of long-term debt.

17


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. 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.

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. On October 8, 2021, Kansas Gas reached a Global Settlement agreement with KCC Staff and various intervenors for a general rate increase and renewal of its safety and integrity rider. The settlement agreement is subject to review and approval by the KCC. If approved, the settlement will shift $6.6 million of rider revenue to base rates, which are expected to be effective January 1, 2022, and also allow rider renewal for at least five more years.

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 nine months ended September 30, 2021 and 2020. Sales tax and other similar taxes are excluded from revenues.

18


Three Months Ended September 30, 2021 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer types:(in thousands)
Retail$179,982 $115,908 $— $15,814 $(8,846)$302,858 
Transportation— 37,651 — — (110)37,541 
Wholesale3,856 — 26,058 — (23,725)6,189 
Market - off-system sales15,149 75 — — (1,638)13,586 
Transmission/Other13,913 9,863 — — (5,297)18,479 
Revenue from contracts with customers$212,900 $163,497 $26,058 $15,814 $(39,616)$378,653 
Other revenues203 1,186 462 574 (488)1,937 
Total revenues$213,103 $164,683 $26,520 $16,388 $(40,104)$380,590 
Timing of revenue recognition:
Services transferred at a point in time$— $— $— $15,814 $(8,846)$6,968 
Services transferred over time212,900 163,497 26,058 — (30,770)371,685 
Revenue from contracts with customers$212,900 $163,497 $26,058 $15,814 $(39,616)$378,653 

Three Months Ended September 30, 2020 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer Types:(in thousands)
Retail$169,505 $94,367 $— $14,668 $(8,100)$270,440 
Transportation— 38,196 — — (139)38,057 
Wholesale5,925 — 26,049 — (24,521)7,453 
Market - off-system sales9,535 36 — — (1,904)7,667 
Transmission/Other15,653 10,277 — — (5,235)20,695 
Revenue from contracts with customers$200,618 $142,876 $26,049 $14,668 $(39,899)$344,312 
Other revenues224 1,053 469 568 (36)2,278 
Total Revenues$200,842 $143,929 $26,518 $15,236 $(39,935)$346,590 
Timing of Revenue Recognition:
Services transferred at a point in time$— $— $— $14,668 $(8,100)$6,568 
Services transferred over time200,618 142,876 26,049 — (31,799)337,744 
Revenue from contracts with customers$200,618 $142,876 $26,049 $14,668 $(39,899)$344,312 
19


Nine Months Ended September 30, 2021 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer types:(in thousands)
Retail$536,952 $601,358 $— $43,751 $(23,093)$1,158,968 
Transportation— 117,251 — — (329)116,922 
Wholesale12,788 — 79,662 — (71,656)20,794 
Market - off-system sales31,746 235 — — (6,197)25,784 
Transmission/Other41,339 29,378 — — (15,892)54,825 
Revenue from contracts with customers$622,825 $748,222 $79,662 $43,751 $(117,167)$1,377,293 
Other revenues2,619 5,030 1,369 1,738 (1,455)9,301 
Total revenues$625,444 $753,252 $81,031 $45,489 $(118,622)$1,386,594 
Timing of revenue recognition:
Services transferred at a point in time$— $— $— $43,751 $(23,093)$20,658 
Services transferred over time622,825 748,222 79,662 — (94,074)1,356,635 
Revenue from contracts with customers$622,825 $748,222 $79,662 $43,751 $(117,167)$1,377,293 

Nine Months Ended September 30, 2020 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer Types:(in thousands)
Retail$459,949 $513,208 $— $43,917 $(23,855)$993,219 
Transportation— 113,096 — — (416)112,680 
Wholesale14,947 — 77,234 — (72,609)19,572 
Market - off-system sales17,940 197 — — (6,123)12,014 
Transmission/Other43,271 32,038 — — (14,080)61,229 
Revenue from contracts with customers$536,107 $658,539 $77,234 $43,917 $(117,083)$1,198,714 
Other revenues2,074 7,273 1,372 1,940 (819)11,840 
Total Revenues$538,181 $665,812 $78,606 $45,857 $(117,902)$1,210,554 
Timing of Revenue Recognition:
Services transferred at a point in time$— $— $— $43,917 $(23,855)$20,062 
Services transferred over time536,107 658,539 77,234 — (93,228)1,178,652 
Revenue from contracts with customers$536,107 $658,539 $77,234 $43,917 $(117,083)$1,198,714 

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.


20


(5)    Financing

Short-term Debt

We had the following Notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
September 30, 2021December 31, 2020
Balance Outstanding
Letters of Credit (a)
Balance Outstanding
Letters of Credit (a)
Revolving Credit Facility— 23,255 — 24,730 
CP Program332,525 — 234,040 — 
Total Notes payable$332,525 $23,255 $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.

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 nine months ended September 30, 2021 were $98.5 million. The weighted average interest rate on short-term borrowings related to our Revolving Credit Facility and CP Program at September 30, 2021 was 0.19%.

Term Loan

On February 24, 2021, we entered into a nine-month, $800 million unsecured term loan to provide additional liquidity and to meet our cash needs related to the incremental fuel, purchased power and natural gas costs from Winter Storm Uri. The term loan, carried no prepayment penalty and was 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. Proceeds from the August 26, 2021 public debt offering (discussed below) were used to repay the remaining balance on this term loan.

Long-term Debt

On August 26, 2021, we completed a public debt offering which consisted of $600 million, 1.037% three year senior unsecured notes due August 23, 2024. The notes include an optional redemption provision and may be redeemed, in whole or in part, without premium, on or after February 23, 2022. The proceeds from the offering, which were net of $3.7 million of deferred financing costs, were used to repay amounts outstanding under our term loan entered into on February 24, 2021.

Debt Covenants

Under our Revolving Credit Facility, 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 non-controlling 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 September 30, 2021:
As of September 30, 2021Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio62.4%Less than65%

21


Equity

At-the-Market Equity Offering Program

During the three months ended September 30, 2021, we issued a total of 0.3 million shares of common stock under the ATM for proceeds of $23 million, net of $0.2 million in issuance costs. During the nine months ended September 30, 2021, we issued a total of 0.9 million shares of common stock under the ATM for proceeds of $63 million, net of $0.6 million in issuance costs.


(6)    Earnings Per Share

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

Three Months Ended September 30,Nine Months Ended September 30,
2021202020212020
Net income available for common stock$44,112 $36,283 $165,589 $150,423 
Weighted average shares - basic63,341 62,575 62,950 62,310 
Dilutive effect of:
Equity compensation95 55 96 52 
Weighted average shares - diluted63,436 62,630 63,046 62,362 
Earnings per share of common stock:
Earnings per share, Basic$0.70 $0.58 $2.63 $2.41 
Earnings per share, Diluted$0.70 $0.58 $2.63 $2.41 

The following securities were excluded from the diluted earnings per share computation because of their anti-dilutive nature (in thousands):
Three Months Ended September 30,Nine Months Ended September 30,
2021202020212020
Equity compensation22 12 22 
Restricted stock— 49 40 
Anti-dilutive shares71 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.
22



Credit Risk

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

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

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

Derivatives and Hedging Activity

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

The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ 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 October 2021 through August 2024. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price forward contracts to deliver gas to our Choice Gas Program customers. The gain or loss on these designated derivatives is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and reclassified into earnings in the same period that the underlying hedged item is recognized in earnings. Effectiveness of our hedging position is evaluated at least quarterly.

