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BKH Black Hills

Filed: 5 Nov 19, 1:22pm

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, 2019
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 Number001-31303
Black Hills Corporation
Incorporated inSouth DakotaIRS Identification Number46-0458824
       
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.
 Yesx 
No o
 

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).
 Yesx 
No o
 

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 Filerx Accelerated Filer 
       
 Non-accelerated Filer Smaller 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 x
 
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, 2019
Common stock, $1.00 par value61,454,071
shares




TABLE OF CONTENTS
   Page
 
    
    
Item 1. 
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
Item 2. 
Item 3. 
Item 4. 
    
    
Item 1. 
Item 4. 
Item 6. 
    
  


2



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., a direct, wholly-owned subsidiary of Black Hills Gas Inc.
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 Electric GenerationBlack Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills EnergyThe name used to conduct the business of our utility companies
Black Hills PowerBlack Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
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
Busch Ranch I
Busch Ranch Wind Farm is a 29 MW wind farm near Pueblo, Colorado, jointly owned
by Colorado Electric and Black Hills Electric Generation. Colorado Electric and Black
Hills Electric Generation each have a 50% ownership interest in the wind farm.

Busch Ranch IIBusch Ranch II wind project will be a 60 MW wind farm near Pueblo, Colorado, built by Black Hills Electric Generation to provide wind energy to Colorado Electric through a 25-year power purchase agreement.
CAPPCustomer Appliance Protection Plan
Cheyenne LightCheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy and providing electric service)
Choice Gas ProgramThe unbundling of the natural gas service from the distribution component, which opens up the gas supply for competition allowing customers to choose from different natural gas suppliers. Black Hills Gas Distribution and Wyoming Gas distribute the gas and Black Hills Energy Services, Wyoming Gas and Black Hills Gas Distribution are Choice Gas suppliers.
CIACContribution In Aid of Construction
City of GilletteGillette, Wyoming
City of CheyenneCheyenne, Wyoming
Chief Operating Decision Maker (CODM)Chief Executive Officer
Colorado Electric
Black Hills Colorado Electric, LLC, an indirect, wholly-owned subsidiary of Black Hills
Utility Holdings (doing business as Black Hills Energy)
Colorado GasBlack Hills Colorado Gas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
Colorado IPPBlack Hills Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Electric Generation
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 of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
CPCNCertificate of Public Convenience and Necessity
CP ProgramCommercial Paper Program
CPUCColorado Public Utilities Commission
CTCombustion turbine
CVACredit Valuation Adjustment
Dodd-FrankDodd-Frank Wall Street Reform and Consumer Protection Act

3



DthDekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
Equity UnitEach Equity Unit had a stated amount of $50, consisting of a purchase contract issued by BHC to purchase shares of BHC common stock and a 1/20, or 5% undivided beneficial ownership interest in $1,000 principal amount of BHC RSNs that were formerly due 2028. On November 1, 2018, we completed settlement of the stock purchase contracts that are components of the Equity Units issued in November 2015.
FASBFinancial Accounting Standards Board
FERCUnited States Federal Energy Regulatory Commission
FitchFitch Ratings
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 of weather 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.
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 (doing business as Black Hills Energy)
MMBtuMillion British thermal units
Moody’sMoody’s Investors Service, Inc.
MWMegawatts
MWhMegawatt-hours
Nebraska GasBlack Hills Nebraska Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
NPSCNebraska Public Service Commission
PPAPower Purchase Agreement
Pueblo Airport Generation Station
Two 100 MW combined cycle gas-fired power generation plants owned by Colorado IPP and located at a site shared with Colorado Electric. The plants commenced operation on January 1, 2012.

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.
RSNsRemarketable junior subordinated notes, issued on November 23, 2015 and retired on August 17, 2018.
SDPUCSouth Dakota Public Utilities Commission
SECU. S. Securities and Exchange Commission
S&PStandard and Poor’s, a division of The McGraw-Hill Companies, Inc.
South Dakota ElectricBlack Hills Power, which includes operations in South Dakota, Wyoming and Montana
SSIRSystem Safety and Integrity Rider
TCJATax Cuts and Jobs Act enacted on December 22, 2017
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.
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
Wyodak PlantWyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, owned 80% by PacifiCorp and 20% by Black Hills Energy South Dakota. Our WRDC mine supplies all of the fuel for the plant.
Wyoming Electric
Includes Cheyenne Light’s electric utility operations

Wyoming GasBlack Hills Wyoming Gas, LLC, an indirect and wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)

4



 

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)Three Months Ended September 30,Nine Months Ended September 30,
 2019201820192018
 (in thousands, except per share amounts)
     
Revenue$325,548
$321,979
$1,257,246
$1,253,072
     
Operating expenses:    
Fuel, purchased power and cost of natural gas sold73,090
80,244
411,695
432,544
Operations and maintenance117,037
115,699
366,907
352,092
Depreciation, depletion and amortization51,884
49,046
154,507
146,345
Taxes - property and production12,986
11,905
39,454
39,181
Total operating expenses254,997
256,894
972,563
970,162
     
Operating income70,551
65,085
284,683
282,910
     
Other income (expense):    
Interest charges -    
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)(36,200)(36,380)(108,232)(107,183)
Allowance for funds used during construction - borrowed2,200
701
4,555
1,345
Interest income513
382
1,208
1,012
Allowance for funds used during construction - equity311
193
486
503
Impairment of investment(19,741)
(19,741)
Other income (expense), net269
(703)(431)(2,426)
Total other income (expense)(52,648)(35,807)(122,155)(106,749)
 



