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BKH Black Hills

Filed: 3 Nov 20, 12:21pm
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, 2020
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, 2020
Common stock, $1.00 par value62,746,692 shares


















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GLOSSARY OF TERMS AND ABBREVIATIONS

The following terms and abbreviations appear in the text of this report and have the definitions described below:
AFUDCAllowance for Funds Used During Construction
AOCIAccumulated Other Comprehensive Income (Loss)
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
CARES ActCoronavirus Aid, Relief, and Economic Security Act, signed on March 27, 2020, which is a tax and spending package intended to provide additional economic relief and address the impact of the COVID-19 pandemic.
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.
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 Colorado SpringsColorado Springs, Colorado
City of GilletteGillette, Wyoming
Colorado ElectricBlack Hills Colorado Electric, LLC, a direct, wholly-owned subsidiary of Black Hills
Utility Holdings, providing electric service to customers in Colorado (doing business as Black Hills Energy).
Colorado GasBlack Hills Colorado Gas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Colorado (doing business as Black Hills Energy).
Consolidated Indebtedness to Capitalization RatioAny indebtedness outstanding at such time, divided by capital at such time. Capital being consolidated net worth (excluding noncontrolling interest) plus consolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit Facility.
Cooling Degree Day (CDD)A cooling degree day is equivalent to each degree that the average of the high and low temperatures for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
CorriedaleWind project near Cheyenne, Wyoming, that will be a 52.5 MW wind farm jointly owned by South Dakota Electric and Wyoming Electric and will serve as the dedicated wind energy supply to the Renewable Ready program.
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COVID-19The official name for the 2019 novel coronavirus disease announced on February 11, 2020, by the World Health Organization, that is causing a global pandemic
CP ProgramCommercial Paper Program
CPUCColorado Public Utilities Commission
CVACredit Valuation Adjustment
Dodd-FrankDodd-Frank Wall Street Reform and Consumer Protection Act
DRSPPDividend Reinvestment and Stock Purchase Plan
DthDekatherm. A unit of energy equal to 10 therms or approximately one million British thermal units (MMBtu)
FASBFinancial Accounting Standards Board
FERCUnited States Federal Energy Regulatory Commission
FitchFitch Ratings Inc.
GAAPAccounting principles generally accepted in the United States of America
Heating Degree Day (HDD)A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
HomeServeRepair service plans offered to electric and natural gas residential customers that cover parts and labor to repair electrical, gas, heating, cooling, and water systems.
ICFRInternal Controls over Financial Reporting
Iowa GasBlack Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Iowa (doing business as Black Hills Energy).
IPPIndependent Power Producer
IRSUnited States Internal Revenue Service
Kansas GasBlack Hills Kansas Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Kansas (doing business as Black Hills Energy).
MMBtuMillion British thermal units
Moody’sMoody’s Investors Service, Inc.
MWMegawatt
MWhMegawatt-hour
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).
NPSCNebraska Public Service Commission
OCAOffice of Consumer Advocate
OCCOffice of Consumer Counsel
OCIOther Comprehensive Income
PPAPower Purchase Agreement
PRPAPlatte River Power Authority
PSAPower Sales Agreement
Pueblo Airport Generation420 MW combined cycle gas-fired power generation plants jointly owned by Colorado Electric (220 MW) and Black Hills Colorado IPP (200 MW). Black Hills Colorado IPP owns and operates this facility. The plants commenced operation on January 1, 2012.
Renewable AdvantageA 200 MW solar facility project to be constructed in Pueblo County, Colorado. The project aims to lower customer energy costs and provide economic and environmental benefits to Colorado Electric’s customers and communities. This project, which was approved by the CPUC in September 2020, will be owned by a third-party renewable energy developer with Colorado Electric purchasing all of the energy generated at the facility under the terms of a 15-year PPA. The project is expected to be placed in service in 2023.
Renewable ReadyVoluntary renewable energy subscription program for large commercial, industrial and governmental agency customers in South Dakota and Wyoming.
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Revolving Credit FacilityOur $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which was amended and restated on July 30, 2018, and now terminates on July 30, 2023.
SDPUCSouth Dakota Public Utilities Commission
SECUnited States Securities and Exchange Commission
Service Guard Comfort PlanNew plan that consolidated Service Guard and Customer Appliance Protection Plan (CAPP) and provides similar home appliance repair services through on-going monthly service agreements to residential utility customers.
S&PStandard and Poor’s, a division of The McGraw-Hill Companies, Inc.
South Dakota ElectricBlack Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and Wyoming (doing business as Black Hills Energy).
SSIRSystem Safety and Integrity Rider
TCJATax Cuts and Jobs Act
Tech ServicesNon-regulated product lines within Black Hills Corporation 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-owner 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
WPSCWyoming Public Service Commission
WRDCWyodak Resources Development Corporation, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings (doing business as Black Hills Energy)
Wygen IA mine-mouth, coal-fired power plant with a total capacity of 90 MW located at our Gillette, Wyoming energy complex. We own 76.5% of the plant and Municipal Energy Agency of Nebraska (MEAN) owns the remaining 23.5%.
Wyodak PlantWyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, owned 80% by PacifiCorp and 20% by South Dakota Electric. Our WRDC mine supplies all of the fuel for the plant.
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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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,
2020201920202019
(in thousands, except per share amounts)
Revenue$346,590 $325,548 $1,210,554 $1,257,246 
Operating expenses:
Fuel, purchased power and cost of natural gas sold71,686 73,544 331,194 413,486 
Operations and maintenance122,759 116,583 365,533 365,116 
Depreciation, depletion and amortization56,348 51,884 169,413 154,507 
Taxes - property and production13,563 12,986 42,062 39,454 
Total operating expenses264,356 254,997 908,202 972,563 
Operating income82,234 70,551 302,352 284,683 
Other income (expense):
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)(36,521)(34,000)(108,067)(103,677)
Interest income480 513 1,028 1,208 
Impairment of investment(19,741)(6,859)(19,741)
Other income (expense), net(1,193)580 (703)55 
Total other income (expense)(37,234)(52,648)(114,601)(122,155)
Income before income taxes45,000 17,903 187,751 162,528 
Income tax (expense)(4,651)(2,508)(25,484)(22,078)
Net income40,349 15,395 162,267 140,450 
Net income attributable to noncontrolling interest(4,066)(3,655)(11,844)(10,319)
Net income available for common stock$36,283 $11,740 $150,423 $130,131 
Earnings per share of common stock:
Earnings per share, Basic$0.58 $0.19 $2.41 $2.15 
Earnings per share, Diluted$0.58 $0.19 $2.41 $2.15 
Weighted average common shares outstanding:
Basic62,575 60,976 62,310 60,458 
Diluted62,630 61,104 62,362 60,578 

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,
2020201920202019
(in thousands)
Net income$40,349 $15,395 $162,267 $140,450 
Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (net of tax of $0,$0, $(17) and $0, respectively)55 
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $6, $3, $19 and $13, respectively)(18)(16)(60)(45)
Reclassification adjustments of benefit plan liability - net gain (net of tax of $(149), $(92), $(426) and $(197), respectively)448 (9)1,365 327 
Derivative instruments designated as cash flow hedges:
Reclassification of net realized losses on settled/amortized interest rate swaps (net of tax of $(168), $(165), $(508) and $(500), respectively)544 548 1,630 1,639 
Net unrealized gains (losses) on commodity derivatives (net of tax of $(112), $35, $(44) and $100, respectively)401 (115)181 (334)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $(41), $(5), $(172), and $142, respectively)137 124 562 (366)
Other comprehensive income, net of tax1,512 532 3,733 1,221 
Comprehensive income41,861 15,927 166,000 141,671 
Less: comprehensive income attributable to noncontrolling interest(4,066)(3,655)(11,844)(10,319)
Comprehensive income available for common stock$37,795 $12,272 $154,156 $131,352 

See Note 11 for additional disclosures.

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.
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BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)As of
September 30, 2020December 31, 2019
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents$6,955 $9,777 
Restricted cash and equivalents4,257 3,881 
Accounts receivable, net160,478 255,805 
Materials, supplies and fuel126,358 117,172 
Derivative assets, current2,001 342 
Income tax receivable, net20,828 16,446 
Regulatory assets, current49,493 43,282 
Other current assets33,287 26,479 
Total current assets403,657 473,184 
Investments15,659 21,929 
Property, plant and equipment7,128,387 6,784,679 
Less: accumulated depreciation and depletion(1,276,410)(1,281,493)
Total property, plant and equipment, net5,851,977 5,503,186 
Other assets:
Goodwill1,299,454 1,299,454 
Intangible assets, net12,242 13,266 
Regulatory assets, non-current221,743 228,062 
Other assets, non-current24,318 19,376 
Total other assets, non-current1,557,757 1,560,158 
TOTAL ASSETS$7,829,050 $7,558,457 

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, 2020December 31, 2019
(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable$152,010 $193,523 
Accrued liabilities244,010 226,767 
Derivative liabilities, current1,439 2,254 
Regulatory liabilities, current22,282 33,507 
Notes payable84,320 349,500 
Current maturities of long-term debt9,871 5,743 
Total current liabilities513,932 811,294 
Long-term debt, net of current maturities3,526,894 3,140,096 
Deferred credits and other liabilities:
Deferred income tax liabilities, net398,136 360,719 
Regulatory liabilities, non-current505,317 503,145 
Benefit plan liabilities144,049 154,472 
Other deferred credits and other liabilities120,522 124,662 
Total deferred credits and other liabilities1,168,024 1,142,998 
Commitments and contingencies (See Notes 7, 9, 12, 13)
Equity:
Stockholders’ equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 62,773,015 and 61,480,658 shares, respectively62,773 61,481 
Additional paid-in capital1,655,912 1,552,788 
Retained earnings828,993 778,776 
Treasury stock, at cost – 24,897 and 3,956 shares, respectively(1,710)(267)
Accumulated other comprehensive income (loss)(26,922)(30,655)
Total stockholders’ equity2,519,046 2,362,123 
Noncontrolling interest101,154 101,946 
Total equity2,620,200 2,464,069 
TOTAL LIABILITIES AND TOTAL EQUITY$7,829,050 $7,558,457 

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,
20202019
Operating activities:(in thousands)
Net income$162,267 $140,450 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization169,413 154,507 
Deferred financing cost amortization5,523 6,326 
Impairment of investment6,859 19,741 
Stock compensation2,696 8,332 
Deferred income taxes28,502 24,381 
Employee benefit plans9,294 7,965 
Other adjustments, net7,910 9,192 
Changes in certain operating assets and liabilities:
Materials, supplies and fuel(10,905)(4,126)
Accounts receivable and other current assets75,960 115,325 
Accounts payable and other current liabilities(11,136)(83,436)
Regulatory assets - current1,954 12,455 
Regulatory liabilities - current(17,686)(15,644)
Contributions to defined benefit pension plans(12,700)(12,700)
Other operating activities, net1,508 3,307 
Net cash provided by operating activities419,459 386,075 
Investing activities:
Property, plant and equipment additions(535,993)(592,537)
Other investing activities6,269 (735)
Net cash (used in) investing activities(529,724)(593,272)
Financing activities:
Dividends paid on common stock(99,999)(91,779)
Common stock issued99,316 101,361 
Net (payments) borrowings of short-term debt(265,180)109,280 
Long-term debt - issuances400,000 400,000 
Long-term debt - repayments(7,163)(304,307)
Distributions to noncontrolling interest(12,636)(12,736)
Other financing activities(6,519)(1,992)
Net cash provided by financing activities107,819 199,827 
Net change in cash, restricted cash and cash equivalents(2,446)(7,370)
Cash, restricted cash and cash equivalents at beginning of period13,658 24,145 
Cash, restricted cash and cash equivalents at end of period$11,212 $16,775 
Supplemental cash flow information:
Cash (paid) refunded during the period:
Interest (net of amounts capitalized)$(87,453)$(99,375)
Income taxes$1,256 $2,255 
Non-cash investing and financing activities:
Accrued property, plant and equipment purchases at September 30$86,474 $86,661 