23


The contract or notional amounts and terms of the electric and natural gas derivative commodity instruments held at our Utilities are composed of both long and short positions. We had the following net long positions as of:
September 30, 2021December 31, 2020
UnitsNotional
Amounts
Maximum
Term
(months) (a)
Notional
Amounts
Maximum
Term
(months) (a)
Natural gas futures purchasedMMBtus1,700,000 6620,000 3
Natural gas options purchased, netMMBtus8,420,000 63,160,000 3
Natural gas basis swaps purchasedMMBtus1,500,000 6900,000 3
Natural gas over-the-counter swaps, net (b)
MMBtus5,920,000 353,850,000 17
Natural gas physical contracts, net (c)
MMBtus18,758,835 717,513,061 22
Electric wholesale contracts (c)
MWh65,625 3219,000 12
__________
(a)    Term reflects the maximum forward period hedged.
(b)    As of September 30, 2021, 2,700,000 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 September 30, 2021, the Company posted $0.9 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.

The following table presents the fair value and balance sheet classification of our derivative instruments (in thousands) as of:
Balance Sheet LocationSeptember 30, 2021December 31, 2020
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivativesDerivative assets, current$6,989 $181 
Noncurrent commodity derivativesOther assets, non-current32 43 
Liability derivative instruments:
Current commodity derivativesDerivative liabilities, current— (108)
Total derivatives designated as hedges$7,021 $116 
Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivativesDerivative assets, current$5,327 $1,667 
Noncurrent commodity derivativesOther assets, non-current1,580 151 
Liability derivative instruments:
Current commodity derivativesDerivative liabilities, current(3,471)(1,936)
Total derivatives not designated as hedges$3,436 $(118)

24


Derivatives Designated as Hedge Instruments

The impacts of cash flow hedges on our Condensed Consolidated Statements of Comprehensive Income and Condensed Consolidated Statements of Income are presented below for the three and nine months ended September 30, 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 September 30,Three Months Ended September 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$712 $712 Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)$(712)$(712)
Commodity derivatives5,536 691 Fuel, purchased power and cost of natural gas sold331 (178)
Total$6,248 $1,403 $(381)$(890)

Nine Months Ended September 30,Nine Months Ended September 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$2,138 $2,138 Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)$(2,138)$(2,138)
Commodity derivatives6,896 959 Fuel, purchased power and cost of natural gas sold356 (734)
Total$9,034 $3,097 $(1,782)$(2,872)

As of September 30, 2021, $4.0 million of net gains related to our interest rate swaps and commodity derivatives are expected to be reclassified from AOCI into earnings as gains within the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

Derivatives Not Designated as Hedge Instruments

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Condensed Consolidated Statements of Income for the three and nine months ended September 30, 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 September 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$2,494 $(1,386)
Commodity derivatives - Natural GasFuel, purchased power and cost of natural gas sold4,004 1,777 
$6,498 $391 
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Nine Months Ended September 30,
20212020
Derivatives Not Designated as Hedging InstrumentsLocation of Gain/(Loss) on Derivatives Recognized in IncomeAmount of Gain/(Loss) on Derivatives Recognized in Income
(in thousands)
Commodity derivatives - ElectricFuel, purchased power and cost of natural gas sold$(2,628)$(228)
Commodity derivatives - Natural GasFuel, purchased power and cost of natural gas sold6,186 2,992 
$3,558 $2,764 

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) or gains included in our Regulatory asset or Regulatory liability related to the hedges in our Gas Utilities were $13.2 million and $(2.2) million as of September 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.
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As of September 30, 2021
Level 1Level 2Level 3
Cash Collateral and Counterparty
Netting (a)
Total
(in thousands)
Assets:
Commodity derivatives — Gas Utilities$— $32,298 $— $(18,370)$13,928 
Commodity derivatives — Electric Utilities$— $— $— $— $— 
Total$— $32,298 $— $(18,370)$13,928 
Liabilities:
Commodity derivatives — Gas Utilities$— $1,128 $— $(141)$987 
Commodity derivatives — Electric Utilities$— $2,484 $— $— $2,484 
Total$— $3,612 $— $(141)$3,471 
__________
(a)    As of September 30, 2021, $18 million of our commodity derivative assets and $0.1 million of our commodity derivative liabilities, as well as related collateral amounts, were subject to master netting agreements. Collateral amounts are included in Other current assets on the Condensed Consolidated Balance Sheets.

As of December 31, 2020
Level 1Level 2Level 3
Cash Collateral and Counterparty
Netting (a)
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 
__________
(a)    As of December 31, 2020, $1.5 million of our commodity derivative assets and $1.6 million of our commodity derivative liabilities, as well as related collateral amounts, were subject to master netting agreements. Collateral amounts are included in Other current assets on the Condensed Consolidated Balance Sheets.

Pension and Postretirement Plan Assets

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

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Other fair value measures

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

The following table presents the carrying amounts and fair values of financial instruments not recorded at fair value on the Condensed Consolidated Balance Sheets (in thousands) as of:
September 30, 2021December 31, 2020
Carrying
Amount
Fair ValueCarrying
Amount
Fair Value
Long-term debt, including current maturities (a)
$4,125,571 $4,614,244 $3,536,536 $4,208,167 
__________
(a)    Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified as Level 2 in the fair value hierarchy. Carrying amount of long-term debt is net of deferred financing costs.


(9)    Other Comprehensive Income

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

The following table details reclassifications out of AOCI and into Net income. The amounts in parentheses below indicate decreases to Net income in the Condensed Consolidated Statements of Income for the period (in thousands):
Location on the Condensed Consolidated Statements of IncomeAmount Reclassified from AOCI
Three Months Ended September 30,Nine Months Ended September 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)$(712)$(712)$(2,138)$(2,138)
Commodity contractsFuel, purchased power and cost of natural gas sold331 (178)356 (734)
(381)(890)(1,782)(2,872)
Income taxIncome tax (expense)(26)209 308 680 
Total reclassification adjustments related to cash flow hedges, net of tax$(407)$(681)$(1,474)$(2,192)
Amortization of components of defined benefit plans:
Prior service costOperations and maintenance$25 $24 $74 $79 
Actuarial gain (loss)Operations and maintenance(598)(597)(1,793)(1,791)
(573)(573)(1,719)(1,712)
Income taxIncome tax (expense)133 143 492 407 
Total reclassification adjustments related to defined benefit plans, net of tax$(440)$(430)$(1,227)$(1,305)
Total reclassifications$(847)$(1,111)$(2,701)$(3,497)
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Balances by classification included within AOCI, net of tax on the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):
Derivatives Designated as Cash Flow Hedges
Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
As of December 31, 2020$(12,558)$$(14,790)$(27,346)
Other comprehensive income (loss)
before reclassifications— 5,476 — 5,476 
Amounts reclassified from AOCI1,743 (269)1,227 2,701 
As of September 30, 2021$(10,815)$5,209 $(13,563)$(19,169)
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— 181 55 236 
Amounts reclassified from AOCI1,630 562 1,305 3,497 
As of September 30, 2020$(13,492)$287 $(13,717)$(26,922)