Income before income taxes17,903
29,278
162,528
176,161
Income tax benefit (expense)(2,508)(7,477)(22,078)11,784
Income from continuing operations15,395
21,801
140,450
187,945
Net (loss) from discontinued operations
(857)
(5,627)
Net income15,395
20,944
140,450
182,318
Net income attributable to noncontrolling interest(3,655)(3,994)(10,319)(10,447)
Net income available for common stock$11,740
$16,950
$130,131
$171,871
     
Amounts attributable to common shareholders:    
Net income from continuing operations$11,740
$17,807
$130,131
$177,498
Net (loss) from discontinued operations
(857)
(5,627)
Net income available for common stock$11,740
$16,950
$130,131
$171,871
     
Earnings (loss) per share of common stock, Basic -    
Earnings from continuing operations$0.19
$0.33
$2.15
$3.33
(Loss) from discontinued operations
(0.02)
(0.10)
Total earnings per share of common stock, Basic$0.19
$0.32
$2.15
$3.22
     
Earnings (loss) per share of common stock, Diluted -    
Earnings from continuing operations$0.19
$0.32
$2.15
$3.26
(Loss) from discontinued operations
(0.02)
(0.10)
Total earnings per share of common stock, Diluted$0.19
$0.31
$2.15
$3.15
     
Weighted average common shares outstanding:    
Basic60,976
53,364
60,458
53,346
Diluted61,104
54,819
60,578
54,508


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

5




BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)Three Months Ended
September 30,
Nine Months Ended
September 30,
 2019201820192018
 (in thousands)
     
Net income$15,395
$20,944
$140,450
$182,318
     
Other comprehensive income (loss), net of tax:    
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $3, $10, $13 and $29, respectively)(16)(34)(45)(104)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax of $(92), $(138), $(197), and $(409), respectively)(9)483
327
1,456
Derivative instruments designated as cash flow hedges:    
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(165), $(152), $(500), and $(456), respectively)548
560
1,639
1,682
Net unrealized gains (losses) on commodity derivatives (net of tax of $35, $0, $100 and $51, respectively)(115)30
(334)(168)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $(5), $3, $142 and $(187), respectively)124
21
(366)615
Other comprehensive income, net of tax532
1,060
1,221
3,481
     
Comprehensive income15,927
22,004
141,671
185,799
Less: comprehensive income attributable to noncontrolling interest(3,655)(3,994)(10,319)(10,447)
Comprehensive income available for common stock$12,272
$18,010
$131,352
$175,352

See Note 13 for additional disclosures.

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

6



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)As of
 September 30, 2019 December 31, 2018
 (in thousands)
ASSETS   
Current assets:   
Cash and cash equivalents$13,087
 $20,776
Restricted cash3,688
 3,369
Accounts receivable, net148,989
 269,153
Materials, supplies and fuel123,002
 117,299
Derivative assets, current412
 1,500
Income tax receivable, net12,931
 12,978
Regulatory assets, current46,206
 48,776
Other current assets29,106
 29,982
Total current assets377,421
 503,833
    
Investments21,583
 41,013
    
Property, plant and equipment6,567,229
 6,000,015
Less: accumulated depreciation and depletion(1,243,794) (1,145,136)
Total property, plant and equipment, net5,323,435
 4,854,879
    
Other assets:   
Goodwill1,299,454
 1,299,454
Intangible assets, net13,566
 14,337
Regulatory assets, non-current214,152
 235,459
Other assets, non-current25,339
 14,352
Total other assets, non-current1,552,511
 1,563,602
    
TOTAL ASSETS$7,274,950
 $6,963,327

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

7



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
(unaudited)As of
 September 30, 2019 December 31, 2018
 (in thousands, except share amounts)
LIABILITIES AND TOTAL EQUITY   
Current liabilities:   
Accounts payable$145,085
 $210,609
Accrued liabilities217,832
 215,501
Derivative liabilities, current2,396
 947
Regulatory liabilities, current25,168
 29,810
Notes payable294,900
 185,620
Current maturities of long-term debt5,743
 5,743
Total current liabilities691,124
 648,230
    
Long-term debt3,049,235
 2,950,835
    
Deferred credits and other liabilities:   
Deferred income tax liabilities, net347,952
 311,331
Regulatory liabilities, non-current498,773
 510,984
Benefit plan liabilities134,150
 145,147
Other deferred credits and other liabilities120,820
 109,377
Total deferred credits and other liabilities1,101,695
 1,076,839
    
Commitments and contingencies (See Notes 8, 10, 15, 16)


 

    
Equity:   
Stockholders’ equity —   
Common stock $1 par value; 100,000,000 shares authorized; issued 61,480,640 and 60,048,567 shares, respectively61,481
 60,049
Additional paid-in capital1,553,190
 1,450,569
Retained earnings742,138
 700,396
Treasury stock, at cost – 26,572 and 44,253 shares, respectively(1,636) (2,510)
Accumulated other comprehensive income (loss)(25,695) (26,916)
Total stockholders’ equity2,329,478
 2,181,588
Noncontrolling interest103,418
 105,835
Total equity2,432,896
 2,287,423
    
TOTAL LIABILITIES AND TOTAL EQUITY$7,274,950
 $6,963,327

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

8



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)Nine Months Ended September 30,
 20192018
Operating activities:(in thousands)
Net income$140,450
$182,318
Loss from discontinued operations, net of tax
5,627
Income from continuing operations140,450
187,945
Adjustments to reconcile net income to net cash provided by operating activities:  
Depreciation, depletion and amortization154,507
146,345
Deferred financing cost amortization6,326
5,682
Impairment of investment19,741