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, 201961,480,658 $61,481 3,956 $(267)$1,552,788 $778,776 $(30,655)$101,946 $2,464,069 
Net income available for common stock— — — — — 93,174 — 4,050 97,224 
Other comprehensive income (loss), net of tax— — — — — — 1,273 — 1,273 
Dividends on common stock ($0.535 per share)— — — — — (32,902)— — (32,902)
Share-based compensation69,378 69 20,700 (1,658)2,263 — — — 674 
Issuance of common stock1,222,942 1,223 — — 98,777 — — — 100,000 
Issuance costs— — — — (967)— — — (967)
Implementation of ASU 2016-13 Financial Instruments - - Credit Losses— — — — — (207)— — (207)
Distributions to noncontrolling interest— — — — — — — (4,741)(4,741)
March 31, 202062,772,978 $62,773 24,656 $(1,925)$1,652,861 $838,841 $(29,382)$101,255 $2,624,423 
Net income available for common stock20,966 — 3,728 24,694 
Other comprehensive income (loss), net of tax— — — — — — 948 — 948 
Dividends on common stock ($0.535 per share)— — — — — (33,538)— — (33,538)
Share-based compensation18 — 1,743 46 1,781 — — — 1,827 
Issuance costs— — — — (79)— — — (79)
Distributions to noncontrolling interest— — — — — — — (3,779)(3,779)
June 30, 202062,772,996 $62,773 26,399 $(1,879)$1,654,563 $826,269 $(28,434)$101,204 $2,614,496 
Net income available for common stock— — — — — 36,283 — 4,066 40,349 
Other comprehensive income, 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 noncontrolling 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 
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Common StockTreasury Stock
(in thousands except share amounts)SharesValueSharesValueAdditional Paid in CapitalRetained EarningsAOCINon controlling InterestTotal
December 31, 201860,048,567 $60,049 44,253 $(2,510)$1,450,569 $700,396 $(26,916)$105,835 $2,287,423 
Net income available for common stock— — — — — 103,808 — 3,554 107,362 
Other comprehensive income (loss), net of tax— — — — — — 457 — 457 
Dividends on common stock ($0.505 per share)— — — — — (30,332)— — (30,332)
Share-based compensation48,956 49 (20,497)1,078 (589)— — — 538 
Tax effect of share-based compensation— — — — — — — — — 
Issuance of common stock280,497 280 — — 19,719 — — — 19,999 
Issuance costs— — — — (289)— — — (289)
Implementation of ASU 2016-02 Leases— — — — — 3,390 — — 3,390 
Distributions to noncontrolling interest— — — — — — — (4,846)(4,846)
March 31, 201960,378,020 $60,378 23,756 $(1,432)$1,469,410 $777,262 $(26,459)$104,543 $2,383,702 
Net income available for common stock— — — — — 14,583 — 3,110 17,693 
Other comprehensive income, net of tax— — — — — — 232 — 232 
Dividends on common stock ($0.505 per share)— — — — — (30,620)— — (30,620)
Share-based compensation54,767 54 1,603 (112)3,948 — — — 3,890 
Tax effect of share-based compensation— — — — — — — — — 
Issuance of common stock658,598 659 — — 49,342 — — — 50,001 
Issuance costs— — — — (492)— — — (492)
Implementation of ASU 2016-02 Leases— — — — — (3)— — (3)
Distributions to noncontrolling interest— — — — — — — (4,405)(4,405)
June 30, 201961,091,385 $61,091 25,359 $(1,544)$1,522,208 $761,222 $(26,227)$103,248 $2,419,998 
Net income available for common stock— — — — — 11,740 — 3,655 15,395 
Other comprehensive income, net of tax— — — — — — 532 — 532 
Dividends on common stock ($0.505 per share)— — — — — (30,827)— — (30,827)
Share-based compensation18 1,213 (92)1,769 — — — 1,677 
Tax effect of share-based compensation— — — — — — — — — 
Issuance of common stock389,237 390 — — 29,611 — — — 30,001 
Issuance costs— — — — (398)— — — (398)
Implementation of ASU 2016-02 Leases— — — — — — — 
Distributions to noncontrolling interest— — — — — — — (3,485)(3,485)
September 30, 201961,480,640 $61,481 26,572 $(1,636)$1,553,190 $742,138 $(25,695)$103,418 $2,432,896 

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BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 2019 Annual Report on Form 10-K)

(1)    Management’s Statement

The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company”, “us”, “we” or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Condensed Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes included in our 2019 Annual Report on Form 10-K filed with the SEC.

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, 2020, December 31, 2019 and September 30, 2019 financial information. Certain industries 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 electric utilities is June through August while the normal peak usage season for 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, 2020 and September 30, 2019, and our financial condition as of September 30, 2020 and December 31, 2019 are not necessarily indicative of the results of operations and financial condition to be expected for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

Reclassification

We changed certain classifications of operating expenses on the Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2019 to conform with current year presentation. The prior year reclassifications, which are shown in the table below, did not impact previously reported operating income or net income.

Three Months Ended September 30, 2019Nine Months Ended September 30, 2019
(in millions)
Fuel, purchased power and cost of natural gas sold$0.5 $1.8 
Operations and maintenance(0.5)(1.8)
Operating income$$

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 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 employees and the communities in which we operate while assuring the continuity of our business operations.
14



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, 2020, there were no material adverse impacts on the Company’s results of operations.

Change in Accounting Principle - Pension Accounting Asset Method

Effective January 1, 2020, we changed our method of accounting for net periodic benefit cost. Prior to the change, the Company used a calculated value for determining market-related value of plan assets which amortized the effects of gains and losses over a five-year period. Effective with the accounting change, the Company will use a calculated value for the return-seeking assets (equities) in the portfolio and change to fair value for the liability-hedging assets (fixed income). See Note 12 for additional information.

Recently Issued 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. The new guidance is effective for interim and annual periods beginning after December 15, 2020 with early adoption permitted. We are currently reviewing this standard to assess the impact on our financial position, results of operations and cash flows.

Recently Adopted Accounting Standards

Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, ASU 2016-13

In June 2016, the FASB issued ASU 2016-13, Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, which was subsequently amended by ASUs 2018-19, 2019-04, 2019-05, 2019-10, and 2019-11. The standard introduces new accounting guidance for credit losses on financial instruments within its scope, including trade receivables. This new guidance adds an impairment model that is based on expected losses rather than incurred losses.

We adopted this standard on January 1, 2020 with prior year comparative financial information remaining as previously reported when transitioning to the new standard. On January 1, 2020, we recorded an increase to our allowance for credit losses, primarily associated with the inclusion of expected losses on unbilled revenue. The cumulative effect of the adoption, net of tax impact, was $0.2 million, which was recorded as an adjustment to retained earnings.

Simplifying the Test for Goodwill Impairment, ASU 2017-04

In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment, by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit. We adopted this standard prospectively on January 1, 2020. Adoption of this guidance did not have an impact on our financial position, results of operations or cash flows.

15


Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, ASU 2018-15

In August 2018, the FASB issued ASU 2018-15, Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, which aligns the requirements for recording implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. As a result, certain categories of implementation costs that previously would have been charged to expense as incurred are now capitalized as prepayments and amortized over the term of the arrangement. We adopted this standard prospectively on January 1, 2020. Adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.


(2)    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, 2020 and 2019. Sales tax and other similar taxes are excluded from revenues.
Three Months Ended September 30, 2020 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer types:(in thousands)
Retail$169,505 $94,367 $$14,668 $(8,100)$270,440 
Transportation38,196 (139)38,057 
Wholesale5,925 26,049 (24,521)7,453 
Market - off-system sales9,535 36 (1,904)7,667 
Transmission/Other15,653 10,277 (5,235)20,695 
Revenue from contracts with customers$200,618 $142,876 $26,049 $14,668 $(39,899)$344,312 
Other revenues224 1,053 469 568 (36)2,278 
Total revenues$200,842 $143,929 $26,518 $15,236 $(39,935)$346,590 
Timing of revenue recognition:
Services transferred at a point in time$$$$14,668 $(8,100)$6,568 
Services transferred over time200,618 142,876 26,049 (31,799)337,744 
Revenue from contracts with customers$200,618 $142,876 $26,049 $14,668 $(39,899)$344,312 
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Three Months Ended September 30, 2019 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer Types:
Retail$162,214 $89,810 $$14,992 $(8,146)$258,870 
Transportation29,019 (195)28,824 
Wholesale8,210 16,119 (14,414)9,915 
Market - off-system sales6,452 139 (1,488)5,103 
Transmission/Other14,274 10,965 (4,206)21,033 
Revenue from contracts with customers$191,150 $129,933 $16,119 $14,992 $(28,449)$323,745 
Other revenues234 811 9,692 560 (9,494)1,803 
Total Revenues$191,384 $130,744 $25,811 $15,552 $(37,943)$325,548 
Timing of Revenue Recognition:
Services transferred at a point in time$$$$14,992 $(8,146)$6,846 
Services transferred over time191,150 129,933 16,119 (20,303)316,899 
Revenue from contracts with customers$191,150 $129,933 $16,119 $14,992 $(28,449)$323,745 
Nine Months Ended September 30, 2020 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer types:(in thousands)
Retail$459,949 $513,208 $$43,917 $(23,855)$993,219 
Transportation113,096 (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$$$$43,917 $(23,855)$20,062 
Services transferred over time536,107 658,539 77,234 (93,228)1,178,652 
Revenue from contracts with customers$536,107 $658,539 $77,234 $43,917 $(117,083)$1,198,714 
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Nine Months Ended September 30, 2019 Electric Utilities Gas UtilitiesPower Generation MiningInter-company RevenuesTotal
Customer Types:
Retail$455,409 $567,715 $$43,249 $(23,315)$1,043,058 
Transportation102,159 (903)101,256 
Wholesale23,334 46,650 (40,923)29,061 
Market - off-system sales16,592 517 (5,047)12,062 
Transmission/Other42,865 35,767 (12,608)66,024 
Revenue from contracts with customers$538,200 $706,158 $46,650 $43,249 $(82,796)$1,251,461 
Other revenues2,465 1,135 29,114 1,777 (28,706)5,785 
Total Revenues$540,665 $707,293 $75,764 $45,026 $(111,502)$1,257,246 
Timing of Revenue Recognition:
Services transferred at a point in time$$$$43,249 $(23,315)$19,934 
Services transferred over time538,200 706,158 46,650 (59,481)1,231,527 
Revenue from contracts with customers$538,200 $706,158 $46,650 $43,249 $(82,796)$1,251,461 

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 4.


(3)    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.

Segment and Corporate and Other information is as follows (in thousands):
Three Months Ended September 30, 2020External Operating
Revenue
Inter-company Operating RevenueTotal 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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Three Months Ended September 30, 2019External Operating RevenueInter-company Operating Revenue Total Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities$185,811 $234 $5,339 $$191,384 
Gas Utilities129,385 810 549 130,744 
Power Generation1,703 531 14,415 9,162 25,811 
Mining6,846 228 8,146 332 15,552 
Inter-company eliminations— — (28,449)(9,494)(37,943)
Total$323,745 $1,803 $$$325,548 
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 

Nine Months Ended September 30, 2019External Operating RevenueInter-company Operating Revenue Total Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities$521,614 $2,465 $16,586 $$540,665 
Gas Utilities704,188 1,134 1,971 707,293 
Power Generation5,725 1,401 40,924 27,714 75,764 
Mining19,934 785 23,315 992 45,026 
Inter-company eliminations— — (82,796)(28,706)(111,502)
Total$1,251,461 $5,785 $$$1,257,246 


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Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
Adjusted operating income (a):
Electric Utilities$52,083 $50,653 $121,726 $125,219 
Gas Utilities18,147 4,736 139,253 116,607 
Power Generation8,738 11,822 31,489 33,945 
Mining3,505 3,374 9,992 9,351 
Corporate and Other(239)(34)(108)(439)
Operating income82,234 70,551 302,352 284,683 
Interest expense, net(36,041)(33,487)(107,039)(102,469)
Impairment of investment(19,741)(6,859)(19,741)
Other income (expense), net(1,193)580 (703)55 
Income tax (expense)(4,651)(2,508)(25,484)(22,078)
Net income40,349 15,395 162,267 140,450 
Net income attributable to noncontrolling interest(4,066)(3,655)(11,844)(10,319)
Net income available for common stock$36,283 $11,740 $150,423 $130,131 
__________
(a)    Adjusted operating income recognizes inter-segment 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.

Segment and Corporate and Other balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):
Total assets (net of inter-company eliminations) as of:September 30, 2020December 31, 2019
Segment:
Electric Utilities$3,040,064 $2,900,983 
Gas Utilities4,201,325 4,032,339 
Power Generation403,491 417,715 
Mining75,752 77,175 
Corporate and Other108,418 130,245 
Total assets$7,829,050 $7,558,457 


(4)    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, 2020December 31, 2019
Accounts receivable, trade$108,351 $144,747 
Unbilled revenue60,736 113,502 
Less: Allowance for credit losses(8,609)(2,444)
Accounts receivable, net$160,478 $255,805 

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Changes to allowance for credit losses for the nine months ended September 30, 2020 and 2019, 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,
2020$2,444 $8,471 (a)$3,720 $(6,026)$8,609 
2019$3,209 $5,637 $2,742 $(8,429)$3,159 

__________
(a)    Due to the COVID-19 pandemic, all of our jurisdictions temporarily suspended disconnections for a period of time, which increased our accounts receivable arrears balances. As a result, we increased our allowance for credit losses and bad debt expense for the nine months ended September 30, 2020 by an incremental $3.7 million.

The ongoing credit evaluation of our customers during the COVID-19 pandemic is further discussed in the Credit Risk section of Note 9.