(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 September 30,Nine Months Ended September 30,
2021202020212020
Service cost$1,260 $1,352 $3,779 $4,058 
Interest cost2,328 3,356 6,984 10,069 
Expected return on plan assets(5,219)(5,647)(15,657)(16,943)
Net loss1,828 2,093 5,486 6,279 
Net periodic benefit cost$197 $1,154 $592 $3,463 

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 September 30,Nine Months Ended September 30,
2021202020212020
Service cost$560 $514 $1,678 $1,542 
Interest cost264 412 793 1,237 
Expected return on plan assets(34)(46)(102)(137)
Prior service cost (benefit)(108)(136)(326)(410)
Net loss116 350 15 
Net periodic benefit cost$798 $749 $2,393 $2,247 

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Supplemental Non-qualified Defined Benefit and Defined Contribution Plans

The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands):
Three Months Ended September 30,Nine Months Ended September 30,
2021202020212020
Service cost$235 $1,035 $1,948 $1,482 
Interest cost176 274 530 824 
Prior service cost— — 
Net loss439 425 1,316 1,277 
Net periodic benefit cost$850 $1,735 $3,794 $3,584 

Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made in the first nine months of 2021 and anticipated contributions for 2021 and 2022 are as follows (in thousands):
Contributions MadeAdditional ContributionsContributions
Nine Months Ended September 30, 2021Anticipated for 2021Anticipated for 2022
Defined Benefit Pension Plan$— $— $3,900 
Non-pension Defined Benefit Postretirement Healthcare Plan$4,145 $1,382 $5,202 
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans$1,445 $482 $2,149 

(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 $130 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 2041. 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 September 30, 2021.

Income Tax (Expense) and Effective Tax Rates

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

Income tax (expense) and the effective tax rate were comparable to the same period in the prior year.

Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 2020

Income tax (expense) for the nine months ended September 30, 2021 was $(6.3) million compared to $(25) million reported for the same period in 2020. For the nine months ended September 30, 2021, the effective tax rate was 3.5% compared to 13.6% 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), $3.2 million of increased tax benefits from federal production tax credits associated with new wind assets, $2.2 million of increased tax benefits from amortization of excess deferred income taxes, $1.9 million of tax benefits from various statutory rate changes and $1.1 million of increased flow-through tax benefits related to repairs and certain indirect costs. These current year tax benefits were partially offset by a prior year tax benefit from the reversal of accrued excess deferred income taxes as part of resolving the last of the Company’s open dockets seeking approval of its TCJA plans.

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(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 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:September 30, 2021December 31, 2020
Electric Utilities$3,267,074 $3,120,928 
Gas Utilities5,052,898 4,376,204 
Power Generation398,915 404,220 
Mining76,791 77,085 
Corporate and Other114,712 110,349 
Total assets$8,910,390 $8,088,786 

Three Months Ended September 30, 2021External Operating RevenueInter-company Operating Revenue Total Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities$207,374 $203 $5,526 $— $213,103 
Gas Utilities161,977 1,087 1,520 99 164,683 
Power Generation2,333 412 23,725 50 26,520 
Mining6,969 235 8,845 339 16,388 
Inter-company eliminations— — (39,616)(488)(40,104)
Total$378,653 $1,937 $— $— $380,590 

Three Months Ended September 30, 2020External Operating RevenueInter-company Operating Revenue Total Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities$194,941 $224 $5,677 $— $200,842 
Gas Utilities141,275 863 1,601 190 143,929 
Power Generation1,528 414 24,521 55 26,518 
Mining6,568 777 8,100 (209)15,236 
Inter-company eliminations— — (39,899)(36)(39,935)
Total$344,312 $2,278 $— $— $346,590 

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Nine Months Ended September 30, 2021External Operating RevenueInter-company Operating RevenueTotal Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities$604,966 $2,619 $17,859 $— $625,444 
Gas Utilities743,663 4,745 4,559 285 753,252 
Power Generation8,006 1,219 71,656 150 81,031 
Mining20,658 718 23,093 1,020 45,489 
Inter-company eliminations— — (117,167)(1,455)(118,622)
Total$1,377,293 $9,301 $— $— $1,386,594 

Nine Months Ended September 30, 2020External Operating RevenueInter-company Operating Revenue Total Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities$518,641 $2,074 $17,466 $— $538,181 
Gas Utilities655,386 7,083 3,153 190 665,812 
Power Generation4,625 1,206 72,609 166 78,606 
Mining20,062 1,477 23,855 463 45,857 
Inter-company eliminations— — (117,083)(819)(117,902)
Total$1,198,714 $11,840 $— $— $1,210,554 

Three Months Ended September 30,Nine Months Ended September 30,
2021202020212020
Adjusted operating income:
Electric Utilities$57,608 $52,083 $114,989 $121,726 
Gas Utilities17,257 18,147 139,336 139,253 
Power Generation10,323 8,738 32,842 31,489 
Mining4,908 3,505 11,813 9,992 
Corporate and Other(223)(239)(3,526)(108)
Operating income89,873 82,234 295,454 302,352 
Interest expense, net(38,018)(36,041)(113,820)(107,039)
Impairment of investment— — — (6,859)
Other income (expense), net1,560 (1,193)1,635 (703)
Income tax (expense)(5,253)(4,651)(6,333)(25,484)
Net income48,162 40,349 176,936 162,267 
Net income attributable to non-controlling interest(4,050)(4,066)(11,347)(11,844)
Net income available for common stock$44,112 $36,283 $165,589 $150,423 


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(13)    Selected Balance Sheet Information

Accounts Receivable and Allowance for Credit Losses

Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
September 30, 2021December 31, 2020
Accounts receivable, trade$120,930 $146,899 
Unbilled revenue63,338 126,065 
Less: Allowance for credit losses(2,312)(7,003)
Accounts receivable, net$181,956 $265,961 

Changes to allowance for credit losses for the nine months ended September 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 September 30,
2021$7,003 $1,111 $2,420 $(8,222)$2,312 
2020$2,444 $8,471 $3,720 $(6,026)$8,609 

Materials, Supplies and Fuel

The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
September 30, 2021December 31, 2020
Materials and supplies$85,612 $85,250 
Fuel - Electric Utilities1,240 1,531 
Natural gas in storage58,891 30,619 
Total materials, supplies and fuel$145,743 $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:
September 30, 2021December 31, 2020
Accrued employee compensation, benefits and withholdings$72,328 $77,806 
Accrued property taxes44,231 47,105 
Customer deposits and prepayments53,652 52,185 
Accrued interest46,532 31,520 
Other (none of which is individually significant)33,092 34,996 
Total accrued liabilities$249,835 $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, Kansas Gas and Wyoming Gas regulatory activity disclosed in Note 2.