Stock compensation8,332
7,544
Deferred income taxes24,381
(14,396)
Employee benefit plans7,965
10,641
Other adjustments, net9,192
7,668
Changes in certain operating assets and liabilities:  
Materials, supplies and fuel(4,126)(8,380)
Accounts receivable, unbilled revenues and other operating assets115,325
72,061
Accounts payable and other operating liabilities(83,436)(86,604)
Regulatory assets - current12,455
41,655
Regulatory liabilities - current(15,644)21,416
Contributions to defined benefit pension plans(12,700)(12,700)
Other operating activities, net3,307
2,007
Net cash provided by operating activities of continuing operations386,075
380,884
Net cash provided by (used in) operating activities of discontinued operations
(2,162)
Net cash provided by operating activities386,075
378,722
   
Investing activities:  
Property, plant and equipment additions(592,537)(278,132)
Purchase of investment
(24,429)
Other investing activities(735)2,766
Net cash provided by (used in) investing activities of continuing operations(593,272)(299,795)
Net cash provided by investing activities of discontinued operations
18,024
Net cash provided by (used in) investing activities(593,272)(281,771)
   
Financing activities:  
Dividends paid on common stock(91,779)(76,309)
Common stock issued101,361
1,079
Net (payments) borrowings of short-term debt109,280
(99,200)
Long-term debt - issuances400,000
700,000
Long-term debt - repayments(304,307)(603,307)
Distributions to noncontrolling interest(12,736)(13,755)
Other financing activities(1,992)(10,457)
Net cash provided by (used in) financing activities199,827
(101,949)
Net change in cash, cash equivalents and restricted cash(7,370)(4,998)
Cash, cash equivalents and restricted cash at beginning of period24,145
18,240
Cash, cash equivalents and restricted cash at end of period$16,775
$13,242


See Note 14 for supplemental disclosure of cash flow information.

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

9



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, 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
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 (loss), 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
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 (loss) available for common stock




11,740

3,655
15,395
Other comprehensive income (loss), 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
Issuance of common stock389,237
390


29,611



30,001
Issuance costs



(398)


(398)
Implementation of ASU 2016-02 Leases




3


3
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
          


10



 Common StockTreasury Stock     
(in thousands except share amounts)SharesValueSharesValueAdditional Paid in CapitalRetained EarningsAOCINon controlling InterestTotal
December 31, 201753,579,986
$53,580
39,064
$(2,306)$1,150,285
$548,617
$(41,202)$111,232
$1,820,206
Net income available for common stock




133,004

3,630
136,634
Other comprehensive income (loss), net of tax





1,260

1,260
Dividends on common stock ($0.475 per share)




(25,444)

(25,444)
Share-based compensation64,770
65
14,895
(743)1,433



755
Dividend reinvestment and stock purchase plan4,061
4


215



219
Other stock transactions




(16)18

2
Distributions to noncontrolling interest






(5,648)(5,648)
March 31, 201853,648,817
$53,649
53,959
$(3,049)$1,151,933
$656,161
$(39,924)$109,214
$1,927,984
Net income available for common stock




21,917

2,823
24,740
Other comprehensive income (loss), net of tax





1,161

1,161
Dividends on common stock ($0.475 per share)




(25,435)

(25,435)
Share-based compensation13,033
13
11,022
(593)3,019



2,439
Other stock transactions



(5)(1)

(6)
Distributions to noncontrolling interest






(4,350)(4,350)
June 30, 201853,661,850
$53,662
64,981
$(3,642)$1,154,947
$652,642
$(38,763)$107,687
$1,926,533
Net income (loss) available for common stock




16,950

3,994
20,944
Other comprehensive income (loss), net of tax





1,060

1,060
Dividends on common stock ($0.475 per share)




(25,430)

(25,430)
Share-based compensation13

7,934
(430)2,107



1,677
Dividend reinvestment and stock purchase plan



1



1
Other stock transactions



159
(8)

151
Distributions to noncontrolling interest






(3,757)(3,757)
September 30, 201853,661,863
$53,662
72,915
$(4,072)$1,157,214
$644,154
$(37,703)$107,924
$1,921,179
          


11




BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 2018 Annual Report on Form 10-K)

(1)    MANAGEMENT’S STATEMENT

The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company”, “us”, “we” or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Condensed Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2018 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.

Effective January 1, 2019, we changed our measure of segment performance to adjusted operating income, which impacted our segment disclosures for all periods presented. See Note 3 for more information.

On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture in 2018. The Oil and Gas segment assets and liabilities were classified as held for sale and the results of operations were shown in income (loss) from discontinued operations, except for certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. At the time the assets were classified as held for sale, depreciation, depletion and amortization expenses were no longer recorded. Unless otherwise noted, the amounts presented in the accompanying notes to the Condensed Consolidated Financial Statements relate to the Company’s continuing operations. See Note 17 and Note 21 for more information on discontinued operations.

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, 2019 and December 31, 2018 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, 2019 and September 30, 2018, and our financial condition as of September 30, 2019 and December 31, 2018 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.

Recently Issued Accounting Standards

Simplifying the Test for Goodwill Impairment, 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. The new standard is effective for interim and annual reporting periods beginning after December 1, 2019, applied on a prospective basis with early adoption permitted. We do not anticipate the adoption of this guidance to have any impact on our financial position, results of operations or cash flows.

12




Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, ASU 2018-19

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 ASU 2018-19 in November 2018. 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. It is effective for interim and annual reporting periods beginning after December 15, 2019, and will be applied on a modified-retrospective basis through a cumulative-effect adjustment to retained earnings as of January 1, 2020. We do not anticipate the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows.