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, 2020December 31, 2019
Materials and supplies$93,069 $82,809 
Fuel - Electric Utilities1,745 2,425 
Natural gas in storage31,544 31,938 
Total materials, supplies and fuel$126,358 $117,172 

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, 2020December 31, 2019
Accrued employee compensation, benefits and withholdings$65,309 $62,837 
Accrued property taxes40,624 44,547 
Customer deposits and prepayments59,510 54,728 
Accrued interest46,044 31,868 
Other (none of which is individually significant)32,523 32,787 
Total accrued liabilities$244,010 $226,767 


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(5)    Regulatory Matters

We had the following regulatory assets and liabilities (in thousands) as of:
September 30, 2020December 31, 2019
Regulatory assets
Deferred energy and fuel cost adjustments (a)
$35,878 $34,088 
Deferred gas cost adjustments (a)
3,670 1,540 
Gas price derivatives (a)
499 3,328 
Deferred taxes on AFUDC (b)
7,683 7,790 
Employee benefit plan costs and related deferred taxes (c)
114,971 115,900 
Environmental (a)
1,417 1,454 
Loss on reacquired debt (a)
23,342 24,777 
Renewable energy standard adjustment (a)
1,622 
Deferred taxes on flow through accounting (c)
44,528 41,220 
Decommissioning costs (b)
9,421 10,670 
Gas supply contract termination (a)
4,027 8,485 
Other regulatory assets (a)
25,800 20,470 
Total regulatory assets271,236 271,344 
Less current regulatory assets(49,493)(43,282)
Regulatory assets, non-current$221,743 $228,062 
Regulatory liabilities
Deferred energy and gas costs (a)
$14,443 $17,278 
Employee benefit plan costs and related deferred taxes (c)
40,719 43,349 
Cost of removal (a)
169,426 166,727 
Excess deferred income taxes (c)
286,055 285,438 
Other regulatory liabilities (c)
16,956 23,860 
Total regulatory liabilities527,599 536,652 
Less current regulatory liabilities(22,282)(33,507)
Regulatory liabilities, non-current$505,317 $503,145 
__________
(a)    Recovery of costs, but we are not allowed a rate of return.
(b)    In addition to recovery of costs, we are allowed a rate of return.
(c)    In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base.

22


Regulatory Activity

Except as discussed below, there have been no other significant changes to our Regulatory Matters from those previously disclosed in Note 13 of the Notes to the Consolidated Financial Statements in our 2019 Annual Report on Form 10-K.

Colorado Gas

Rate Reviews and Jurisdictional Consolidation

On September 11, 2020, Colorado Gas filed a rate review with the CPUC seeking recovery on significant infrastructure investments in its 7,000-mile natural gas pipeline system. The rate review requests $13.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 9.95%. The request seeks to implement new rates in the second quarter of 2021. On September 11, 2020, in accordance with the final order from the earlier rate review discussed below, Colorado Gas also filed a new SSIR proposal that would recover safety-focused investments in its system over five years.

On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting $2.5 million in new revenue to recover investments in safety, reliability and system integrity and approval to consolidate rates, tariffs, and services of its 2 existing gas distribution territories. Colorado Gas also requested a new rider mechanism to recover future safety and integrity investments in its system. On May 19, 2020, the CPUC issued a final order which denied the system integrity recovery mechanism and consolidation of rate territories. In addition, the order resulted in an annual revenue decrease of $0.6 million and a return on equity of 9.2%. New rates were effective July 3, 2020.

TCJA

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. As such, the Company remeasured our deferred income taxes at the 21% federal tax rate as of December 31, 2017. In 2018, the Company successfully delivered the benefits from the TCJA to most of its utility customers.

In 2020, regulatory proceedings resolved the last of the Company’s open dockets seeking approval of its TCJA plans. As a result, the Company relieved certain TCJA-related liabilities, which resulted in an increase to net income for the three and nine months ended September 30, 2020 of $3.5 million and $4.0 million, respectively.

Nebraska Gas

Jurisdictional Consolidation and Rate Review

On June 1, 2020, Nebraska Gas filed a rate review with the NPSC to consolidate rate schedules into a new, single statewide structure and seek recovery on significant infrastructure investments in its 13,000-mile natural gas pipeline system. The rate review requests $17.3 million in new revenue with a capital structure of 50% equity and 50% debt and a return on equity of 10%. Nebraska statute allows for implementation of interim rates 90 days after filing a rate review and Nebraska Gas implemented interim rates effective on September 1, 2020. The request seeks to finalize rates in the first quarter of 2021. Nebraska Gas is also requesting an extension of its SSIR for five years to align the rider recovery mechanism across the consolidated utility.

Black Hills Wyoming and Wyoming Electric

Wygen I FERC Filing

On October 15, 2020, the FERC approved a settlement agreement that represents a resolution of all issues in the joint application filed by Wyoming Electric and Black Hills Wyoming on August 2, 2019 for approval of a new 60 MW PPA. Under the terms of the settlement, Wyoming Electric will continue to receive 60 MW of capacity and energy from the Wygen I power plant. The new agreement will commence on January 1, 2022, replace the existing PPA and continue for 11 years.



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(6)    Earnings Per Share

A reconciliation of share amounts used to compute earnings per share in the accompanying Condensed Consolidated Statements of Income was as follows (in thousands):
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
Net income available for common stock$36,283 $11,740 $150,423 $130,131 
Weighted average shares - basic62,575 60,976 62,310 60,458 
Dilutive effect of:
Equity compensation55 128 52 120 
Weighted average shares - diluted62,630 61,104 62,362 60,578 
Earnings per share of common stock:
Earnings per share, Basic$0.58 $0.19 $2.41 $2.15 
Earnings per share, Diluted$0.58 $0.19 $2.41 $2.15 


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,
2020201920202019
Equity compensation22 22 
Restricted stock49 40 
Anti-dilutive shares71 62 



(7)    Notes Payable, Current Maturities and Debt

We had the following short-term debt outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
September 30, 2020December 31, 2019
Balance Outstanding
Letters of Credit (a)
Balance Outstanding
Letters of Credit (a)
Revolving Credit Facility$$24,588 $$30,274 
CP Program84,320 349,500 
Total$84,320 $24,588 $349,500 $30,274 
_______________
(a)    Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit
Facility.

For the nine months ended September 30, 2020, we utilized a combination of our $750 million Revolving Credit Facility and CP Program to meet our business needs and support our capital investment plan. Our net short-term borrowings (payments) during the nine months ended September 30, 2020 were $(265) million.

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Debt Covenants

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

Our Revolving Credit Facility and term loans require compliance with the following financial covenant, which we were in compliance with at September 30, 2020:
As of September 30, 2020Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio59.3%Less than65%

Debt Offering

On June 17, 2020, we completed a public debt offering which consisted of $400 million of 2.50% 10-year senior unsecured notes due June 15, 2030. The proceeds were used to repay short-term debt and for working capital and general corporate purposes.

South Dakota Electric Series 94A Debt

On March 24, 2020, South Dakota Electric paid off its $2.9 million, Series 94A variable rate notes due June 1, 2024. These notes were tendered by the sole investor on March 17, 2020.


(8)    Equity

February 2020 Equity Issuance

On February 27, 2020, we issued 1.2 million shares of common stock to a single investor through an underwritten registered transaction at a price of $81.77 per share for proceeds of $99 million, net of $1.0 million of issuance costs. The shares of common stock were offered pursuant to our shelf registration statement filed with the SEC.

Shelf Registration, DRSPP and ATM Activity

On August 3, 2020, we filed a shelf registration and DRSPP with the SEC. In conjunction with these shelf filings, we renewed the ATM. The renewed ATM program, which allows us to sell shares of our common stock, is the same as the prior program other than the aggregate value increased from $300 million to $400 million and a forward sales option was incorporated. Under the ATM, shares may be offered from time to time pursuant to a sales agreement dated August 3, 2020. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC.

We did not issue any common shares under the ATM during the three and nine months ended September 30, 2020. During the three months ended September 30, 2019, we issued a total of 0.4 million shares of common stock under the ATM for proceeds of $30 million, net of $0.3 million in issuance costs. During the nine months ended September 30, 2019, we issued a total of 1.3 million shares of common stock under the ATM for proceeds of $99 million, net of $1.0 million in issuance costs.


25


(9)    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, wholesale electric power marketing activities and our fuel procurement for several of our gas-fired generation assets which include market fluctuations due to unpredictable factors such as the COVID-19 pandemic, weather, market speculation, pipeline constraints, and other factors that may impact natural gas and electric energy supply and demand; and

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

Credit Risk

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

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

We perform ongoing credit evaluations of our customers and adjust credit limits based on 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.

We continue to monitor COVID-19 impacts and changes to customer load, consistency in customer payments, requests for deferred or discounted payments, and requests for changes to credit limits to quantify estimated future financial impacts to the allowance for credit losses. During the three and nine months ended September 30, 2020, the potential economic impact of the COVID-19 pandemic was considered in forward looking projections related to write-off and recovery rates, and resulted in increases to the allowance for credit losses and bad debt expense of $1.7 million and $3.7 million, respectively. See Note 4 for further information.

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 10.

Utilities

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

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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 utility commission guidelines. When the related costs are recovered through our rates, the hedging activity is 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/or sales from October 2020 through May 2022. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price forward contracts to deliver gas to our Choice Gas Program customers. The gain or loss on these designated derivatives is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and reclassified into earnings in the same period that the underlying hedged item is recognized in earnings. Effectiveness of our hedging position is evaluated at least quarterly.

The contract or notional amounts and terms of the electric and natural gas derivative commodity instruments held at our utilities are composed of both long and short positions. We had the following net long positions as of:
September 30, 2020December 31, 2019
UnitsNotional
Amounts
Maximum
Term
(months) (a)
Notional
Amounts
Maximum
Term
(months) (a)
Natural gas futures purchasedMMBtus1,930,000 61,450,000 12
Natural gas options purchased, netMMBtus8,320,000 63,240,000 3
Natural gas basis swaps purchasedMMBtus1,780,000 61,290,000 12
Natural gas over-the-counter swaps, net (b)
MMBtus4,525,100 204,600,000 24
Natural gas physical contracts, net (c)
MMBtus23,350,287 1313,548,235 12
Electric wholesale contracts (c)
MWh55,225 30
__________
(a)    Term reflects the maximum forward period hedged.
(b)    As of September 30, 2020, 1,274,900 MMBtus of natural gas over-the-counter swaps purchases were designated as cash flow hedges.
(c)     Volumes exclude contracts that qualify for the normal purchases and normal sales exception.

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, 2020, the Company posted $0.5 million related to such provisions, which is included in Other current assets on the Condensed Consolidated Balance Sheets.

Derivatives by Balance Sheet Classification

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

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The following table presents the fair value and balance sheet classification of our derivative instruments (in thousands) as of:
Balance Sheet LocationSeptember 30, 2020December 31, 2019
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivativesDerivative assets, current$435 $
Noncurrent commodity derivativesOther assets, non-current94 
Liability derivative instruments:
Current commodity derivativesDerivative liabilities, current(9)(490)
Noncurrent commodity derivativesOther deferred credits and other liabilities(29)
Total derivatives designated as hedges$520 $(515)
Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivativesDerivative assets, current$1,566 $341 
Noncurrent commodity derivativesOther assets, non-current434 
Liability derivative instruments:
Current commodity derivativesDerivative liabilities, current(1,430)(1,764)
Noncurrent commodity derivativesOther deferred credits and other liabilities(63)
Total derivatives not designated as hedges$570 $(1,484)

Derivatives Designated as Hedges

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, 2020 and 2019. 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,
2020201920202019
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 $713 Interest expense$(712)$(713)
Commodity derivatives691 (21)Fuel, purchased power and cost of natural gas sold(178)(129)
Total$1,403 $692 $(890)$(842)
Nine Months Ended September 30,Nine Months Ended September 30,
2020201920202019
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 $2,139 Interest expense$(2,138)$(2,139)
Commodity derivatives959 (942)Fuel, purchased power and cost of natural gas sold(734)508 
Total$3,097 $1,197 $(2,872)$(1,631)

Based on September 30, 2020 prices, a $0.1 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

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Derivatives Not Designated as Hedges

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, 2020 and 2019. 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,
20202019
Derivatives Not Designated as Hedging InstrumentsIncome Statement LocationAmount of Gain/(Loss) on Derivatives Recognized in Income
Commodity derivatives - ElectricFuel, purchased power and cost of natural gas sold$(1,386)$— 
Commodity derivatives - ElectricOther income (expense), net— 142 
Commodity derivatives - Natural GasFuel, purchased power and cost of natural gas sold1,777 (20)
$391 $122 

Nine Months Ended September 30,
20202019
Derivatives Not Designated as Hedging InstrumentsIncome Statement LocationAmount of Gain/(Loss) on Derivatives Recognized in Income
(in thousands)
Commodity derivatives - ElectricFuel, purchased power and cost of natural gas sold$(228)$— 
Commodity derivatives - ElectricOther income (expense), net— 142 
Commodity derivatives - Natural GasFuel, purchased power and cost of natural gas sold2,992 (1,180)
$2,764 $(1,038)

As discussed above, financial instruments used in our regulated utilities are not designated as cash flow hedges. There is no earnings impact for our Gas Utilities because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory asset or Regulatory liability accounts related to these derivatives in our Gas Utilities were $0.5 million and $3.3 million as of September 30, 2020 and December 31, 2019, respectively. For our Electric Utilities, the unrealized gains and losses arising from these derivatives are recognized in the Condensed Consolidated Statements of Income.


(10)    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; and

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.