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

The following discussions should be read in conjunction with the Notes contained herein and Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in the 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. Proceeds from the August 26, 2021 debt transaction were used to repay amounts outstanding under this term loan. See Note 5 of the Notes to Condensed Consolidated Financial Statements for further 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. To date, several of our Utilities have received interim or final Commission Orders and have begun recovering costs from customers. See Note 2 of the Notes to Condensed Consolidated Financial Statements for further information on our regulatory activity.

COVID-19 Update

For the nine months ended September 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.

On September 9, 2021 the Biden administration announced a mandatory COVID-19 vaccination plan, which directs OSHA to develop a rule requiring employers with 100 or more employees to ensure their workforce is fully vaccinated or require any workers who remain unvaccinated to produce a negative test result on at least a weekly basis. We are closely monitoring updates from OSHA including the effective date of this rule. If an OSHA vaccine rule is implemented, the extent of the regulatory impact is unclear but it could have an adverse impact on the Company's workforce, labor relations and operations.

As we look forward, our operating results could be affected by COVID-19 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

Wyoming Electric announced its Ready Wyoming electric transmission expansion initiative. The 285-mile, multi-phase transmission expansion project will serve the growing needs of customers by enhancing the resiliency of its overall electric system and expanding access to power markets and renewable resources. The project will help Wyoming Electric maintain top-quartile reliability and enable economic growth in the Cheyenne region. Wyoming Electric plans to file an application seeking WPSC approval for the project in the first quarter of 2022. If approved, construction is expected to commence in early 2023.

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.

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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. 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.

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 of the Notes to Condensed Consolidated Financial Statements for recent regulatory activity for our Gas Utilities in Colorado, Iowa, Kansas and Nebraska.

Power Generation

In September 2021, Wygen I experienced an unplanned outage which had a $2.3 million negative impact to operating income for the three and nine months ended September 30, 2021.

Corporate and Other

On August 26, 2021, we completed a public debt offering which consisted of $600 million, 1.037% 3-year senior unsecured notes due August 23, 2024. The proceeds from the offering were used to repay amounts outstanding under our term loan entered into on February 24, 2021. See Note 5 of the Notes to Condensed Consolidated Financial Statements for further information.

On July 19, 2021, we amended and restated our corporate Revolving Credit Facility. See Note 5 of the Notes to Condensed Consolidated Financial Statements 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 nine months ended September 30, 2021 and 2020, and our financial condition as of September 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.
35



Consolidated Summary and Overview
Three Months Ended September 30,Nine Months Ended September 30,
2021202020212020
(in thousands, except per share amounts)
Adjusted operating income (a):
Electric Utilities$57,608 $52,083 $114,989 $121,726 
Gas Utilities17,257 18,147 139,336 139,253 
Power Generation10,323 8,738 32,842 31,489 
Mining4,908 3,505 11,813 9,992 
Corporate and Other(223)(239)(3,526)(108)
Operating income89,873 82,234 295,454 302,352 
Interest expense, net(38,018)(36,041)(113,820)(107,039)
Impairment of investment— — — (6,859)
Other income (expense), net1,560 (1,193)1,635 (703)
Income tax (expense)(5,253)(4,651)(6,333)(25,484)
Net income48,162 40,349 176,936 162,267 
Net income attributable to non-controlling interest(4,050)(4,066)(11,347)(11,844)
Net income available for common stock$44,112 $36,283 165,589 150,423 
Total earnings per share of common stock, Diluted$0.70 $0.58 $2.63 $2.41 
__________
(a)    Adjusted operating income recognizes intersegment revenues and costs for Colorado Electric’s PPA with Black Hills Colorado IPP on an accrual basis rather than as a finance lease. This presentation of segment information does not impact consolidated financial results.

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

The variance to the prior year included the following:

Electric Utilities’ adjusted operating income increased $5.5 million primarily due to favorable mark-to-market adjustments on wholesale energy contacts, residential customer growth and increased usage, and increased power marketing and wholesale revenues which were partially offset by higher operating expenses;
Gas Utilities’ adjusted operating income decreased $0.9 million primarily due to higher operating expenses and unfavorable weather which led to decreased irrigation loads and lower heating demand mostly offset by favorable market-to-market adjustments on wholesale commodity contracts, new rates and prior year COVID-19 impacts;
Power Generation’s adjusted operating income increased $1.6 million primarily driven by lower operating expenses due to early retirement of certain assets in the prior year partially offset by negative impacts of an unplanned outage at Wygen I;
Mining’s adjusted operating income increased $1.4 million primarily due to higher prices per ton sold under our cost based supply agreements;
Interest expense increased $2.0 million due to higher debt balances partially offset by lower rates; and
Other income increased $2.8 million primarily due to lower non-service pension costs driven by a lower discount rate, lower costs for our non-qualified benefit plans which were driven by market performance and recognition of death benefits from Company-owned life insurance.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

The variance to the prior year included the following:

Electric Utilities’ adjusted operating income decreased $6.7 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 power marketing and wholesale revenues, residential customer growth and increased usage, and prior year COVID-19 impacts;
Gas Utilities’ adjusted operating income increased $0.1 million primarily due to new rates, higher heating demand from colder weather and favorable market-to-market adjustments on wholesale commodity contracts 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;
36


Power Generation’s adjusted operating income increased $1.4 million primarily due to lower operating expenses driven by early retirement of certain assets in the prior year and favorable impacts from Winter Storm Uri partially offset by unfavorable impacts from current year outages;
Mining’s adjusted operating income increased $1.8 million primarily due to lower operating expenses driven by lower tons sold and overburden removed;
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;
Interest expense increased $6.8 million 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;
Other income increased $2.3 million due to lower non-service pension costs driven by a lower discount rate and recognition of death benefits from Company-owned life insurance; and
Income tax expense decreased $19.2 million 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.

Segment Operating Results

A discussion of operating results from our business segments follows.


Non-GAAP Financial Measure

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

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

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


Electric Utilities

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

Three Months Ended September 30,Nine Months Ended September 30,
20212020Variance20212020Variance
Revenue$213,103 $200,842 $12,261 $625,444 $538,181 $87,263 
Total fuel and purchased power82,794 77,885 4,909 290,101 201,398 88,703 
Gross margin (non-GAAP)130,309 122,957 7,352 335,343 336,783 (1,440)
Operations and maintenance47,293 47,426 (133)144,832 144,956 (124)
Depreciation and amortization25,408 23,448 1,960 75,522 70,101 5,421 
Total operating expenses72,701 70,874 1,827 220,354 215,057 5,297 
Adjusted operating income$57,608 $52,083 $5,525 $114,989 $121,726 $(6,737)

37


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

Gross margin for the three months ended September 30, 2021 increased as a result of the following:
(in millions)
Mark-to-market on wholesale energy contracts$3.9 
Residential customer growth and increased usage per customer2.5 
Increased commercial and industrial demand1.2 
Power marketing and wholesale1.1 
Prior year COVID-19 impacts0.2 
Prior year release of TCJA revenue reserves(1.5)
Weather(0.5)
Other0.5 
Total change in Gross margin (non-GAAP)$7.4 

Operations and maintenance expense was comparable to the same period in the prior year.