Recently Adopted Accounting Standards

Leases, ASU 2016-02

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) to increase transparency and comparability among organizations by requiring the recognition of right-of-use assets and lease liabilities on the balance sheet for most leases, whereas previously only financing-type lease liabilities (capital leases) were recognized on the balance sheet. Under the new standard, disclosures are required to meet the objective of enabling users of financial statements to assess the amount, timing and uncertainty of cash flows arising from leases.

We adopted the standard effective January 1, 2019. We elected not to recast comparative periods coinciding with the new lease standard transition and will report these comparative periods as presented under previous lease guidance. In addition, we elected the package of practical expedients permitted under the transition guidance with the new standard, which among other things, allowed us to carry forward the historical lease classification. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for existing land easement agreements.

Adoption of the new standard resulted in the recording of an operating lease right-of-use asset of $3.1 million, an operating lease obligation liability of $3.2 million, and an accrued rent receivable of $4.5 million, as of January 1, 2019. The cumulative effect of the adoption, net of tax impact, was $3.4 million, which was recorded as an adjustment to retained earnings at January 1, 2019.

Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities, ASU 2017-12

Effective January 1, 2019, we adopted ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. This standard better aligns risk management activities and financial reporting for hedging relationships, simplifies hedge accounting requirements and improves disclosures of hedging arrangements. The adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.




13




(2)    REVENUE

Revenue Recognition

As of January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and its related amendments (collectively known as ASC 606). Revenue is recognized in an amount that reflects the consideration we expect to receive in exchange for goods or services, when control of the promised goods or services is transferred to our customers. 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 reporting segments, for the three and nine months ended September 30, 2019 and 2018. Sales tax and other similar taxes are excluded from revenues.

Three Months Ended September 30, 2019 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer types:(in thousands)
Retail$162,214
$89,810
$
$14,992
$(8,146)$258,870
Transportation
29,019


(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
       

Three Months Ended September 30, 2018 Electric Utilities Gas Utilities
 Power Generation (a)
 Mining
Inter-company Revenues (a)
Total
Customer Types:      
Retail$157,049
$88,559
$
$16,751
$(7,941)$254,418
Transportation
30,079


(267)29,812
Wholesale8,255

15,373

(13,935)9,693
Market - off-system sales9,059
140


(1,349)7,850
Transmission/Other10,196
11,887


(3,693)18,390
Revenue from contracts with customers$184,559
$130,665
$15,373
$16,751
$(27,185)$320,163
Other revenues231
1,011
9,118
550
(9,094)1,816
Total Revenues$184,790
$131,676
$24,491
$17,301
$(36,279)$321,979
       
Timing of Revenue Recognition:      
Services transferred at a point in time$
$
$
$16,751
$(7,942)$8,809
Services transferred over time184,559
130,665
15,373

(19,243)311,354
Revenue from contracts with customers$184,559
$130,665
$15,373
$16,751
$(27,185)$320,163
       

14



Nine Months Ended September 30, 2019 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer types:(in thousands)
Retail$455,409
$567,715
$
$43,249
$(23,315)$1,043,058
Transportation
102,159


(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
       


Nine Months Ended September 30, 2018 Electric Utilities Gas Utilities
 Power Generation (a)
 Mining
Inter-company Revenues (a)
Total
Customer Types:      
Retail$449,482
$565,816
$
$49,653
$(23,761)$1,041,190
Transportation
100,760


(977)99,783
Wholesale25,497

43,744

(39,457)29,784
Market - off-system sales18,142
728


(5,531)13,339
Transmission/Other36,622
36,230


(10,967)61,885
Revenue from contracts with customers$529,743
$703,534
$43,744
$49,653
$(80,693)$1,245,981
Other revenues2,218
3,106
27,429
1,675
(27,337)7,091
Total Revenues$531,961
$706,640
$71,173
$51,328
$(108,030)$1,253,072
       
Timing of Revenue Recognition:      
Services transferred at a point in time$
$
$
$49,653
$(23,761)$25,892
Services transferred over time529,743
703,534
43,744

(56,932)1,220,089
Revenue from contracts with customers$529,743
$703,534
$43,744
$49,653
$(80,693)$1,245,981
       

(a)Due to the changes in our segment disclosures discussed in Note 3, Power Generation Wholesale revenue was revised for the three and nine months ended September 30, 2018, which resulted in an increase of $0.9 million and $2.6 million, respectively. The changes to Power Generation Wholesale revenue were offset by changes to eliminations in Inter-company Revenues within Corporate and Other and there was no impact to our consolidated Total Revenues.

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. We do not typically incur costs that would be capitalized to obtain or fulfill a revenue contract.


15



(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.

Accounting standards for presentation of segments require an approach based on the way we organize the segments for making operating decisions and how the chief operating decision maker (CODM) assesses performance.  Effective January 1, 2019, we concluded that adjusted operating income, instead of net income available for common stock which was used previously, is the most relevant metric for measuring segment performance. The change to our segment performance measure resulted in a revision of the Company’s segment disclosures for all periods to report adjusted operating income as the measure of segment performance.

Prior to January 1, 2019, operating income for the Electric Utilities and Power Generation segments and Corporate and Other included the impacts of finance lease accounting relating to Colorado Electric’s PPA with Colorado IPP. This PPA provides 200 MW of energy and capacity to Colorado Electric from Colorado IPP’s combined-cycle turbines and expires on December 31, 2031. Finance lease accounting required us to de-recognize the asset from Colorado IPP (Power Generation segment), which legally owns the asset, and recognize it at Colorado Electric (Electric Utilities segment).