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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 to the Consolidated Financial Statements included in our 2019 Annual Report on Form 10-K filed with the SEC.
As of September 30, 2020
Level 1Level 2Level 3Cash Collateral and Counterparty
Netting
Total
(in thousands)
Assets:
Commodity derivatives — Gas Utilities$$6,544 $$(4,015)$2,529 
Commodity derivatives — Electric Utilities
Total$$6,544 $$(4,015)$2,529 
Liabilities:
Commodity derivatives — Gas Utilities$$1,537 $$(326)$1,211 
Commodity derivatives — Electric Utilities228 $228 
Total$$1,765 $$(326)$1,439 

As of December 31, 2019
Level 1Level 2Level 3Cash Collateral and Counterparty
Netting
Total
(in thousands)
Assets:
Commodity derivatives — Gas Utilities$$1,433 $$(1,085)$348 
Total$$1,433 $$(1,085)$348 
Liabilities:
Commodity derivatives — Gas Utilities$$5,254 $$(2,909)$2,345 
Total$$5,254 $$(2,909)$2,345 

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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 18 to the Consolidated Financial Statements included in our 2019 Annual Report on Form 10-K. The Company has concluded that the market volatility associated with COVID-19 does not require interim re-measurement of our pension plan assets or defined benefit obligations. See Note 12 for additional information.

Nonrecurring Fair Value Measurement

A discussion of the fair value of our investment in equity securities of a privately held oil and gas company, a Level 3 asset, is included in Note 15.

Other Fair Value Measures

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, 2020December 31, 2019
Carrying
Amount
Fair ValueCarrying
Amount
Fair Value
Long-term debt, including current maturities (a)
$3,536,765 $4,177,801 $3,145,839 $3,479,367 
__________
(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.


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(11)    Other Comprehensive Income (Loss)

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,
2020201920202019
Gains and (losses) on cash flow hedges:
Interest rate swapsInterest expense$(712)$(713)$(2,138)$(2,139)
Commodity contractsFuel, purchased power and cost of natural gas sold(178)(129)(734)508 
(890)(842)(2,872)(1,631)
Income taxIncome tax benefit (expense)209 170 680 358 
Total reclassification adjustments related to cash flow hedges, net of tax$(681)$(672)$(2,192)$(1,273)
Amortization of components of defined benefit plans:
Prior service costOperations and maintenance$24 $19 $79 $58 
Actuarial gain (loss)Operations and maintenance(597)(83)(1,791)(524)
(573)(64)(1,712)(466)
Income taxIncome tax benefit (expense)143 89 407 184 
Total reclassification adjustments related to defined benefit plans, net of tax$(430)$25 $(1,305)$(282)
Total reclassifications$(1,111)$(647)$(3,497)$(1,555)

Balances by classification included within AOCI, net of tax on the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):
Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
As of December 31, 2019$(15,122)$(456)$(15,077)$(30,655)
Other comprehensive income (loss)
before reclassifications181 55 236 
Amounts reclassified from AOCI1,630 562 1,305 3,497 
As of September 30, 2020$(13,492)$287 $(13,717)$(26,922)
Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
As of December 31, 2018$(17,307)$328 $(9,937)$(26,916)
Other comprehensive income (loss)
before reclassifications(334)(334)
Amounts reclassified from AOCI1,639 (366)282 1,555 
As of September 30, 2019$(15,668)$(372)$(9,655)$(25,695)

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(12)    Employee Benefit Plans

Change in Accounting Principle - Pension Accounting Asset Method

Effective January 1, 2020, the Company changed its method of accounting for net periodic benefit cost. Prior to the change, the Company used a calculated value for determining market-related value of plan assets which amortized the effects of gains and losses over a five-year period. Effective with the accounting change, the Company will use a calculated value for the return-seeking assets (equities) in the portfolio and fair value for the liability-hedging assets (fixed income). The Company considers the fair value method for determining market-related value of liability-hedging assets to be a preferable method of accounting because asset-related gains and losses are subject to amortization into pension cost immediately. Additionally, the fair value for liability-hedging assets allows for the impact of gains and losses on this portion of the asset portfolio to be reflected in tandem with changes in the liability which is linked to changes in the discount rate assumption for re-measurement.

We evaluated the effect of this change in accounting method and deemed it immaterial to the historical and current financial statements and therefore did not account for the change retrospectively. Accordingly, the Company calculated the cumulative difference using a calculated value versus fair value to determine market-related value for liability-hedging assets of the portfolio. The cumulative effect of this change, as of January 1, 2020, resulted in a decrease to prior service costs, as recorded in Other income (expense), net, of $0.6 million, an increase in Income tax expense of $0.2 million and an increase to Net income of $0.4 million within the accompanying Condensed Consolidated Statements of Income for the nine months ended September 30, 2020.

Funding Status of Employee Benefit Plans

Based on the fair value of assets and estimated discount rate used to value benefit obligations as of September 30, 2020, we estimate the unfunded status of our employee benefit plans to be approximately $51 million compared to $51 million at December 31, 2019. In 2012, we froze our pension plan and closed it to new participants. Since then, we have implemented various de-risking strategies including lump sum buyouts, the purchase of annuities and the reduction of return-seeking assets over time to a more liability-hedged portfolio. As a result, recent capital markets volatility driven by the COVID-19 pandemic has not materially affected our unfunded status and does not require interim re-measurement of our pension plan assets or defined benefit obligations.

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,
2020201920202019
Service cost$1,352 $1,346 $4,058 $4,037 
Interest cost3,356 4,344 10,069 13,031 
Expected return on plan assets(5,647)(6,100)(16,943)(18,300)
Prior service cost (benefit)19 
Net loss (gain)2,093 941 6,279 2,822 
Net periodic benefit cost$1,154 $537 $3,463 $1,609 

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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,
2020201920202019
Service cost$514 $454 $1,542 $1,362 
Interest cost412 560 1,237 1,683 
Expected return on plan assets(46)(57)(137)(172)
Prior service cost (benefit)(136)(99)(410)(298)
Net loss (gain)15 
Net periodic benefit cost$749 $858 $2,247 $2,575 

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,
2020201920202019
Service cost$1,035 $429 $1,482 $2,406 
Interest cost274 324 824 972 
Prior service cost (benefit)
Net loss (gain)425 134 1,277 402 
Net periodic benefit cost$1,735 $887 $3,584 $3,781 

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 2020 and anticipated contributions for 2020 and 2021 are as follows (in thousands):
Contributions MadeAdditional ContributionsContributions
Nine Months Ended September 30, 2020Anticipated for 2020Anticipated for 2021
Defined Benefit Pension Plan$12,700 $$12,700 
Non-pension Defined Benefit Postretirement Healthcare Plans$4,006 $1,335 $5,227 
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans$1,065 $355 $1,964 


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(13)    Commitments and Contingencies

There have been no significant changes to commitments and contingencies from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2019 Annual Report on Form 10-K except for those described below and in Note 5.

Power Sales Agreement - Colorado Electric

On July 1, 2020, Colorado Electric entered into a PSA with the City of Colorado Springs to sell up to 60 MW of wind energy purchased from PRPA under a separate 60 MW PPA transacted on June 26, 2019. This PSA with the City of Colorado Springs expires June 30, 2025.

Power Purchase Agreement - South Dakota Electric

On September 11, 2020, South Dakota Electric entered into a PPA with Fall River Solar, LLC to purchase up to 80 MW of renewable energy upon construction completion of a new solar facility which is expected by the end of 2022. This agreement will expire 20 years after construction completion.


(14)    Income Taxes

CARES Act

On March 27, 2020, the President signed the CARES Act, which contained, in part, an allowance for deferral of the employer portion of Social Security employment tax liabilities until 2021 and 2022, as well as a COVID-19 employee retention tax credit of up to $5,000 per eligible employee.

Eligible employers are taxpayers experiencing either: (1) a full or partial suspension of business operations stemming from a government COVID-19 related order or (2) a more than 50% drop in gross receipts compared to the corresponding calendar quarter in 2019. This 50% employee retention tax credit applies up to $10,000 in qualified wages paid between March 13, 2020 through December 31, 2020, and is refundable to the extent it exceeds the employer portion of payroll tax liability.

Eligible wages or employer-paid health benefits must be paid for the period of time during which an employee did not provide services. However, employees do not need to stop providing all services to the employer for the credit to potentially apply.

Additionally, the CARES Act accelerates the amount of alternative minimum tax (“AMT”) credits that can be refunded for the 2018 and 2019 annual tax returns. In 2020, we filed for, and received, a refund of approximately $2.4 million of AMT credit carryforwards under this provision.

During the three and nine months ended September 30, 2020, we utilized the payroll tax deferral provision which allowed us to defer payment of approximately $4.0 million and $6.9 million, respectively, of Social Security employment tax liabilities. We are currently reviewing the potential future benefits of the CARES Act related to employee retention tax credits to assess the impact on our financial position, results of operations and cash flows.

Income tax (expense) for the Three Months Ended September 30, 2020 Compared to the Three Months Ended September 30, 2019.

Income tax (expense) for the three months ended September 30, 2020 was $(4.7) million compared to $(2.5) million reported for the same period in 2019. For the three months ended September 30, 2020, the effective tax rate was 10.3% compared to 14.0% for the same period in 2019. The lower effective tax rate is primarily due to increased tax benefits from federal production tax credits associated with new wind assets and 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 as discussed in Note 5.

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Income tax (expense) for the Nine Months Ended September 30, 2020 Compared to the Nine Months Ended September 30, 2019.

Income tax (expense) for the nine months ended September 30, 2020 was $(25) million compared to $(22) million reported for the same period in 2019. The effective tax rate was 13.6% for both the nine months ended September 30, 2020 and 2019, primarily due to increased tax benefits from forecasted federal production tax credits associated with new wind assets and 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 as discussed in Note 5 offset by a prior year discrete tax benefit related to repairs and certain indirect costs.


(15)     Investments

In February 2018, we contributed $28 million of assets in exchange for equity securities in a privately held oil and gas company as we divested our Oil and Gas segment. The carrying value of our investment in the equity securities was recorded at cost. We review this investment on a periodic basis to determine whether a significant event or change in circumstances has occurred that may have an adverse effect on the value of the investment.

During the third quarter of 2019, we assessed our investment for impairment as a result of a deterioration in earnings performance of the privately held oil and gas company and an adverse change in future natural gas prices. We engaged a third-party valuation consultant to estimate the fair value of our investment. The valuation was primarily based on an income approach but also considered a market valuation approach. The significant inputs used to estimate the fair value were the oil and gas reserve quantities and values utilizing forward market price curves, industry standard reserve adjustment factors and a discount rate of 10%. Based on the results of the valuation, we concluded that the carrying value of the investment exceeded fair value. As a result, we recorded a pre-tax impairment loss of $20 million for the three months ended September 30, 2019, which was the difference between the carrying value and the fair value of the investment at that time.

During the first quarter of 2020, we assessed our investment for impairment as a result of continued adverse changes in future natural gas prices and liquidity concerns at the privately held oil and gas company. We performed an internal analysis to compute the fair value of our investment, utilizing a consistent methodology as applied during the third quarter of 2019. Based on the results of the valuation, we concluded that the carrying value of the investment exceeded fair value. As a result, we recorded a pre-tax impairment loss of $6.9 million for the three months ended March 31, 2020, which was the difference between the carrying value and the fair value of the investment at that time.

The following table presents the carrying value of our investments (in thousands) as of:
September 30, 2020December 31, 2019
Investment in privately held oil and gas company$1,500 $8,359 
Cash surrender value of life insurance contracts13,467 13,056 
Other investments692 514 
Total investments$15,659 $21,929 


(16)    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 those items disclosed in Note 5.
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ITEM 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.


Executive Summary

We are a customer-focused, growth-oriented utility company operating in the United States. We report our operations and results in the following business segments:

Electric Utilities: Our Electric Utilities segment generates, transmits and distributes electricity to approximately 214,000 customers in Colorado, Montana, South Dakota and Wyoming. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our distribution systems. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates. We also provide non-regulated services through our Tech Services product lines.

Gas Utilities: Our Gas Utilities segment conducts natural gas utility operations through our Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming subsidiaries. Our Gas Utilities segment distributes and transports natural gas through our pipeline network to approximately 1,066,000 natural gas customers. Additionally, we sell contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates, on an as-available basis.

Black Hills Energy Services provides natural gas supply to approximately 49,000 retail distribution customers under the Choice Gas Program in Nebraska and Wyoming. Additionally, we provide services under the Service Guard Comfort Plan and Tech Services and also offer HomeServe products.

Power Generation: Our Power Generation segment produces electric power from its non-regulated generating plants and sells the electric capacity and energy primarily to our utilities under long-term contracts.

Mining: Our Mining segment extracts coal at our mine near Gillette, Wyoming, and sells the coal primarily to on-site, mine-mouth power generation facilities.

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. All of our non-utility business segments support our utilities. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other.

Certain industries 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, 2020 and 2019, and our financial condition as of September 30, 2020 and December 31, 2019, 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.

See Forward-Looking Information in the Liquidity and Capital Resources section of this Item 2, beginning on Page 59.

COVID-19 Pandemic

One of the Company’s core values is safety. The COVID-19 pandemic has given us an opportunity to demonstrate our commitment to the health and safety of our customers, employees, business partners and the communities we serve. We have executed our business continuity plans across all of our jurisdictions with the goal of continuing to provide safe and reliable service during the COVID-19 pandemic.
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For the three and nine months ended September 30, 2020, we have experienced limited impacts to our financial results and operational activities due to COVID-19. Year-to-date decreases to gross margins are driven primarily by lower volumes and waived customer late payment fees. Increased operations and maintenance expenses due to sequestration of mission critical and essential employees and increased bad debt expense were partially offset by decreased training, travel, outside services and employee related expenses.