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

Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 2020:

Gross margin for the nine months ended September 30, 2021 decreased as a result of the following:
(in millions)
TCJA-related bill credits (a)
$(10.2)
Winter Storm Uri impacts (b)
(2.9)
Mark-to-market on wholesale energy contracts(2.4)
Prior year release of TCJA revenue reserves(2.2)
Weather(0.1)
Power marketing and wholesale6.6 
Residential customer growth and increased usage per customer3.2 
Rider recovery2.9 
Increased commercial and industrial demand1.7 
Prior year COVID-19 impacts1.7 
Other0.2 
Total change in Gross margin (non-GAAP)$(1.5)
________________
(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)    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.

38


Operating Statistics
Revenue (in thousands)Quantities Sold (MWh)
Three Months Ended
September 30,
Nine Months Ended
September 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
20212020202120202021202020212020
Residential$66,138 $62,395 $192,349 $167,048 419,001 405,989 1,150,150 1,113,821 
Commercial70,696 64,756 214,512 178,979 576,037 538,299 1,570,455 1,492,239 
Industrial37,323 35,660 115,518 99,725 459,076 462,545 1,316,060 1,382,710 
Municipal5,069 4,834 14,471 12,732 47,515 46,256 123,620 121,027 
Subtotal Retail Revenue - Electric179,226 167,645 536,850 458,484 1,501,629 1,453,089 4,160,285 4,109,797 
Contract Wholesale7,939 5,924 22,155 14,947 129,221 129,960 415,979 348,991 
Off-system/Power Marketing Wholesale11,065 9,535 22,378 17,939 151,250 167,494 467,440 469,590 
Other14,873 17,738 44,061 46,811 — — — — 
Total Revenue and Energy Sold213,103 200,842 625,444 538,181 1,782,100 1,750,543 5,043,704 4,928,378 
Other Uses, Losses or Generation, net— — — — 139,093 118,410 363,815 294,466 
Total Revenue and Energy213,103 200,842 625,444 538,181 1,921,193 1,868,953 5,407,519 5,222,844 
Less cost of fuel and purchased power82,794 77,885 290,101 201,398 
Gross Margin (non-GAAP)$130,309 $122,957 $335,343 $336,783 

Three Months Ended September 30,Revenue
(in thousands)
Gross Margin (non-GAAP) (in thousands)
Quantities Sold (MWh)(a)
202120202021202020212020
Colorado Electric$83,274 $74,742 $45,482 $42,236 720,592 666,916 
South Dakota Electric81,787 78,861 62,081 58,062 709,862 699,150 
Wyoming Electric48,042 47,239 22,746 22,659 490,739 502,887 
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold$213,103 $200,842 $130,309 $122,957 1,921,193 1,868,953 

Nine Months Ended September 30,Revenue
(in thousands)
Gross Margin (non-GAAP) (in thousands)
Quantities Sold (MWh)(a)
202120202021202020212020
Colorado Electric$227,328 $191,197 $103,982 $106,961 1,945,741 1,765,501 
South Dakota Electric250,617 213,059 163,523 163,659 1,997,696 1,954,902 
Wyoming Electric147,499 133,925 67,838 66,163 1,464,082 1,502,441 
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold$625,444 $538,181 $335,343 $336,783 5,407,519 5,222,844 
________________
(a)    Includes company uses, line losses, and excess exchange production.
39



Three Months Ended September 30,Nine Months Ended September 30,
Quantities Generated and Purchased (MWh)2021202020212020
Generated:
Coal589,194 592,681 1,569,410 1,712,540 
Natural Gas and Oil231,433 199,408 535,148 453,950 
Wind90,496 54,518 315,654 191,696 
Total Generated911,123 846,607 2,420,212 2,358,186 
Purchased1,010,070 1,022,346 2,987,307 2,864,658 
Total Generated and Purchased1,921,193 1,868,953 5,407,519 5,222,844 


Three Months Ended September 30,Nine Months Ended September 30,
Quantities Generated and Purchased (MWh)2021202020212020
Generated:
Colorado Electric150,646 97,450 351,723 271,957 
South Dakota Electric538,632 518,821 1,450,114 1,434,353 
Wyoming Electric221,845 230,336 618,375 651,876 
Total Generated911,123 846,607 2,420,212 2,358,186 
Purchased:
Colorado Electric569,946 569,466 1,594,018 1,493,544 
South Dakota Electric171,229 180,329 547,582 520,549 
Wyoming Electric268,895 272,551 845,707 850,565 
Total Purchased1,010,070 1,022,346 2,987,307 2,864,658 
Total Generated and Purchased1,921,193 1,868,953 5,407,519 5,222,844 


Three Months Ended September 30,
20212020
Degree DaysActualVariance from
Normal
ActualVariance from
Normal
Heating Degree Days:
Colorado Electric22 (78)%99 %
South Dakota Electric90 (60)%202 (10)%
Wyoming Electric112 (62)%208 (29)%
Combined (a)
63 (65)%156 (14)%
Cooling Degree Days:
Colorado Electric942 38 %987 44 %
South Dakota Electric649 22 %561 %
Wyoming Electric487 63 %492 65 %
Combined (a)
751 35 %742 34 %
40



Nine Months Ended September 30,
20212020
Degree DaysActualVariance from
Normal
ActualVariance from
Normal
Heating Degree Days
Colorado Electric3,348 (1)%3,073 (9)%
South Dakota Electric4,462 — %4,440 — %
Wyoming Electric4,594 %4,356 (3)%
Combined (a)
3,979 — %3,799 (4)%
Cooling Degree Days:
Colorado Electric1,242 39 %1,369 53 %
South Dakota Electric816 29 %681 %
Wyoming Electric604 74 %593 70 %
Combined (a)
968 39 %977 41 %
____________________
(a)    Combined actuals are calculated based on the weighted average number of total customers by state.

Three Months Ended September 30,Nine Months Ended September 30,
Contracted generating facilities Availability by fuel type (a)
2021202020212020
Coal (b)
96.3 %97.4 %88.5 %94.1 %
Natural Gas and diesel oil (b) (c)
96.5 %79.7 %93.8 %80.5 %
Wind97.0 %97.7 %95.6 %98.3 %
Total Availability96.5 %86.8 %92.4 %86.3 %
Wind capacity factor34.1 %33.2 %38.0 %39.3 %
____________________
(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.