The CODM assesses the performance of our segments using adjusted operating income, which recognizes intersegment revenues, costs, and assets for Colorado Electric’s PPA with Colorado IPP on an accrual basis rather than as a finance lease. Effective January 1, 2019, we changed how we account for this PPA at the segment level, which impacts disclosures for all periods for revenues, fuel and purchased power cost, operating income and total assets for the Electric Utilities and Power Generation segments as well as Corporate and Other. There were no revisions to Gas Utilities and Mining segments and this change had no effect on our consolidated revenues, fuel and purchased power cost, operating income or total assets.

Segment information and Corporate and Other is as follows (in thousands):
        
Three Months Ended September 30, 2019External Operating Revenue Inter-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
        
Three Months Ended September 30, 2018External Operating Revenue Inter-company Operating Revenue  Total Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:       
Electric Utilities$179,527
$231
 $5,032
$
 $184,790
Gas Utilities130,390
1,011
 275

 131,676
Power Generation (a)
1,437
348
 13,936
8,770
 24,491
Mining8,809
226
 7,942
324
 17,301
Inter-company eliminations (a)


 (27,185)(9,094) (36,279)
Total$320,163
$1,816
 $
$
 $321,979

16



Nine Months Ended September 30, 2019
External Operating
Revenue
 Inter-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
        
Nine Months Ended September 30, 2018External Operating Revenue Inter-company Operating Revenue  Total Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:       
Electric Utilities$513,270
$2,218
 $16,473
$
 $531,961
Gas Utilities702,532
3,106
 1,002

 706,640
Power Generation (a)
4,287
1,066
 39,457
26,363
 71,173
Mining25,892
701
 23,761
974
 51,328
Inter-company eliminations (a)


 (80,693)(27,337) (108,030)
Total$1,245,981
$7,091
 $
$
 $1,253,072


(a)Due to the changes in our segment disclosures, Power Generation Inter-company Operating Revenue for Contract Customers was revised for the three and nine months ended September 30, 2018 which resulted in an increase of $0.9 million and $2.6 million, respectively. The changes to Power Generation were offset by changes to Inter-company eliminations within Corporate and Other and there was no impact on our consolidated Total revenues.

17



     
 Three Months Ended September 30,Nine Months Ended September 30,
 2019201820192018
Adjusted operating income:    
Electric Utilities (a)
$50,653
$43,393
$125,219
$123,073
Gas Utilities4,736
4,240
116,607
116,168
Power Generation (a)
11,822
13,079
33,945
33,731
Mining3,374
4,551
9,351
12,647
Corporate and Other (a)
(34)(178)(439)(2,709)
Operating income70,551
65,085
284,683
282,910
     
Interest expense, net(33,487)(35,297)(102,469)(104,826)
Impairment of investment(19,741)
(19,741)
Other income (expense), net580
(510)55
(1,923)
Income tax benefit (expense) (b)
(2,508)(7,477)(22,078)11,784
Income from continuing operations15,395
21,801
140,450
187,945
Net (loss) from discontinued operations
(857)
(5,627)
Net income15,395
20,944
140,450
182,318
Net income attributable to noncontrolling interest(3,655)(3,994)(10,319)(10,447)
Net income available for common stock$11,740
$16,950
$130,131
$171,871
___________
(a)Due to the changes in our segment disclosures, Adjusted operating income was revised for the three and nine months ended September 30, 2018, which resulted in an increase (decrease) as follows (in millions):
SegmentThree Months Ended September 30, 2018Nine Months Ended September 30, 2018
Electric Utilities$1.6
$4.8
Power Generation(1.4)(4.4)
Corporate and Other(0.2)(0.4)
 $
$


(b)
Income tax benefit (expense) for the nine months ended September 30, 2018 included a $49 million tax benefit resulting from legal entity restructuring. See Note 18 for more information.


Segment information 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, 2019 December 31, 2018
Segment:   
Electric Utilities (a)
$2,810,108
 $2,707,695
Gas Utilities3,797,941
 3,623,475
Power Generation (a)
414,526
 342,085
Mining78,073
 80,594
Corporate and Other174,302
 209,478
Total assets$7,274,950
 $6,963,327

___________
(a)Due to the changes in our segment disclosures, Electric Utilities and Power Generation Total assets were revised as of December 31, 2018 which resulted in an increase (decrease) of ($188) million and $188 million, respectively. There was no impact on our consolidated Total assets.


18



(4)    ACCOUNTS RECEIVABLE

Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 AccountsUnbilledLess Allowance forAccounts
September 30, 2019Receivable, TradeRevenue Doubtful AccountsReceivable, net
Electric Utilities$39,151
$31,843
$(500)$70,494
Gas Utilities46,265
24,091
(2,490)67,866
Power Generation2,733


2,733
Mining1,804


1,804
Corporate6,261

(169)6,092
Total$96,214
$55,934
$(3,159)$148,989

 AccountsUnbilledLess Allowance forAccounts
December 31, 2018Receivable, TradeRevenue Doubtful AccountsReceivable, net
Electric Utilities$39,721
$35,125
$(448)$74,398
Gas Utilities96,123
90,521
(2,592)184,052
Power Generation1,876


1,876
Mining3,988


3,988
Corporate5,008

(169)4,839
Total$146,716
$125,646
$(3,209)$269,153

     