During the three and nine months ended September 30, 2020, COVID-19 had a limited impact on revenues and customer loads. Increases in revenues and customer loads for the three months ended September 30, 2020, when compared to the same period in the prior year, were driven primarily by warmer and drier weather across our service territories. Declines in revenues and customer loads for the nine months ended September 30, 2020, when compared to the same period in the prior year, were driven primarily by milder first quarter winter temperatures in our Gas Utilities’ service territories. We continue to closely monitor loads in our states as updated executive orders and recommendations associated with COVID-19 are provided. We have continued to proactively communicate with various commercial and industrial customers in our service territories to understand their needs and forecast the potential financial implications. We have increased our allowance for credit losses and bad debt expense by $1.7 million and $3.7 million for the three and nine months ended September 30, 2020, respectively, after considering the potential economic impact of the COVID-19 pandemic in forward looking projections related to write-off and recovery rates. All of our jurisdictions temporarily suspended disconnections for a period of time. State orders lifting those restrictions have been issued in nearly all of our jurisdictions; however, we expect the status of restrictions will continue to fluctuate for the next several months. We continue to monitor customer loads, accounts receivable arrears balances, disconnects, cash flows and bad debt expense. We are proactively working with customers to establish payment plans and find available payment assistance resources.

We continue to maintain adequate liquidity to operate our businesses and fund our capital investment program. In February 2020, the Company issued $100 million in equity to support its 2020 capital investment program. In June 2020, the Company issued $400 million of long-term debt which was used to repay short-term debt and for working capital and general corporate purposes. For the nine months ended September 30, 2020, the Company also utilized a combination of its $750 million Revolving Credit Facility and CP Program to meet its funding requirements. The Company has no material debt maturities until late 2023 and as of September 30, 2020, had $648 million of liquidity which included $7.0 million of cash and $641 million of available capacity on its Revolving Credit Facility. We continue to meet our debt covenant requirements. We also continue to monitor the funding status of our employee benefit plan obligations, which did not materially change during the nine months ended September 30, 2020.

We are monitoring supply chains, including lead times for key materials and supplies, availability of resources, and statuses of large capital projects. To date, there have been limited impacts from COVID-19 on supply chains including the availability of supplies, materials and lead times. Capital projects are ongoing without material disruption to schedules. Our third party resources continue to support our business plans without disruption. Contingency plans are ready to be executed if significant disruption to supply chain occurs; however, we currently do not anticipate a significant impact from COVID-19 on our capital investment plan for 2020.

We continue to work closely with local health, public safety and government officials to minimize the spread of COVID-19 and its impact to our employees and the services we provide to our customers. Actions the Company had taken earlier in the year include implementing protocols for our field operations personnel to continue to safely and effectively interact with our customers, asking employees to work from home, requiring employees to complete daily health assessments, covering COVID-19 testing at 100% for our active employee medical plans, limiting travel to only mission-critical purposes and sequestering essential employees.

During the third quarter of 2020, we suspended sequestration of essential employees but continue to monitor the impacts of COVID-19 in our service territories to ensure we provide essential services to our customers. Additionally, we implemented our Ready2Return program, which includes a phased return of our employees to our work facilities while keeping our workforce healthy, safe and informed. Our Ready2Return program also focuses on enhancing our facility readiness to improve ventilation, ensure social distancing and establish cleaning services to reduce the spread of infection.

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

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During these uncertain times, we remain highly focused on the safety and health of our customers, employees, business partners and communities. We continue to monitor load, customers’ ability to pay, the potential for supply chain disruption that may impact our capital and maintenance project plans, the availability of resources to execute our plans and the capital markets to ensure we have the liquidity necessary to support our financial needs.

As we look forward to the fourth quarter of 2020 and beyond, we anticipate that our operating results could be further affected by COVID-19, as discussed in detail in our Risk Factors.

2020 Business Segment Highlights and Corporate Activity

Electric Utilities

South Dakota Electric and Wyoming Electric continued construction of the $79 million, Corriedale project. The wind project will be jointly owned by the two electric utilities to deliver renewable energy for large commercial, industrial and governmental agency customers. The project is expected to be fully in service in the fourth quarter of 2020.

On October 15, 2020, the FERC approved a settlement agreement that represents a resolution of all issues in the joint application filed by Wyoming Electric and Black Hills Wyoming on August 2, 2019 for approval of a new 60 MW PPA. Under terms of the settlement, Wyoming Electric will continue to receive 60 MW of capacity and energy from the Wygen I power plant. The new agreement will commence on January 1, 2022, replace the existing PPA and continue for 11 years.

On September 23, 2020, Colorado Electric received approval from the CPUC for its request for approval of its preferred solar bid in support of its Renewable Advantage program. The program plans to add up to 200 MW of renewable energy in Colorado by the end of 2023.

On July 10, 2020, Wyoming Electric set a new all-time peak load of 271 MW, surpassing the previous peak of 265 MW set in July 2019.

On May 5, 2020, citizens in Pueblo, Colorado voted overwhelmingly to retain Colorado Electric as its electric utility provider by 75.6% of votes cast. The current franchise agreement continues through 2030.

Gas Utilities

On September 11, 2020, Colorado Gas filed a rate review with the CPUC seeking recovery on significant infrastructure investments in its 7,000-mile natural gas pipeline system. The rate review requests $13.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 9.95%. The request seeks to implement new rates in the second quarter of 2021. On September 11, 2020, in accordance with the final order from the earlier rate review discussed below, Colorado Gas also filed a new SSIR proposal that would recover safety-focused investments in its system over five years.

On June 1, 2020, Nebraska Gas filed a rate review with the NPSC to consolidate rate schedules into a new, single statewide structure and seek recovery on significant infrastructure investments in its 13,000-mile natural gas pipeline system. The rate review requests $17.3 million in new revenue with a capital structure of 50% equity and 50% debt and a return on equity of 10%. Nebraska statute allows for implementation of interim rates 90 days after filing a rate review and Nebraska Gas implemented interim rates effective on September 1, 2020. The request seeks to finalize rates in the first quarter of 2021. Nebraska Gas is also requesting an extension of its SSIR for five years to align the rider recovery mechanisms across the consolidated utility.

On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting $2.5 million in new revenue to recover investments in safety, reliability and system integrity and approval to consolidate rates, tariffs, and services of its two existing gas distribution territories. Colorado Gas also requested a new rider mechanism to recover future safety and integrity investments in its system. On May 19, 2020, the CPUC issued a final order which denied the new system integrity recovery mechanism and consolidation of rate territories. In addition, the order resulted in an annual revenue decrease of $0.6 million and a return on equity of 9.2%. New rates were effective July 3, 2020.

39



Wyoming Gas’s new single statewide rate structure was effective March 1, 2020. On December 11, 2019, Wyoming Gas received approval from the WPSC to consolidate the rates, tariffs and services of its four existing gas distribution territories. New rates are expected to generate $13 million in new annual revenue based on a return on equity of 9.40% and a capital structure of 50.23% equity and 49.77% debt. The approval also allows for a rider to recover integrity investments for system safety and reliability.

Power Generation

On October 15, 2020, the FERC approved a settlement agreement that represents a resolution of all issues in the joint application filed by Black Hills Wyoming and Wyoming Electric on August 2, 2019 for approval of a new 60 MW PPA. See additional information in the Electric Utilities Segment highlights above.

Corporate and Other

On August 20, 2020, Fitch affirmed South Dakota Electric’s credit rating at A.

On August 20, 2020, Fitch affirmed our BBB+ rating and maintained a stable outlook.

On August 3, 2020, we filed a shelf registration and DRSPP with the SEC. In conjunction with these shelf filings, we renewed the ATM. The renewed ATM program, which allows us to sell shares of our common stock, is the same as the prior program other than the aggregate value increased from $300 million to $400 million and a forward sales option was incorporated.

On June 17, 2020, we completed a public debt offering of $400 million principal amount in senior unsecured notes. The debt offering consisted of $400 million of 2.50%, 10-year senior notes due June 15, 2030. The proceeds were used to repay short-term debt and for working capital and general corporate purposes.

On April 16, 2020, S&P affirmed South Dakota Electric’s credit rating at A.

On April 10, 2020, S&P affirmed our BBB+ rating and maintained a stable outlook.

On February 27, 2020, we issued 1.2 million shares of common stock at a price of $81.77 per share for net proceeds of $99 million.


40


Results of Operations

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

Consolidated Summary and Overview
(in thousands, except per share amounts)Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
Revenue
Revenue$386,525 $363,491 $1,328,456 $1,368,748 
Inter-company eliminations(39,935)(37,943)(117,902)(111,502)
$346,590 $325,548 $1,210,554 $1,257,246 
Adjusted operating income (a)
Electric Utilities$52,083 $50,653 $121,726 $125,219 
Gas Utilities18,147 4,736 139,253 116,607 
Power Generation8,738 11,822 31,489 33,945 
Mining3,505 3,374 9,992 9,351 
Corporate and Other(239)(34)(108)(439)
Operating income82,234 70,551 302,352 284,683 
Interest expense, net(36,041)(33,487)(107,039)(102,469)
Impairment of investment— (19,741)(6,859)(19,741)
Other income (expense), net(1,193)580 (703)55 
Income tax (expense)(4,651)(2,508)(25,484)(22,078)
Net income40,349 15,395 162,267 140,450 
Net income attributable to noncontrolling interest(4,066)(3,655)(11,844)(10,319)
Net income available for common stock$36,283 $11,740 $150,423 $130,131 
Earnings per share, Basic$0.58 $0.19 $2.41 $2.15 
Earnings per share, Diluted$0.58 $0.19 $2.41 $2.15 
__________
(a)    Adjusted operating income recognizes inter-segment 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, 2020 Compared to Three Months Ended September 30, 2019:

The variance to the prior year included the following:

COVID-19 related impacts to consolidated results included $1.0 million of lower gross margin driven primarily by waived customer late payment fees, $1.7 million of additional bad debt expense and $0.5 million of costs due to sequestration of mission-critical and essential employees which were partially offset by $1.1 million of lower travel, training, and employee related expenses;
Electric Utilities’ adjusted operating income increased $1.4 million primarily due to rider revenues and benefits from the release of TCJA revenue reserves partially offset by higher operating expenses and mark-to-market losses on wholesale energy contracts;
Gas Utilities’ adjusted operating income increased $13 million primarily due to drier summer weather favorably impacting our Nebraska service territory irrigation loads, new customer rates in Wyoming and Nebraska and mark-to-market gains on non-utility natural gas commodity contracts partially offset by higher operating expenses;
Power Generation adjusted operating income decreased $3.1 million primarily due to higher operating expenses driven by the early retirement of certain assets;
Interest expense increased $2.6 million primarily due to higher debt balances partially offset by lower rates;
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A prior year $20 million pre-tax non-cash impairment of our investment in equity securities of a privately held oil and gas company;
Other expense increased $1.8 million primarily due to increased costs for our non-qualified benefit plan driven by market performance on plan assets and increased non-service pension costs resulting from a change in accounting principle for our defined benefit pension plan effective January 1, 2020; and
Income tax expense increased $2.1 million primarily due to higher pre-tax earnings partially offset by a lower effective tax rate.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019:

The variance to the prior year included the following:

COVID-19 related impacts to consolidated results included $3.4 million of lower gross margin driven primarily by lower volumes and waived customer late payment fees, $2.6 million of costs due to sequestration of mission-critical and essential employees and $3.7 million of additional bad debt expense which were partially offset by $4.6 million of lower travel, training, outside services and employee related expenses;
Electric Utilities’ adjusted operating income decreased $3.5 million primarily due to higher operating expenses and COVID-19 impacts partially offset by benefits from the release of TCJA revenue reserves, rider revenues and favorable weather;
Gas Utilities’ adjusted operating income increased $23 million primarily due to new customer rates in Wyoming, mark-to-market gains on non-utility natural gas commodity contracts, prior year amortization of excess deferred income taxes and customer growth partially offset by higher operating expenses and COVID-19 impacts;
Power Generation adjusted operating income decreased $2.5 million primarily due to higher operating expenses driven by the early retirement of certain assets;
Interest expense increased $4.6 million primarily due to higher debt balances partially offset by lower rates;
A prior year $20 million pre-tax non-cash impairment of our investment in equity securities of a privately held oil and gas company compared to a current year $6.9 million impairment on the same investment; and
Income tax expense increased $3.4 million primarily due to higher pre-tax earnings with similar effective tax rates.

Operating Results by Segment

A discussion of operating results from our segments and Corporate activities follows in the sections below. Revenues for operating segments in the following sections are presented in total and by retail class. For disaggregation of revenue by contract type and operating segment, see Note 2 of the Notes to Condensed Consolidated Financial Statements for more information.


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 measures. Furthermore, this measure is not intended to replace operating income, as determined in accordance with GAAP, as an indicator of operating performance.