41


Gas Utilities

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

Three Months Ended September 30,Nine Months Ended September 30,
20212020Variance20212020Variance
Revenue:
Natural gas - regulated$150,075 $128,468 $21,607 $700,617 $612,797 $87,820 
Other - non-regulated services14,608 15,461 (853)52,635 53,015 (380)
Total revenue164,683 143,929 20,754 753,252 665,812 87,440 
Cost of sales:
Natural gas - regulated43,883 25,235 18,648 289,167 222,144 67,023 
Other - non-regulated services(749)1,800 (2,549)10,132 4,874 5,258 
Total cost of sales43,134 27,035 16,099 299,299 227,018 72,281 
Gross margin (non-GAAP)121,549 116,894 4,655 453,953 438,794 15,159 
Operations and maintenance78,161 73,642 4,519 237,624 223,351 14,273 
Depreciation and amortization26,131 25,105 1,026 76,993 76,190 803 
Total operating expenses104,292 98,747 5,545 314,617 299,541 15,076 
Adjusted operating income$17,257 $18,147 $(890)$139,336 $139,253 $83 

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

Gross margin for the three months ended September 30, 2021 increased as a result of:
(in millions)
Mark-to-market on non-utility natural gas commodity contracts$2.3 
New rates2.0 
Winter Storm Uri carrying costs (a)
1.7 
Prior year COVID-19 impacts0.8 
Weather (b)
(3.4)
Other1.3 
Total increase in Gross margin (non-GAAP)$4.7 
__________
(a)    In certain jurisdictions, we have accrued Winter Storm Uri carrying costs and began recovering from customers. See Note 2 of the Notes to Condensed Consolidated Financial Statements for additional information.
(b)    Weather impacts for the three months ended September 30, 2021 compared to the same period in the prior year include decreased irrigation loads to agriculture customers and decreased heating demand due to warmer temperatures.

Operations and maintenance expense increased primarily due to $3.4 million of higher employee costs, $1.2 million of higher outside services related expenses, $1.1 million of increased property taxes due to a higher asset base and $0.7 million of prior year COVID-19 savings due to lower travel and training expenses partially offset by $2.2 million of decreased bad debt expense associated with lower expected credit losses.

Depreciation and amortization increased primarily due to a higher asset base driven by prior and current year capital expenditures mostly offset by lower depreciation rates approved in the Nebraska Gas and Colorado Gas rate reviews.
42


Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 2020:

Gross margin for the nine months ended September 30, 2021 increased as a result of the following:
(in millions)
New rates$16.7 
Weather4.2 
Mark-to-market on non-utility natural gas commodity contracts3.5 
Winter Storm Uri carrying costs (a)
1.7 
Prior year COVID-19 impacts1.7 
Black Hills Energy Services Winter Storm Uri costs (b)
(8.2)
TCJA-related bill credits (c)
(2.9)
Non-utility - Service Guard Comfort Plan and Gas Supply Services(2.9)
Other1.4 
Total increase in Gross margin (non-GAAP)$15.2 
__________
(a)    In certain jurisdictions, we have accrued Winter Storm Uri carrying costs and began recovering from customers. See Note 2 of the Notes to Condensed Consolidated Financial Statements for additional information.
(b)    Black Hills Energy Services offers fixed contract pricing for non-regulated gas supply services to our regulated natural gas customers. The increased cost of natural gas sold during Winter Storm Uri is not recoverable through a regulatory mechanism.
(c)    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 $10.3 million of higher employee costs, $4.0 million of higher outside services related expenses, $3.4 million of higher facilities and office related expenses driven by prior year COVID-19 savings, and $2.7 million of increased property taxes due to a higher asset base partially offset by $5.6 million of decreased bad debt expense associated with lower expected credit losses.

Depreciation and amortization increased primarily due to a higher asset base driven by prior and current year capital expenditures mostly offset by lower depreciation rates approved in the Nebraska Gas and Colorado Gas rate reviews.

Operating Statistics
Revenue (in thousands)
Gross Margin (non-GAAP) (in thousands)
Gas Utilities Quantities Sold & Transported (Dth)
Three Months Ended
September 30,
Three Months Ended
September 30,
Three Months Ended
September 30,
202120202021202020212020
Residential$68,646 $61,515 $49,349 $48,165 3,564,722 4,058,040 
Commercial27,038 19,940 13,999 12,821 2,426,019 2,354,719 
Industrial13,863 7,280 2,316 2,514 2,873,540 2,674,127 
Other2,706 1,271 2,706 1,271 — — 
Total Distribution112,253 90,006 68,370 64,771 8,864,281 9,086,886 
Transportation and Transmission37,822 38,462 37,822 38,462 34,735,601 33,668,174 
Total Regulated150,075 128,468 106,192 103,233 43,599,882 42,755,060 
Non-regulated Services14,608 15,461 15,357 13,661 
Total Gas Revenue & Gross Margin (non-GAAP)$164,683 $143,929 $121,549 $116,894 
43


Revenue (in thousands)Gross Margin (non-GAAP) (in thousands)Gas Utilities Quantities Sold & Transported (Dth)
Nine Months Ended
September 30,
Nine Months Ended
September 30,
Nine Months Ended
September 30,
202120202021202020212020
Residential$401,413 $351,986 $219,885 $207,654 42,708,511 40,790,670 
Commercial155,015 127,617 66,447 61,676 20,732,271 19,155,051 
Industrial24,576 18,539 5,505 6,697 5,109,501 5,771,732 
Other1,816 856 1,816 856 — — 
Total Distribution582,820 498,998 293,653 276,883 68,550,283 65,717,453 
Transportation and Transmission117,797 113,799 117,797 113,770 114,124,253 108,967,182 
Total Regulated700,617 612,797 411,450 390,653 182,674,536 174,684,635 
Non-regulated Services52,635 53,015 42,503 48,141 
Total Gas Revenue & Gross Margin (non-GAAP)$753,252 $665,812 $453,953 $438,794 

Revenue (in thousands)Gross Margin (non-GAAP) (in thousands)Gas Utilities Quantities Sold & Transported (Dth)
Three Months Ended
September 30,
Three Months Ended
September 30,
Three Months Ended
September 30,
202120202021202020212020
Arkansas Gas$25,188 $21,043 $18,468 $17,400 4,319,944 3,925,893 
Colorado Gas22,452 22,724 17,097 16,972 3,798,587 3,702,666 
Iowa Gas22,015 18,155 14,442 14,672 5,810,932 5,628,110 
Kansas Gas25,972 18,591 13,600 13,099 9,075,960 8,564,408 
Nebraska Gas51,538 46,315 42,896 39,755 16,174,821 16,525,547 
Wyoming Gas17,518 17,101 15,046 14,996 4,419,638 4,408,436 
Total Gas Revenue & Gross Margin (non-GAAP)$164,683 $143,929 $121,549 $116,894 43,599,882 42,755,060 