19



(5)    REGULATORY ACCOUNTING

We had the following regulatory assets and liabilities (in thousands) as of:
 September 30, 2019December 31, 2018
Regulatory assets  
Deferred energy and fuel cost adjustments (a)
$31,832
$29,661
Deferred gas cost adjustments (a)
3,899
3,362
Gas price derivatives (a)
4,296
6,201
Deferred taxes on AFUDC (b)
7,691
7,841
Employee benefit plans (c)
107,921
110,524
Environmental (a)
917
959
Loss on reacquired debt (a)
19,710
21,001
Renewable energy standard adjustment (a)
2,871
1,722
Deferred taxes on flow through accounting (c)
37,609
31,044
Decommissioning costs (b)
11,206
11,700
Gas supply contract termination (a)
9,953
14,310
Other regulatory assets (a)
22,453
45,910
Total regulatory assets260,358
284,235
Less current regulatory assets(46,206)(48,776)
Regulatory assets, non-current$214,152
$235,459
   
Regulatory liabilities  
Deferred energy and gas costs (a)
$9,919
$6,991
Employee benefit plan costs and related deferred taxes (c)
42,737
42,533
Cost of removal (a)
162,169
150,123
Excess deferred income taxes (c)
286,587
310,562
TCJA revenue reserve2,770
18,032
Other regulatory liabilities (c)
19,759
12,553
Total regulatory liabilities523,941
540,794
Less current regulatory liabilities(25,168)(29,810)
Regulatory liabilities, non-current$498,773
$510,984
__________
(a)We are allowed 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.

Regulatory Matters

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 2018 Annual Report on Form 10-K.


20



Regulatory Activity

Wyoming Gas

On June 13, 2019, we received approval from the WPSC to consolidate our Wyoming gas utility operations into a new utility entity.  The Wyoming portion of Black Hills Gas Distribution, LLC, Cheyenne Light’s natural gas utility operations (Cheyenne Gas and Northeast Wyoming), and Wyoming Gas (Northwest Wyoming) were combined into a new company called Black Hills Wyoming Gas, LLC.  On June 3, 2019, Wyoming Gas filed a rate review application with the WPSC to consolidate the rates, tariffs and services of its 4 existing gas distribution territories in Wyoming. The rate review requests $16 million in new revenue to recover investments in safety, reliability and system integrity. Wyoming Gas is also requesting a new rider mechanism to recover future safety and integrity investments in its system. A settlement was recently reached with the intervening parties in the rate review filing and filed with the WPSC on November 1, 2019. The stipulation and agreement are subject to review and approval by the WPSC, with a decision expected by the end of 2019.

South Dakota Electric and Wyoming Electric

South Dakota Electric and Wyoming Electric received approvals for the Renewable Ready Service Tariffs and related jointly-filed CPCN to construct the $57 million, 40 MW Corriedale Wind Energy Project. The wind project will be jointly owned by the 2 electric utilities to deliver renewable energy for large commercial, industrial and governmental agency customers. The project is expected to be in service by the end of 2020. In September 2019, the customer subscription period was completed with customer interest fulfilling the 40 MW of available energy. On November 1, 2019, South Dakota Electric filed with the SDPUC an amendment seeking approval to increase the generating capacity under the tariff for the South Dakota portion by 12.5 MW to a total of 32.5 MW.

Nebraska

On October 29, 2019, Nebraska Gas received approval from the NPSC to merge its 2 gas distribution companies in Nebraska. A rate review is expected to be filed by mid-year 2020 to consolidate the rates, tariffs and services of its 2 existing gas distribution companies.

Kansas

On June 25, 2019, Kansas Gas received approval from the Kansas Corporation Commission for an annual increase in revenue of $1.4 million, effective July 1, 2019, based on updates to the Gas System Reliability Surcharge Rider.

Wyoming Electric

On April 30, 2019, the WPSC approved Wyoming Electric’s application for a new Blockchain Interruptible Service Tariff. The utility has partnered with the economic development organization for City of Cheyenne and Laramie County to actively recruit blockchain customers to the state. This tariff is complementary to recently enacted Wyoming legislation supporting the development of blockchain within the state.

Colorado

On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate rates, tariffs, and services of its 2 existing gas distribution territories in Colorado. The rate review requests $2.5 million in new revenue to recover investments in safety, reliability and system integrity. Colorado Gas is also requesting a new rider mechanism to recover future safety and integrity investments in its system. A decision from the CPUC is expected by March 2020.



21



(6)    MATERIALS, SUPPLIES AND FUEL

The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 September 30, 2019 December 31, 2018
Materials and supplies$81,382
 $75,081
Fuel - Electric Utilities2,535
 2,850
Natural gas in storage held for distribution39,085
 39,368
Total materials, supplies and fuel$123,002
 $117,299




(7)    EARNINGS PER SHARE

A reconciliation of share amounts used to compute Earnings (loss) 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,
 20192018 20192018
      
Net income available for common stock$11,740
$16,950
 $130,131
$171,871
      
Weighted average shares - basic60,976
53,364
 60,458
53,346
Dilutive effect of:     
Equity Units (a)

1,344
 
1,060
Equity compensation128
111
 120
102
Weighted average shares - diluted61,104
54,819
 60,578
54,508

__________
(a)Calculated using the treasury stock method. On November 1, 2018, we completed settlement of the stock purchase contracts that were components of the Equity Units issued in November 2015.

The following outstanding securities were excluded in the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands):
 Three Months Ended September 30, Nine Months Ended September 30,
 20192018 20192018
      
Equity compensation2
12
 4
15
Restricted Stock

 1

Anti-dilutive shares2
12
 5
15



(8)    NOTES PAYABLE, CURRENT MATURITIES AND DEBT

We had the following notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 September 30, 2019December 31, 2018
 Balance OutstandingLetters of CreditBalance OutstandingLetters of Credit
Revolving Credit Facility$50,000
$18,313
$
$22,311
CP Program244,900

185,620

Total$294,900
$18,313
$185,620
$22,311


22




Our $750 million corporate Revolving Credit Facility extends through July 30, 2023 with 2, one year extension options (subject to consent from lenders). This facility includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our Corporate credit rating from S&P, Fitch, and Moody's for our senior unsecured long-term debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.125%, 1.125%, and 1.125%, respectively, at September 30, 2019. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at September 30, 2019.