42


Electric Utilities
Three Months Ended September 30,Nine Months Ended September 30,
20202019Variance20202019Variance
(in thousands)
Revenue$200,842 $191,384 $9,458 $538,181 $540,665 $(2,484)
Total fuel and purchased power77,885 71,593 6,292 201,398 207,004 (5,606)
Gross margin (non-GAAP)122,957 119,791 3,166 336,783 333,661 3,122 
Operations and maintenance47,426 47,172 254 144,956 143,049 1,907 
Depreciation and amortization23,448 21,966 1,482 70,101 65,393 4,708 
Total operating expenses70,874 69,138 1,736 215,057 208,442 6,615 
Adjusted operating income$52,083 $50,653 $1,430 $121,726 $125,219 $(3,493)

Three Months Ended September 30, 2020 Compared to the Three Months Ended September 30, 2019:

Gross margin for the three months ended September 30, 2020 increased as a result of the following:
(in millions)
Release of TCJA revenue reserves$1.5 
Rider recovery1.3 
Off-system power marketing0.9 
Weather0.2 
Mark-to-market on wholesale energy contracts(1.4)
COVID-19 impacts(0.2)
Other0.9 
Total increase in Gross margin (non-GAAP)$3.2 

Operations and maintenance expense increased primarily due to COVID-19 related expenses of $0.5 million for the sequestration of essential employees and $0.3 million of additional bad debt expense which were partially offset by $0.4 million of lower travel, training and employee related expenses.

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

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Nine Months Ended September 30, 2020 Compared to the Nine Months Ended September 30, 2019:

Gross margin for the nine months ended September 30, 2020 increased as a result of the following:
(in millions)
Release of TCJA revenue reserves$2.7 
Rider recovery and true-up (a)
1.0 
Weather0.9 
COVID-19 impacts (b)
(1.7)
Other0.2 
Total increase in Gross margin (non-GAAP)$3.1 
____________________
(a)    Gross margin increased due to $2.6 million of rider revenues, which was partially offset by a $1.6 million rider true-up.
(b)    The impacts to Electric Utilities’ gross margin from COVID-19 were primarily driven by reduced commercial volumes and waived customer late payment fees partially offset by higher residential usage.

Operations and maintenance expense increased primarily due to $1.4 million of expenses related to the efforts to retain our franchise privileges in Pueblo, Colorado. COVID-19 impacts to operations and maintenance expense included $2.2 million of expenses related to the sequestration of essential employees and $0.9 million of additional bad debt expense which were partially offset by $2.4 million of lower travel, training, outside services and employee related expenses.

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


Operating Statistics
Electric RevenueQuantities Sold
(in thousands)(MWh)
Three Months Ended
September 30,
Nine Months Ended
September 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
20202019202020192020201920202019
Residential$62,395 $58,919 $167,048 $162,257 405,989 384,735 1,113,821 1,075,394 
Commercial64,756 65,732 178,979 186,434 538,299 560,547 1,492,239 1,556,449 
Industrial35,660 33,937 99,725 98,074 462,545 462,809 1,382,710 1,335,260 
Municipal4,834 4,792 12,732 13,184 46,256 46,106 121,027 121,025 
Subtotal Retail Revenue - Electric167,645 163,380 458,484 459,949 1,453,089 1,454,197 4,109,797 4,088,128 
Contract Wholesale (a)
5,924 8,211 14,947 23,335 129,960 229,369 348,991 646,611 
Off-system/Power Marketing Wholesale9,535 6,452 17,939 16,592 167,494 160,357 469,590 436,298 
Other17,738 13,341 46,811 40,789 — — — — 
Total Revenue and Energy Sold200,842 191,384 538,181 540,665 1,750,543 1,843,923 4,928,378 5,171,037 
Other Uses, Losses or Generation, net (b)
— — — — 118,410 112,172 294,466 299,038 
Total Revenue and Energy200,842 191,384 538,181 540,665 1,868,953 1,956,095 5,222,844 5,470,075 
Less cost of fuel and purchased power77,885 71,593 201,398 207,004 
Gross Margin (non-GAAP)$122,957 $119,791 $336,783 $333,661 


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Electric Revenue
(in thousands)
Gross Margin (non-GAAP) (in thousands)
Quantities Sold (MWh) (b)
Three Months Ended September 30,202020192020201920202019
Colorado Electric$74,742 $70,771 $42,236 $41,916 666,916 634,098 
South Dakota Electric (a)
78,861 77,022 58,062 55,217 699,150 835,725 
Wyoming Electric47,239 43,591 22,659 22,658 502,887 486,272 
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold$200,842 $191,384 $122,957 $119,791 1,868,953 1,956,095 
Electric Revenue
(in thousands)
Gross Margin (non-GAAP) (in thousands)
Quantities Sold (MWh) (b)
Nine Months Ended September 30,202020192020201920202019
Colorado Electric$191,197 $186,030 $106,961 $104,411 1,765,501 1,611,126 
South Dakota Electric (a)
213,059 225,309 163,659 162,390 1,954,902 2,438,366 
Wyoming Electric133,925 129,326 66,163 66,860 1,502,441 1,420,583 
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold$538,181 $540,665 $336,783 $333,661 5,222,844 5,470,075 
________________
(a)    Revenue and purchased power for the three and nine months ended September 30, 2020 as well as associated quantities, for certain wholesale contracts have been presented on a net basis.  Amounts for the three and nine months ended September 30, 2019, were presented on a gross basis and, due to their immaterial nature, were not revised.  This presentation change has no impact on Gross margin.
(b)    Includes company uses, line losses, and excess exchange production.
Three Months Ended
September 30,
Nine Months Ended
September 30,
Quantities Generated and Purchased (MWh)2020201920202019
Coal-fired592,681 564,220 1,712,540 1,621,355 
Natural Gas and Oil199,408 234,366 453,950 445,498 
Wind54,518 55,407 191,696 167,331 
Total Generated846,607 853,993 2,358,186 2,234,184 
Purchased (a)
1,022,346 1,102,102 2,864,658 3,235,891 
Total Generated and Purchased1,868,953 1,956,095 5,222,844 5,470,075 

Three Months Ended
September 30,
Nine Months Ended
September 30,
Quantities Generated and Purchased (MWh)2020201920202019
Generated:
Colorado Electric97,450 149,509 271,957 341,925 
South Dakota Electric518,821 489,042 1,434,353 1,262,336 
Wyoming Electric230,336 215,442 651,876 629,923 
Total Generated846,607 853,993 2,358,186 2,234,184 
Purchased:
Colorado Electric569,466 484,589 1,493,544 1,269,201 
South Dakota Electric (a)
180,329 346,683 520,549 1,176,030 
Wyoming Electric272,551 270,830 850,565 790,660 
Total Purchased1,022,346 1,102,102 2,864,658 3,235,891 
Total Generated and Purchased1,868,953 1,956,095 5,222,844 5,470,075 
________________
(a)    Purchased power quantities for the three and nine months ended September 30, 2020, for certain wholesale contracts have been presented on a net basis.  Amounts for the three and nine months ended September 30, 2019, were presented on a gross basis and, due to their immaterial nature, were not revised.  This presentation change has no impact on Gross margin.
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Three Months Ended September 30,
Degree days20202019
ActualVariance from
Normal
ActualVariance from
Normal
Heating Degree Days:
Colorado Electric99 %(96)%
South Dakota Electric202 (10)%175 (22)%
Wyoming Electric208 (29)%120 (77)%
Combined (a)
156 (14)%86 (36)%
Cooling Degree Days:
Colorado Electric987 44 %1,079 58 %
South Dakota Electric561 %366 (31)%
Wyoming Electric492 65 %433 45 %
Combined (a)
742 34 %705 27 %

Nine Months Ended September 30,
Degree days20202019
ActualVariance from
Normal
ActualVariance from
Normal
Heating Degree Days:
Colorado Electric3,073 (9)%3,156 (6)%
South Dakota Electric4,440 — %5,370 20 %
Wyoming Electric4,356 (3)%4,677 %
Combined (a)
3,799 (4)%4,198 %
Cooling Degree Days:
Colorado Electric1,369 53 %1,226 37 %
South Dakota Electric681 %404 (36)%
Wyoming Electric593 70 %462 33 %
Combined (a)
977 41 %791 14 %
____________________
(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 Power Plant Fleet Availability (a)
2020201920202019
Coal-fired plants (b)
97.4 %94.6 %94.1 %90.0 %
Natural gas-fired plants and Other plants (c)(d)
79.7 %89.6 %80.5 %89.8 %
Wind97.7 %93.7 %98.3 %95.0 %
Total Availability86.8 %91.5 %86.3 %90.3 %
Wind Capacity Factor33.2 %33.8 %39.3 %37.1 %
____________________
(a)    Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.
(b)    2019 included planned outages at Neil Simpson II and Wygen III and unplanned outages at Wyodak Plant and Wygen III.
(c)     2020 included a planned outage at Cheyenne Prairie and unplanned outages at Pueblo Airport Generation and Lange CT.
(d)    2019 included planned outages at Neil Simpson CT and Lange CT.

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Gas Utilities
Three Months Ended September 30,Nine Months Ended September 30,
20202019Variance20202019Variance
(in thousands)
Revenue:
Natural gas - regulated$128,468 $117,549 $10,919 $612,797 $651,366 $(38,569)
Other - non-regulated services15,461 13,195 2,266 53,015 55,927 (2,912)
Total revenue143,929 130,744 13,185 665,812 707,293 (41,481)
Cost of sales:
Natural gas - regulated25,235 28,154 (2,919)222,144 280,312 (58,168)
Other - non-regulated services1,800 4,870 (3,070)4,874 16,975 (12,101)
Total cost of sales27,035 33,024 (5,989)227,018 297,287 (70,269)
Gross margin (non-GAAP)116,894 97,720 19,174 438,794 410,006 28,788 
Operations and maintenance73,642 70,170 3,472 223,351 225,239 (1,888)
Depreciation and amortization25,105 22,814 2,291 76,190 68,160 8,030 
Total operating expenses98,747 92,984 5,763 299,541 293,399 6,142 
Adjusted operating income$18,147 $4,736 $13,411 $139,253 $116,607 $22,646 


Three Months Ended September 30, 2020 Compared to the Three Months Ended September 30, 2019:

Gross margin for the three months ended September 30, 2020 increased as a result of:
(in millions)
Weather (a)
$8.4 
New rates4.9 
Mark-to-market on non-utility natural gas commodity contracts1.8 
Customer growth - distribution1.5 
Non-Utility - Tech Services0.6 
COVID-19 impacts (b)
(0.8)
Other2.8 
Total increase in Gross margin (non-GAAP)$19.2 
____________________
(a)    Weather impacts for the three months ended September 30, 2020 compared to the same period in the prior year include increased irrigation loads to agriculture customers in 2020 in our Nebraska Gas service territory as 2019 was a record precipitation year and increased heating demand due to cooler temperatures.
(b)    The impacts to Gas Utilities’ gross margin from COVID-19 were primarily driven by waived customer late payment fees.

Operations and maintenance expense increased primarily due to higher employee costs. COVID-19 impacts to operations and maintenance expense included $1.4 million of additional bad debt expense which was partially offset by $0.7 million of lower travel and training expenses.

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

47


Nine Months Ended September 30, 2020 Compared to the Nine Months Ended September 30, 2019:

Gross margin for the nine months ended September 30, 2020 increased as a result of:
(in millions)
New rates$14.1 
Mark-to-market on non-utility natural gas commodity contracts4.2 
Customer growth - distribution3.6 
Prior year amortization of excess deferred income taxes3.5 
Non-Utility - Tech Services and Gas Supply Services1.4 
Weather (a)
0.8 
COVID-19 impacts (b)
(1.7)
Other2.9 
Total increase in Gross margin (non-GAAP)$28.8 
____________________
(a)    Weather impacts for the nine months ended September 30, 2020 compared to the same period in the prior year include increased irrigation loads to agriculture customers in the third quarter of 2020 in our Nebraska Gas service territory as 2019 was a record precipitation year mostly offset by lower heating demand in the first quarter of 2020 due to warmer temperatures.
(b)    The impacts to Gas Utilities’ gross margin from COVID-19 were primarily driven by reduced volumes from certain transport customers and waived customer late payment fees.

Operations and maintenance expense decreased primarily due to $2.7 million of lower outside services expenses and $1.2 million of lower employee costs partially offset by $1.0 million of higher property taxes due to a higher asset base. COVID-19 impacts to operations and maintenance expense included $2.8 million of additional bad debt expense which was partially offset by $2.2 million of lower travel, training, outside services and employee related expenses.