Revenue (in thousands)Gross Margin (non-GAAP) (in thousands)Gas Utilities Quantities Sold & Transported (Dth)
Nine Months Ended
September 30,
Nine Months Ended
September 30,
Nine Months Ended
September 30,
202120202021202020212020
Arkansas Gas$145,176 $124,621 $93,319 $88,161 23,345,095 19,795,077 
Colorado Gas135,764 123,943 75,919 73,785 23,121,887 21,845,915 
Iowa Gas108,600 94,386 53,082 50,355 27,141,518 25,429,502 
Kansas Gas87,198 70,571 45,110 44,162 26,694,184 25,202,180 
Nebraska Gas187,673 170,447 124,923 122,140 59,281,802 56,857,061 
Wyoming Gas88,841 81,844 61,600 60,191 23,090,050 25,554,900 
Total Gas Revenue & Gross Margin (non-GAAP)$753,252 $665,812 $453,953 $438,794 182,674,536 174,684,635 


44



Three Months Ended September 30,
20212020
Heating Degree DaysActualVariance
from Normal
ActualVariance
from Normal
Arkansas Gas (a)
11(74)%24(44)%
Colorado Gas92(51)%159(26)%
Iowa Gas42(70)%1401%
Kansas Gas (a)
10(82)%7027%
Nebraska Gas33(70)%109(1)%
Wyoming Gas153(50)%245(20)%
Combined Gas (b)
53(61)%125(13)%

Nine Months Ended September 30,
20212020
Heating Degree Days:ActualVariance
from Normal
ActualVariance
from Normal
Arkansas Gas (a)
2,5151%2,036(18)%
Colorado Gas3,922(4)%3,797(7)%
Iowa Gas4,155(1)%4,104(2)%
Kansas Gas (a)
3,0794%2,851(4)%
Nebraska Gas3,754(1)%3,636(4)%
Wyoming Gas4,7781%4,678(1)%
Combined Gas (b)
3,978—%3,731(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.


Power Generation

Our Power Generation segment operating results were as follows (in thousands):
Three Months Ended September 30,Nine Months Ended September 30,
20212020Variance20212020Variance
Revenue$26,520 $26,518 $$81,031 $78,606 $2,425 
Fuel expense2,547 2,320 227 7,839 6,692 1,147 
Operations and maintenance8,233 10,539 (2,306)24,913 24,886 27 
Depreciation and amortization5,417 4,921 496 15,437 15,539 (102)
Total operating expense16,197 17,780 (1,583)48,189 47,117 1,072 
Adjusted operating income$10,323 $8,738 $1,585 $32,842 $31,489 $1,353 
45



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

The increase in current year adjusted operating income was primarily driven by a prior year $3.1 million expense related to the early retirement of certain assets partially offset by $2.3 million of negative impacts from a current year unplanned outage at Wygen I.

Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 2020:

Adjusted operating income increased compared to the same period in the prior year primarily due to a prior year $3.1 million expense related to the early retirement of certain assets and $1.7 million of favorable Winter Storm Uri impacts realized under Black Hills Wyoming’s Economy Energy PSA partially offset by negative impacts of current year planned and unplanned outages.

Operating Statistics
Revenue (in thousands)
Quantities Sold (MWh) (a)
Revenue (in thousands)
Quantities Sold (MWh) (a)
Three Months Ended September 30,Nine Months Ended September 30,
20212020202120202021202020212020
Black Hills Colorado IPP$14,627 $14,527 275,237 301,934 $42,862 $42,917 718,496 830,860 
Black Hills Wyoming (b)
10,634 10,757 146,525 157,855 34,208 31,403 453,291 471,073 
Black Hills Electric Generation1,259 1,234 72,493 65,697 3,961 4,286 257,511 255,605 
Total Power Generation Revenue and Quantities Sold$26,520 $26,518 494,255 525,486 $81,031 $78,606 1,429,298 1,557,538 

Three Months Ended September 30,Nine Months Ended September 30,
Quantities Generated and Purchased (MWh) (a)
Fuel Type2021202020212020
Generated
Black Hills Colorado IPPNatural Gas275,237 301,934 718,496 830,860 
Black Hills Wyoming (b)
Coal123,705 139,313 388,059 408,545 
Black Hills Electric GenerationWind72,493 65,697 257,511 255,605 
Total Generated471,435 506,944 1,364,066 1,495,010 
Purchased
Black Hills Wyoming (b)
Various23,575 18,004 68,184 62,097 
Total Purchased23,575 18,004 68,184 62,097 
____________
(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 September 30,Nine Months Ended September 30,
Contracted generating facilities Availability by fuel type (a)
2021202020212020
Coal (b)
84.9 %96.1 %90.4 %94.5 %
Natural gas (b)
99.7 %99.8 %95.3 %99.6 %
Wind96.2 %90.6 %95.9 %92.8 %
Total Availability96.0 %95.8 %94.7 %96.3 %
Wind capacity factor21.5 %19.4 %25.6 %25.7 %
____________________
(a)    Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.
(b)     2021 included planned and unplanned outages at Wygen I and planned outages at Pueblo Airport Generation.

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Mining

Our Mining segment operating results were as follows (in thousands):
Three Months Ended September 30,Nine Months Ended September 30,
20212020Variance20212020Variance
Revenue$16,388 $15,236 $1,152 $45,489 $45,857 $(368)
Operations and maintenance9,344 8,923 421 26,956 28,481 (1,525)
Depreciation, depletion and amortization2,136 2,808 (672)6,720 7,384 (664)
Total operating expenses11,480 11,731 (251)33,676 35,865 (2,189)
Adjusted operating income$4,908 $3,505 $1,403 $11,813 $9,992 $1,821 

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

Revenue increased reflecting a 6% increase in price per ton sold driven by contract price adjustments based on actual mining costs.

Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 2020:

Current year revenue was comparable due to fewer tons sold driven primarily by planned and unplanned outages at the Gillette, Wyoming energy complex mostly offset by a 4% increase in price per ton sold driven by contract price adjustments based on actual mining costs. Operating expenses decreased primarily due to lower overburden and processing costs.

Operating Statistics

The following table provides certain operating statistics for our Mining segment (in thousands, except for Revenue per ton):
Three Months Ended September 30,Nine Months Ended September 30,
2021202020212020
Tons of coal sold960 940 2,691 2,808 
Cubic yards of overburden moved1,757 1,595 5,188 6,073 
Revenue per ton$16.47 $15.60 $16.26 $15.64 


Corporate and Other

Corporate and Other operating results were as follows (in thousands):
Three Months Ended September 30,Nine Months Ended September 30,
20212020Variance20212020Variance
Adjusted operating income (loss)$(223)$(239)$16 $(3,526)$(108)$(3,418)

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

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

Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 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.
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Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax (Expense)
Three Months Ended September 30,Nine Months Ended September 30,
20212020Variance20212020Variance
(in thousands)
Interest expense, net$(38,018)$(36,041)$(1,977)$(113,820)$(107,039)$(6,781)
Impairment of investment— — $— $— $(6,859)$6,859 
Other income (expense), net1,560 (1,193)$2,753 $1,635 $(703)$2,338 
Income tax (expense)(5,253)(4,651)$(602)$(6,333)$(25,484)$19,151 

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

Interest Expense

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

Other Income (Expense)

The increase in Other income was primarily due to lower non-service pension costs driven by a lower discount rate, lower costs for our non-qualified benefit plans which were driven by market performance and recognition of death benefits from Company-owned life insurance.

Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 2020:

Interest Expense

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

Impairment of Investment

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

Other Income (Expense)

The increase in Other income was primarily due to lower non-service pension costs driven by a lower discount rate and recognition of death benefits from Company-owned life insurance.

Income Tax (Expense)

For the nine months ended September 30, 2021, the effective tax rate was 3.5% compared to 13.6% 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.

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.


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Cash Flow Activities

The following table summarizes our cash flows for the nine months ended September 30, (in thousands):
Cash provided by (used in):20212020Variance
Operating activities$(144,760)$419,459 $(564,219)
Investing activities$(484,106)$(529,724)$45,618 
Financing activities$633,061 $107,819 $525,242 

Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 2020

Operating Activities:

Net cash provided by operating activities was $564 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 $14 million lower for the nine months ended September 30, 2021 compared to the same period in the prior year primarily driven by higher operating expenses and higher interest expenses;

Net inflows from changes in certain operating assets and liabilities were $560 million lower, primarily attributable to:

Cash outflows increased by $553 million as a result of changes in our regulatory assets and liabilities primarily driven by incremental costs from Winter Storm Uri;

Cash outflows increased by $9.0 million as a result of decreases in accounts payable and accrued liabilities primarily driven by payment timing related to payroll taxes;

Cash inflows decreased by $2.3 million as a result of changes in accounts receivable and other current assets primarily driven by increased collections of accounts receivable mostly offset by increased purchases of natural gas in storage;

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

Cash outflows increased by $2.9 million for other operating activities.

Investing Activities:

Net cash used in investing activities was $46 million lower than the same period in 2020. The variance to the prior year was primarily attributable to:

Capital expenditures of $498 million for the nine months ended September 30, 2021 compared to $536 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 segments and the prior year Corriedale wind project at our Electric Utilities segment; and

Cash inflows increased by $7.5 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 $525 million higher than the same period in 2020. The variance to the prior year was primarily attributable to:

Cash inflows increased $562 million due to short-term and long-term borrowings in excess of repayments;

Cash inflows decreased $36 million due to lower issuances of common stock;

Cash outflows increased $7.0 million due to increased dividends paid on common stock;

Cash outflows decreased $2.4 million due to decreased distributions to non-controlling interests; and

Cash outflows decreased by $3.7 million for other financing activities.
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Capital Sources

Short-term Debt

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.

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 FacilityExpirationCapacitySeptember 30, 2021September 30, 2021September 30, 2021
Revolving Credit Facility and CP ProgramJuly 19, 2026$750 $333 $23 $394 
__________
(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 September 30, 2021 was 0.19%. Short-term borrowing activity related to our Revolving Credit Facility and CP Program for the nine months ended September 30, 2021 was:
(dollars in millions)
Maximum amount outstanding (based on daily outstanding balances)$333 
Average amount outstanding (based on daily outstanding balances)$224 
Weighted average interest rates0.21 %

Term Loan

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

Long-term Debt

See Note 5 of the Notes to Condensed Consolidated Financial Statements for information related to our long-term debt.

Covenant Requirements

The Revolving Credit Facility and Wyoming Electric’s financing agreements contain covenant requirements. We were in compliance with these covenants as of September 30, 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 strategic objectives. In the fourth quarter of 2021, we plan to fund our capital plan and strategic objectives by using cash generated from operating activities, our Revolving Credit Facility and CP Program and issuing an additional $40 million to $60 million of common stock under the ATM.


Credit Ratings

After assessing the current operating performance, liquidity and credit ratings of the Company, management believes that the Company will have access to the capital markets at prevailing market rates for companies with comparable credit ratings.
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The following table represents the credit ratings and outlook and risk profile of BHC at September 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 September 17, 2021, Fitch reported BBB+ rating and maintained a Stable outlook.

The following table represents the credit ratings of South Dakota Electric at September 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 September 17, 2021, Fitch reported A rating.


Capital Requirements

Capital Expenditures
Actual
Forecasted (c)
Capital Expenditures by Segment
Nine Months Ended September 30, 2021 (a)
2021 (b)
2022202320242025
(in millions)
Electric Utilities$172 $251 $227 $192 $271 $216 
Gas Utilities294 393 363 383 386 349 
Power Generation11 14 
Mining10 
Corporate and Other11 13 13 13 
Incremental Projects (d)
— — — — — 60 
$486 $678 $611 $600 $684 $653 
__________
(a)    Includes accruals for property, plant and equipment as disclosed in supplemental cash flow information in the Condensed Consolidated Statements of Cash Flows in the Condensed Consolidated Financial Statements.
(b)    Includes actual capital expenditures for the nine months ended September 30, 2021.
(c)    The increase in forecasted capital expenditures is primarily driven by the Ready Wyoming transmission project at our Electric Utilities. Additionally, we have identified various other projects at our Electric and Gas Utilities that were previously disclosed as Incremental.
(d)    These represent projects that are being evaluated by our segments for timing, cost and other factors.

Dividends

Dividends paid on our common stock totaled $107 million for the nine months ended September 30, 2021, or $0.565 per share per quarter. On October 26, 2021, our board of directors declared a quarterly dividend of $0.595 per share payable December 1, 2021, equivalent to an annual dividend of $2.38 per share. The amount of any future cash dividends to be declared and paid, if any, will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our Revolving Credit Facility and our future business prospects.

Unconditional Purchase Obligations

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


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


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PART II.    OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS

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

ITEM 1A.RISK FACTORS

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

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

The following table contains monthly information about our acquisitions of equity securities for the three months ended September 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
July 1, 2021 - July 31, 20212$66.21 — — 
August 1, 2021 - August 31, 2021260$70.24 — — 
September 1, 2021 - September 30, 20211$71.52 — — 
Total263 $70.21 — — 
_____________
(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.

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ITEM 6.        EXHIBITS

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

Exhibit NumberDescription
4.1
10.1
31.1*
31.2*
32.1*
32.2*
95*
101.INS*XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*XBRL Taxonomy Extension Schema Document
101.CAL*XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*XBRL Taxonomy Extension Label Linkbase Document
101.PRE*XBRL Taxonomy Extension Presentation Linkbase Document
104*Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)

54


SIGNATURES


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

BLACK HILLS CORPORATION
/s/ Linden R. Evans
Linden R. Evans, President and
  Chief Executive Officer
/s/ Richard W. Kinzley
Richard W. Kinzley, Senior Vice President and
  Chief Financial Officer
Dated:November 3, 2021

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