We have a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million. The notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration exemption.

Our net short-term borrowings (payments) during the nine months ended September 30, 2019 were $109 million. At September 30, 2019, the weighted average interest rate on short-term borrowings was 2.43%.

Debt Covenants

Under our Revolving Credit Facility and term loan agreements, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Our Consolidated Indebtedness to Capitalization Ratio was calculated by dividing (i) Consolidated Indebtedness, which includes letters of credit and certain guarantees issued, by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interest in subsidiaries. As of September 30, 2019, we were in compliance with these covenants.

Debt Transaction

On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million, extended the term through June 17, 2021, and had substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The net proceeds from the increase in total commitments were used to pay down short-term debt. Proceeds from the October 3, 2019 public debt offering were used to repay this term loan.

Subsequent Event - Debt Offering

On October 3, 2019, we completed a public debt offering of $700 million principal amount in senior unsecured notes. The debt offering consisted of $400 million of 3.05% 10-year senior notes due October 15, 2029 and $300 million of 3.875% 30-year senior notes due October 15, 2049 (together the “Notes”). The proceeds of the Notes were used for the following:

Repay the $400 million Corporate term loan under the Amended and Restated Credit Agreement due June 17, 2021;

Retire the $200 million 5.875% senior notes due July 15, 2020; and

Repay a portion of short-term debt.



23



(9)    EQUITY

At-the-Market Equity Offering Program

Our ATM equity offering program allows us to sell shares of our common stock with an aggregate value of up to $300 million. The shares may be offered from time to time pursuant to a sales agreement dated August 4, 2017. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. During the three months ended September 30, 2019, we issued a total of 389,237 shares of common stock under the ATM equity offering program for proceeds of $30 million, net of $0.3 million in commissions. During the nine months ended September 30, 2019, we issued a total of 1,328,332 shares of common stock under the ATM equity offering program for proceeds of $99 million, net of $1.0 million in commissions. As of September 30, 2019, there were no shares that were sold, but not settled.


(10)    RISK MANAGEMENT ACTIVITIES

Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operation of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk and Credit Policies and Procedures as discussed in our 2018 Annual Report on Form 10-K.

Market Risk

Market risk is the potential loss that might occur as a result of an adverse change in market price or rate. We are exposed to, but not limited to, commodity price risk associated with our retail natural gas marketing activities and our fuel procurement for certain gas-fired generation assets.

Credit Risk

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

For other than retail utility activities, 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 guaranties, prepayments, 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 customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience and any specific customer collection issue that is identified.

Our derivative and hedging activities recorded 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 11.

Utilities

The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to 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.

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 state 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 risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/or sales during time frames ranging from October 2019 through October 2021; a portion of these swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with 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. Effectiveness of our hedged position is evaluated at inception of the hedge, upon occurrence of a triggering event and as of the end of each quarter.


24



The contract or notional amounts and terms of the natural gas derivative commodity instruments held at our utilities are composed of both long and short positions. We were in a net long position as of:
 September 30, 2019 December 31, 2018
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
Natural gas futures purchased2,350,000
 15 4,000,000
 24
Natural gas options purchased, net8,580,000
 6 4,320,000
 13
Natural gas basis swaps purchased2,090,000
 15 3,960,000
 24
Natural gas over-the-counter swaps, net (b)
5,460,000
 25 3,660,000
 24
Natural gas physical contracts, net (c)
23,459,639
 6 18,325,852
 30

__________
(a)Term reflects the maximum forward period hedged.
(b)As of September 30, 2019, 1,812,500 MMBtus were designated as cash flow hedges.
(c)Volumes exclude contracts that qualify for the normal purchase, normal sales exception.

Based on September 30, 2019 prices, a $0.4 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.

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, 2019, the Company posted $0.5 million related to such provisions, which is included in Other current assets on the Condensed Consolidated Balance Sheets.

Cash Flow Hedges

The impacts of cash flow hedges on our Condensed Consolidated Statements of Income is presented below for the three and nine months ended September 30, 2019 and 2018. 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, 2019
(in thousands)
Derivatives in Cash Flow Hedging Relationships 
Location of
Reclassifications from AOCI into Income
 
Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
Interest rate swaps Interest expense $(713)
Commodity derivatives Fuel, purchased power and cost of natural gas sold (129)
Total   $(842)

Three Months Ended September 30, 2018
(in thousands)
Derivatives in Cash Flow Hedging Relationships 
Location of
Reclassifications from AOCI into Income
 
Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
Interest rate swaps Interest expense $(712)
Commodity derivatives Fuel, purchased power and cost of natural gas sold (18)
Total   $(730)


25



Nine Months Ended September 30, 2019
(in thousands)
Derivatives in Cash Flow Hedging Relationships 
Location of
Reclassifications from AOCI into Income
 
Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
Interest rate swaps Interest expense $(2,139)
Commodity derivatives Fuel, purchased power and cost of natural gas sold 508
Total   $(1,631)

Nine Months Ended September 30, 2018
(in thousands)
Derivatives in Cash Flow Hedging Relationships 
Location of
Reclassifications from AOCI into Income
 
Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
Interest rate swaps Interest expense $(2,138)
Commodity derivatives Fuel, purchased power and cost of natural gas sold (802)
Total   $(2,940)

The following tables summarize the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the three and nine months ended September 30, 2019 and 2018.
    