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


Operating Statistics
Gas 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,
202020192020201920202019
Residential$61,515 $57,244 $48,165 $43,441 4,058,040 3,599,549 
Commercial19,940 19,629 12,821 11,589 2,354,719 2,298,919 
Industrial7,280 8,770 2,514 2,493 2,674,127 2,960,930 
Other1,271 2,499 1,271 2,499 — — 
Total Distribution90,006 88,142 64,771 60,022 9,086,886 8,859,398 
Transportation and Transmission38,462 29,407 38,462 29,373 33,668,174 31,538,815 
Total Regulated128,468 117,549 103,233 89,395 42,755,060 40,398,213 
Non-regulated Services15,461 13,195 13,661 8,325 
Total Gas Revenue & Gross Margin
(non-GAAP)
$143,929 $130,744 $116,894 $97,720 
48


Gas 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,
202020192020201920202019
Residential$351,986 $383,466 $207,654 $201,168 40,790,670 44,356,725 
Commercial127,617 146,752 61,676 61,673 19,155,051 21,484,646 
Industrial18,539 18,764 6,697 5,830 5,771,732 5,141,399 
Other856 (968)856 (968)— — 
Total Distribution498,998 548,014 276,883 267,703 65,717,453 70,982,770 
Transportation and Transmission113,799 103,352 113,770 103,351 108,967,182 110,622,285 
Total Regulated612,797 651,366 390,653 371,054 174,684,635 181,605,055 
Non-regulated Services53,015 55,927 48,141 38,952 
Total Gas Revenue & Gross Margin
(non-GAAP)
$665,812 $707,293 $438,794 $410,006 

Gas 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,
202020192020201920202019
Arkansas Gas$21,043 $21,387 $17,400 $16,249 3,925,893 4,094,454 
Colorado Gas22,724 22,632 16,972 15,667 3,702,666 3,806,360 
Iowa Gas18,155 16,381 14,672 13,135 5,628,110 5,686,772 
Kansas Gas18,591 19,013 13,099 12,309 8,564,408 7,602,758 
Nebraska Gas46,315 35,715 39,755 28,046��16,525,547 13,999,302 
Wyoming Gas17,101 15,616 14,996 12,314 4,408,436 5,208,567 
Total Gas Revenue & Gross Margin (non-GAAP)$143,929 $130,744 $116,894 $97,720 42,755,060 40,398,213 

Gas 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,
202020192020201920202019
Arkansas Gas$124,621 $127,014 $88,161 $79,148 19,795,077 21,061,567 
Colorado Gas123,943 135,816 73,785 73,022 21,845,915 23,050,638 
Iowa Gas94,386 105,736 50,355 50,773 25,429,502 28,834,731 
Kansas Gas70,571 77,609 44,162 42,385 25,202,180 24,336,744 
Nebraska Gas170,447 183,827 122,140 111,828 56,857,061 57,815,316 
Wyoming Gas81,844 77,291 60,191 52,850 25,554,900 26,506,059 
Total Gas Revenue & Gross Margin (non-GAAP)$665,812 $707,293 $438,794 $410,006 174,684,635 181,605,055 

Our Gas Utilities are highly seasonal and sales volumes vary considerably with weather and seasonal heating and industrial loads. Approximately 70% of our Gas Utilities’ revenue and margins are expected in the first and fourth quarters of each year. Therefore, revenue for, and certain expenses of, these operations fluctuate significantly among quarters. Depending upon the geographic location in which our Gas Utilities operate, the winter heating season begins around November 1 and ends around March 31.
49


Three Months Ended September 30,
20202019
Heating Degree DaysActualVariance
from Normal
ActualVariance
from Normal
Arkansas Gas (a)
24(44)%(100)%
Colorado Gas159(26)%68(68)%
Iowa Gas1401%43(69)%
Kansas Gas (a)
7027%(101)%
Nebraska Gas109(1)%22(80)%
Wyoming Gas245(20)%183(37)%
Combined (b)
125(13)%53(62)%
Nine Months Ended September 30,
20202019
Heating Degree DaysActualVariance
from Normal
ActualVariance
from Normal
Arkansas Gas (a)
2,036(18)%2,347(5)%
Colorado Gas3,797(7)%4,115—%
Iowa Gas4,104(2)%4,61110%
Kansas Gas (a)
2,851(4)%3,2048%
Nebraska Gas3,636(4)%4,16910%
Wyoming Gas4,678(1)%5,0939%
Combined (b)
3,731(4)%4,2977%
___________
(a)    Arkansas and Kansas have weather normalization mechanisms that mitigate the weather impact on gross margins.
(b)    The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas due to its weather normalization mechanism. Arkansas is 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 5 of the Notes to Condensed Consolidated Financial Statements and Part I, Items 1 and 2 and Part II, Item 8 of our 2019 Annual Report on Form 10-K filed with the SEC.


Power Generation
Three Months Ended September 30,Nine Months Ended September 30,
20202019Variance20202019Variance
(in thousands)
Revenue$26,518 $25,811 $707 $78,606 $75,764 $2,842 
Fuel expense2,320 2,283 37 6,692 6,933 (241)
Operations and maintenance10,539 6,946 3,593 24,886 20,817 4,069 
Depreciation and amortization4,921 4,760 161 15,539 14,069 1,470 
Total operating expense17,780 13,989 3,791 47,117 41,819 5,298 
Adjusted operating income$8,738 $11,822 $(3,084)$31,489 $33,945 $(2,456)
50



Three Months Ended September 30, 2020 Compared to the Three Months Ended September 30, 2019:

Revenue increased in the current year driven primarily by increased MWh sold from new wind assets and additional Black Hills Colorado IPP fired-engine hours. Operating expenses increased primarily due to a $3.1 million expense related to the early retirement of certain assets and higher generation costs and depreciation from new wind assets.

Nine Months Ended September 30, 2020 Compared to the Nine Months Ended September 30, 2019:

Revenue increased in the current year driven by an increase in MWh sold from new wind assets and additional Black Hills Colorado IPP fired-engine hours. Operating expenses increased primarily due to a $3.1 million expense related to the early retirement of certain assets and higher generation costs and depreciation from new wind assets. COVID-19 impacts to operations and maintenance expense included $0.4 million of expenses related to the sequestration of essential employees.

Operating Statistics
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
Quantities Sold, Generated and Purchased
(MWh) (a)
Sold
Black Hills Colorado IPP301,934 275,867 830,860 692,156 
Black Hills Wyoming (b)
157,855 162,668 471,073 476,430 
Black Hills Electric Generation65,697 30,912 255,605 112,461 
Total Sold525,486 469,447 1,557,538 1,281,047 
Generated
Black Hills Colorado IPP301,934 275,867 830,860 692,156 
Black Hills Wyoming (b)
139,313 142,219 408,545 407,001 
Black Hills Electric Generation65,697 30,912 255,605 112,461 
Total Generated506,944 448,998 1,495,010 1,211,618 
Purchased
Black Hills Wyoming (b)
18,004 16,865 62,097 56,205 
Total Purchased18,004 16,865 62,097 56,205 
___________
(a)    Company uses and losses are not included in the quantities sold, generated, and purchased.
(b)    Under the 20-year economy energy PPA 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 Black Hills Wyoming has with South Dakota Electric to cover energy imbalances.
51


Three Months Ended September 30,Nine Months Ended September 30,
Contracted Power Plant Fleet Availability (a)
2020201920202019
Coal-fired plant96.1 %98.0 %94.5 %95.2 %
Natural gas-fired plants (b)
99.8 %97.6 %99.6 %98.4 %
Wind90.6 %81.9 %92.8 %93.4 %
Total Availability95.8 %93.6 %96.3 %96.5 %
Wind Capacity Factor19.4 %15.0 %25.7 %22.1 %
___________
(a)    Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.
(b)     2019 included a planned outage at Pueblo Airport Generation.


Mining
Three Months Ended September 30,Nine Months Ended September 30,
20202019Variance20202019Variance
(in thousands)
Revenue$15,236 $15,552 $(316)$45,857 $45,026 $831 
Operations and maintenance8,923 9,900 (977)28,481 28,988 (507)
Depreciation, depletion and amortization2,808 2,278 530 7,384 6,687 697 
Total operating expenses11,731 12,178 (447)35,865 35,675 190 
Adjusted operating income$3,505 $3,374 $131 $9,992 $9,351 $641 


Operating Statistics
Three Months Ended September 30,Nine Months Ended September 30,
(in thousands, except for Revenue per ton)2020201920202019
Tons of coal sold940 969 2,808 2,720 
Cubic yards of overburden moved1,595 2,341 6,073 6,380 
Revenue per ton$15.60 $15.47 $15.64 $15.90 


Corporate and Other
Three Months Ended September 30,Nine Months Ended September 30,
20202019Variance20202019Variance
(in thousands)
Adjusted operating income (loss)$(239)$(34)$(205)$(108)$(439)$331 



52


Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax (Expense)
Three Months Ended September 30,Nine Months Ended September 30,
20202019Variance20202019Variance
(in thousands)(in thousands)
Interest expense, net$(36,041)$(33,487)$(2,554)$(107,039)$(102,469)$(4,570)
Impairment of investment— (19,741)$19,741 (6,859)(19,741)$12,882 
Other income (expense), net(1,193)580 $(1,773)(703)55 $(758)
Income tax (expense)(4,651)(2,508)$(2,143)(25,484)(22,078)$(3,406)

Three Months Ended September 30, 2020 Compared to the Three Months Ended September 30, 2019.

Interest expense, net

The increase in Interest expense, net for the three months ended September 30, 2020, compared to the same period in the prior year, was driven by higher debt balances partially offset by lower interest rates.

Impairment of Investment

For the three months ended September 30, 2019, we recorded a pre-tax non-cash write-down of $20 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. The remaining book value of our investment is $1.5 million, and this is our only remaining investment in oil and gas exploration and production activities. See Note 15 of the Notes to Condensed Consolidated Financial Statements for additional details.

Other Income (Expense)

The variance in Other income (expense), net for the three months ended September 30, 2020, compared to the same period in the prior year, was primarily due to increased costs for our non-qualified benefit plans which were driven by market performance on plan assets and increased non-service pension costs resulting from a change in accounting principle for our defined benefit pension plan effective January 1, 2020.
Income Tax (Expense)

For the three months ended September 30, 2020, the effective tax rate was 10.3% compared to 14.0% for the same period in 2019. The lower effective tax rate is primarily due to increased tax benefits from federal production tax credits associated with new wind assets and 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.

Nine Months Ended September 30, 2020 Compared to the Nine Months Ended September 30, 2019.

Interest expense, net

The increase in Interest expense, net for the nine months ended September 30, 2020, compared to the same period in the prior year was driven by higher debt balances partially offset by lower interest rates.

Impairment of Investment

For the nine months ended September 30, 2020, 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, compared to a $20 million write-down for the same period in the prior year. The impairments in both years were triggered by continued adverse changes in future natural gas prices and liquidity concerns at the privately held oil and gas company. The remaining book value of our investment is $1.5 million, and this is our only remaining investment in oil and gas exploration and production activities. See Note 15 of the Notes to Condensed Consolidated Financial Statements for additional details.



53



Income Tax (Expense)

The effective tax rate was 13.6% for both the nine months ended September 30, 2020 and 2019, primarily due to increased tax benefits from forecasted federal production tax credits associated with new wind assets and 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 offset by a prior year discrete tax benefit related to repairs and certain indirect costs.


Critical Accounting Policies Involving Significant Accounting Estimates

There have been no material changes in our critical accounting estimates from those reported in our 2019 Annual Report on Form 10-K filed with the SEC except for Pension and Other Postretirement Benefits provided below. We continue to closely monitor the rapidly evolving and uncertain impact of COVID-19 on our critical accounting estimates including, but not limited to, collectibility of customer receivables, recoverability of 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 2019 Annual Report on Form 10-K.

Pension and Other Postretirement Benefits

As described in Note 18 of the Notes to the Consolidated Financial Statements in our 2019 Annual Report on Form 10-K filed with the SEC, we have one defined benefit pension plan, one defined post-retirement healthcare plan and several non-qualified retirement plans. A Master Trust holds the assets for the pension plan. A trust for the funded portion of the post-retirement healthcare plan has also been established.

Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rates, healthcare cost trend rates, expected return on plan assets, compensation increases, retirement rates and mortality rates. The determination of our obligation and expenses for pension and other postretirement benefits is dependent on the assumptions determined by management and used by actuaries in calculating the amounts. Although we believe our assumptions are appropriate, significant differences in our actual experience or significant changes in our assumptions may materially affect our pension and other postretirement obligations and our future expense.

Effective January 1, 2020, the Company changed its method of accounting for net periodic benefit cost. Prior to the change, the Company used a calculated value for determining market-related value of plan assets which amortized the effects of gains and losses over a five-year period. Effective with the accounting change, the Company will use a calculated value for the return-seeking assets (equities) in the portfolio and fair value for the liability-hedging assets (fixed income). The Company considers the fair value method for determining market-related value of liability-hedging assets to be a preferable method of accounting because asset-related gains and losses are subject to amortization into pension cost immediately. Additionally, the fair value for liability-hedging assets allows for the impact of gains and losses on this portion of the asset portfolio to be reflected in tandem with changes in the liability which is linked to changes in the discount rate assumption for re-measurement.

See Note 12 of the Notes to Condensed Consolidated Financial Statements for additional information.


54


Liquidity and Capital Resources

There have been no material changes in Liquidity and Capital Resources from those reported in Item 7 of our 2019 Annual Report on Form 10-K filed with the SEC except as described below and within the “COVID-19 Pandemic” discussion in the Executive Summary section above.

Collateral Requirements

Our utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas which have performance assurance provisions that allow the counterparty to require collateral postings under certain conditions, including when requested on a reasonable basis due to a deterioration in our financial condition or nonperformance. A significant downgrade in our credit ratings, such as a downgrade to a level below investment grade, could result in counterparties requiring collateral postings under such adequate assurance provisions. The amount of credit support that we may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions and the amounts owed by or to the counterparty. At September 30, 2020, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts. For the nine months ended September 30, 2020, we did not experience any requests to post additional collateral, including for concerns over a potential deterioration of our financial condition due to COVID-19.


Cash Flow Activities

The following table summarizes our cash flows for the nine months ended September 30, (in millions):
Cash provided by (used in):20202019Variance
Operating activities$419.5 $386.1 $33.4 
Investing activities$(529.7)$(593.3)$63.6 
Financing activities$107.8 $199.8 $(92.0)

Year-to-Date 2020 Compared to Year-to-Date 2019

Operating Activities

Net cash provided by operating activities was $419 million for the nine months ended September 30, 2020, compared to net cash provided by operating activities of $386 million for the same period in 2019, for an increase of $33 million. The variance was primarily attributable to:

Cash earnings (net income plus non-cash adjustments) were $22 million higher for the nine months ended September 30, 2020 compared to the same period in the prior year primarily driven by higher operating income at the Gas Utilities segment;

Net cash inflows from changes in operating assets and liabilities were $27 million for the nine months ended September 30, 2020, compared to net cash inflows of $15 million in the same period in the prior year. This $12 million increase was primarily due to:

Cash inflows decreased by $46 million primarily as a result of changes in accounts receivable driven by lower commodity prices and increased materials and supplies purchases;

Cash outflows decreased by $72 million as a result of changes in accounts payable and accrued liabilities driven by the impact of lower commodity prices, lower outside services expenses, timing of interest payments, deferral of payroll taxes under the CARES Act and other working capital requirements; and

Cash outflows increased by $13 million primarily as a result of changes in our regulatory assets and liabilities driven by timing of recovery and returns for fuel costs adjustments partially offset by the TCJA tax rate change that was returned to customers in the prior year.

55



Investing Activities

Net cash used in investing activities was $530 million for the nine months ended September 30, 2020, compared to net cash used in investing activities of $593 million for the same period in 2019, a decrease of $64 million primarily due to the following:

Capital expenditures of $536 million for the nine months ended September 30, 2020 compared to $593 million for the same period in the prior year. Higher prior year expenditures were driven by large prior year projects such as the Natural Bridge pipeline project, the Busch Ranch II wind project and construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota to Stegall, Nebraska. These large prior year expenditures were partially offset by the current year Corriedale wind project at our Electric Utilities segment.

Financing Activities

Net cash provided by financing activities for the nine months ended September 30, 2020 was $108 million, compared to $200 million of net cash provided by financing activities for the same period in 2019, a decrease of $92 million primarily due to the following:

$374 million of higher repayments of short-term debt;

Increase of $297 million in net proceeds due to issuances of long-term debt in excess of maturities;

Cash dividends on common stock of $100 million were paid in the current year compared to $92 million paid in the prior year;

Cash outflows for other financing activities increased $4.5 million driven primarily by current year financing costs in the June 17, 2020 debt offering; and

Decrease of $2.0 million in net proceeds from the issuance of common stock;


Dividends

Dividends paid on our common stock totaled $100 million for the nine months ended September 30, 2020, or $0.535 per share per quarter. On October 27, 2020, our board of directors declared a quarterly dividend of $0.565 per share payable December 1, 2020, equivalent to an annual dividend of $2.26 per share. The amount of any future cash dividends to be declared and paid, if any, will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our Revolving Credit Facility and our future business prospects.


Financing Transactions and Short-Term Liquidity

Revolving Credit Facility and CP Program

Our Revolving Credit Facility and CP Program had the following borrowings, outstanding letters of credit, and available capacity (in millions):
CurrentRevolver Borrowings atCP Program Borrowings at
Letters of Credit (a) at
Available Capacity at
Credit FacilityExpirationCapacitySeptember 30, 2020September 30, 2020September 30, 2020September 30, 2020
Revolving Credit Facility and CP ProgramJuly 30, 2023$750 $— $84 $25 $641 
_______________
(a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility.

56


Revolving Credit Facility and CP Program borrowing activity for the nine months ended September 30, 2020 was (dollars in millions):
For the Nine Months Ended September 30, 2020
Maximum amount outstanding - Revolving Credit Facility (based on daily outstanding balances)$220 
Maximum amount outstanding - CP Program (based on daily outstanding balances)$366 
Average amount outstanding - Revolving Credit Facility (based on daily outstanding balances)$109 
Average amount outstanding - CP Program (based on daily outstanding balances)$170 
Weighted average interest rates - Revolving Credit Facility1.75 %
Weighted average interest rates - CP Program1.10 %

Covenant Requirements

The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on certain liens, restrictions on certain transactions, and maintenance of a certain Consolidated Indebtedness to Capitalization Ratio. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. We were in compliance with these covenants as of September 30, 2020. See Note 7 of the Notes to Condensed Consolidated Financial Statements for more information.

Covenants within Wyoming Electric’s financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of September 30, 2020, we were in compliance with these covenants.
Financing Activities

See Notes 7 and 8 of the Notes to Condensed Consolidated Financial Statements for information concerning significant financing activities for the nine months ended September 30, 2020.

Future Financing Plans

We will continue to assess debt and equity needs to support our capital expenditure plan.

Credit Ratings

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

The following table represents the credit ratings and outlook and risk profile of BHC at September 30, 2020:
Rating AgencySenior Unsecured RatingOutlook
S&P (a)
BBB+Stable
Moody’s (b)
Baa2Stable
Fitch (c)
  BBB+Stable
__________
(a)    On April 10, 2020, S&P affirmed our BBB+ rating and maintained a Stable outlook.
(b)    On December 20, 2019, Moody’s affirmed our Baa2 rating and maintained a Stable outlook.
(c)    On August 20, 2020, Fitch affirmed our BBB+ rating and maintained a Stable outlook.

57


The following table represents the credit ratings of South Dakota Electric at September 30, 2020:
Rating AgencySenior Secured Rating
S&P (a)
A
Moody’s (b)
A1
Fitch (c)
A
__________
(a)    On April 16, 2020, S&P affirmed A rating.
(b)    On December 20, 2019, Moody’s affirmed A1 rating.
(c)    On August 20, 2020, Fitch affirmed A rating.


Capital Requirements

Capital Expenditures
ActualPlannedPlannedPlannedPlannedPlanned
Capital Expenditures by Segment
Nine Months Ended September 30, 2020 (a)
2020 (b)
2021202220232024
(in millions)
Electric Utilities$179 $262 $240 $180 $143 $156 
Gas Utilities329 434 363 334 327 317 
Power Generation12 10 10 
Mining
Corporate and Other10 19 11 12 13 
$536 $733 $633 $537 $497 $499 
__________
(a)    Expenditures for the nine months ended September 30, 2020 include the impact of accruals for property, plant and equipment.
(b)    Includes actual capital expenditures for the nine months ended September 30, 2020.

We are monitoring supply chains, including lead times for key materials and supplies, availability of resources, and statuses of large capital projects. To date, there have been limited impacts from COVID-19 on supply chains including the availability of supplies and materials and lead times. Capital projects are ongoing without material disruption to schedules. Our third party resources continue to support our business plans without disruption. Contingency plans are ready to be executed if significant disruption to supply chain occurs; however, we currently do not anticipate a significant impact from COVID-19 on our capital investment plan for 2020.

Contractual Obligations

There have been no significant changes in contractual obligations from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2019 Annual Report on Form 10-K except for the items described in Note 13 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Off-Balance Sheet Commitments

There have been no significant changes to off-balance sheet commitments from those previously disclosed in Item 7 of our 2019 Annual Report on Form 10-K filed with the SEC except for the items described in Note 7 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

New Accounting Pronouncements

Other than the pronouncements reported in our 2019 Annual Report on Form 10-K filed with the SEC 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.

58


FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements as defined by the SEC. Forward-looking statements are all statements other than statements of historical fact, including, without limitation, those statements that are identified by the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts” and similar expressions and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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

Any forward-looking statement contained in this document speaks only as of the date the statement was made. The Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement was made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, such as the COVID-19 pandemic, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements described in our 2019 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our 2019 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.


ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information regarding our quantitative and qualitative disclosures about market risk is disclosed in Item 7A of our Annual Report on Form 10-K. See Note 9 of the Notes to Condensed Consolidated Financial Statements for updates to market risks during the nine months ended September 30, 2020.


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, 2020. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at September 30, 2020.

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, 2020, 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. Although we have altered some work routines due to the COVID-19 pandemic, the changes in our work environment (i.e. remote work arrangements) have not materially impacted our internal controls over financial reporting and have not adversely affected the Company’s ability to maintain operations, including financial reporting systems, ICFR, and disclosure controls and procedures.


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PART II.    OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS

For information regarding legal proceedings, see Note 19 in Item 8 of our 2019 Annual Report on Form 10-K and Note 13 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 13 is incorporated by reference into this item.

ITEM 1A.RISK FACTORS

There are no material changes to the risk factors previously disclosed in Item 1A of Part I in our 2019 Annual Report on Form 10-K filed with the SEC except as shown below:

Our business, results of operations, financial condition and cash flows could be adversely affected by the recent coronavirus (COVID-19) pandemic.

We have responded to the global pandemic of COVID-19 by taking steps to mitigate the potential risks to us posed by its spread.

For the nine months ended September 30, 2020, the COVID-19 pandemic had a limited financial impact on our business, operations, financial condition and cash flows. In particular, we experienced:

Increased allowance for credit losses and bad debt expense due to anticipated customer non-payment as a result of suspended disconnections;
Increased costs due to sequestration of mission-critical and essential employees;
Lower commercial and certain transport volumes partially offset by higher electric and natural gas residential usage;
Reduced availability of our employees;
Increased costs for personal protection equipment and cleaning supplies;
Limited cash flow impacts from delayed payments from residential, commercial and industrial customers;
Minimal disruptions receiving the materials and supplies necessary to maintain operations and continue executing our capital investment plan;
Minimal impacts to the availability of our third-party resources;
Minimal decline in the funded status of our pension plan;
Minimal interest expense increase due to disruptions in the Commercial Paper markets; and
Reduced training, travel, employee, outside services and employee related expenses.

Should the COVID-19 pandemic continue for a prolonged period or impact the areas we serve more significantly than it has to date, our business, operations, financial condition and cash flows could be impacted in more significant ways. In addition to exacerbating the impacts described above, we could experience:

Adverse impacts on our strategic business plans, growth strategy and capital investment plans;
Increased adverse impacts to electricity and natural gas demand from our customers, particularly from commercial and industrial customers;
Further reduction in the availability of our employees and third-party resources;
Increased costs as a result of our emergency measures;
Increased allowance for credit losses and bad debt expense as a result of delayed or non-payment from our customers, both of which could be magnified by Federal or state government legislation that requires us to extend suspensions of disconnections for non-payment;
Delays and disruptions in the availability, timely delivery and cost of materials and components used in our operations;
Disruptions in the commercial operation dates of certain projects impacting qualification criteria for certain tax credits and triggering potential damages under our power purchase agreements;
Deterioration of the credit quality of our counterparties, including gas commodity contract counterparties, power purchase agreement counterparties, contractors or retail customers, that could result in credit losses;
Impairment of goodwill or long-lived assets;
Adverse impacts on our ability to develop, construct and operate facilities;
Inability to meet the requirements of the covenants in our existing credit facilities, including covenants regarding Consolidated Indebtedness to Capitalization Ratio;
Deterioration in our financial metrics or the business environment that adversely impacts our credit ratings;
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Delay in the permitting process of certain development projects, affecting the timing of final investment decisions and start dates of construction;
Adverse impact on our liquidity position and cost of and ability to access funds from financial institutions and capital markets;
Delays in our ability to change rates through regulatory proceedings; and
Other risks that impact us, such as the risks described in the “Risk Factors” section of our 2019 Annual Report on Form 10-K and our ability to meet our financial obligations.

To date, we have experienced limited impacts to our results of operations, financial condition, cash flows or business plans. However, the situation remains fluid and it is difficult to predict with certainty the potential impact of COVID-19 on our business, results of operations, financial condition and cash flows.

ITEM 4.    MINE SAFETY DISCLOSURES

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

ITEM 6.    EXHIBITS
Exhibit NumberDescription
Exhibit 3.1*
Exhibit 3.2*
Exhibit 4.1*
Exhibit 4.2*
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Exhibit 4.3*
Exhibit 4.4*
Exhibit 10.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2
Exhibit 95
101.INSXBRL 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.SCHXBRL Taxonomy Extension Schema Document
101.CALXBRL Taxonomy Extension Calculation Linkbase Document
101.DEFXBRL Taxonomy Extension Definition Linkbase Document
101.LABXBRL Taxonomy Extension Label Linkbase Document
101.PREXBRL Taxonomy Extension Presentation Linkbase Document
104Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)
__________
*    Previously filed as part of the filing indicated and incorporated by reference herein.

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SIGNATURES


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

BLACK HILLS CORPORATION
/s/ Linden R. Evans
Linden R. Evans, President and
  Chief Executive Officer
/s/ Richard W. Kinzley
Richard W. Kinzley, Senior Vice President and
  Chief Financial Officer
Dated:November 3, 2020

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