 Three Months Ended September 30,
 2019 2018
 (in thousands)
Increase (decrease) in fair value:   
Forward commodity contracts$(150) $30
Recognition of (gains) losses in earnings due to settlements:   
Interest rate swaps713
 712
Forward commodity contracts129
 18
Total other comprehensive income (loss) from hedging$692
 $760
 Nine Months Ended September 30,
 2019 2018
 (in thousands)
Increase (decrease) in fair value:   
Forward commodity contracts$(434) $(219)
Recognition of (gains) losses in earnings due to settlements:   
Interest rate swaps2,139
 2,138
Forward commodity contracts(508) 802
Total other comprehensive income (loss) from hedging$1,197
 $2,721


26



Derivatives Not Designated as Hedge Instruments

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2019 and 2018 (in thousands). 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,
  2019 2018
Derivatives Not Designated as Hedging InstrumentsLocation of Gain/(Loss) on Derivatives Recognized in IncomeAmount of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income
     
Commodity derivativesFuel, purchased power and cost of natural gas sold$(20) $(96)
Commodity derivativesOther income (expense), net142
 
  $122
 $(96)

  Nine Months Ended September 30,
  2019 2018
Derivatives Not Designated as Hedging InstrumentsLocation of Gain/(Loss) on Derivatives Recognized in IncomeAmount of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income
     
Commodity derivativesFuel, purchased power and cost of natural gas sold$(1,180) $929
Commodity derivativesOther income (expense), net$142
 $
  $(1,038) $929


As discussed above, financial instruments used in our regulated utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory asset or Regulatory liability accounts related to the hedges in our utilities were $4.3 million and $6.2 million as of September 30, 2019 and December 31, 2018, respectively.


(11)    FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

The accounting guidance for fair value measurements requires certain disclosures about assets and liabilities measured at fair value. This guidance establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. 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. For additional information, see Notes 1, 9, 10 and 11 to the Consolidated Financial Statements included in our 2018 Annual Report on Form 10-K filed with the SEC.

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.

Valuation Methodologies for Derivatives

The commodity contracts for our Utilities Segments, are valued using the market approach and include exchange-traded futures, options, basis swaps and over-the-counter swaps and options (Level 2) for 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.

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 21.

Recurring Fair Value Measurements

 As of September 30, 2019
 Level 1Level 2Level 3 
Cash Collateral and Counterparty
Netting
Total
 (in thousands)
Assets:      
Commodity derivatives — Utilities$
$2,750
$
 $(2,335)$415
Total$
$2,750
$
 $(2,335)$415
       
Liabilities:      
Commodity derivatives — Utilities$
$6,080
$
 $(3,471)$2,609
Total$
$6,080
$
 $(3,471)$2,609



27



 As of December 31, 2018
 Level 1Level 2Level 3 
Cash Collateral and Counterparty
Netting
Total
 (in thousands)
Assets:      
Commodity derivatives — Utilities$
$2,927
$
 $(1,408)$1,519
Total$
$2,927
$
 $(1,408)$1,519
       
Liabilities:      
Commodity derivatives — Utilities$
$6,801
$
 $(5,794)$1,007
Total$
$6,801
$
 $(5,794)$1,007


       


Fair Value Measures 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 permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements and the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions.

The following table presents the fair value and balance sheet classification of our derivative instruments (in thousands) as of:
 Balance Sheet Location September 30, 2019December 31, 2018
Derivatives designated as hedges:    
Asset derivative instruments:    
Current commodity derivativesDerivative assets — current $
$415
Noncurrent commodity derivativesOther assets, non-current 2
18
Liability derivative instruments:    
Current commodity derivativesDerivative liabilities — current (427)(114)
Noncurrent commodity derivativesOther deferred credits and other liabilities (70)(4)
Total derivatives designated as hedges  $(495)$315
     
Derivatives not designated as hedges:    
Asset derivative instruments:    
Current commodity derivativesDerivative assets — current $412
$1,085
Noncurrent commodity derivativesOther assets, non-current 1
1
Liability derivative instruments:    
Current commodity derivativesDerivative liabilities — current (1,969)(833)
Noncurrent commodity derivativesOther deferred credits and other liabilities (143)(56)
Total derivatives not designated as hedges  $(1,699)$197

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 2018 Annual Report on Form 10-K.


28



(12)    FAIR VALUE OF FINANCIAL INSTRUMENTS

Other financial instruments for which the carrying value did not equal fair value were as follows (in thousands) as of:
 September 30, 2019 December 31, 2018
 
Carrying
Amount
Fair Value 
Carrying
Amount
Fair Value
Long-term debt, including current maturities (a) (b)
$3,054,978
$3,424,747
 $2,956,578
$3,039,108
__________
(a)Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.
(b)Carrying amount of long-term debt is net of deferred financing costs.


(13)
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 Nine Months Ended
September 30, 2019September 30, 2018 September 30, 2019September 30, 2018
Gains and (losses) on cash flow hedges:      
Interest rate swapsInterest expense$(713)$(712) $(2,139)$(2,138)
Commodity contracts
Fuel, purchased power and cost of natural gas sold

(129)(18) 508
(802)
  (842)(730) (1,631)(2,940)
Income taxIncome tax benefit (expense)170
149
 358
643
Total reclassification adjustments related to cash flow hedges, net of tax $(672)$(581) $(1,273)$(2,297)
       
Amortization of components of defined benefit plans:      
Prior service costOperations and maintenance$20
$44
 $59
$133
       
Actuarial gain (loss)Operations and maintenance(84)(621) (525)(1,865)
  (64)(577) (466)(1,732)
Income taxIncome tax benefit (expense)89
128
 184
380
Total reclassification adjustments related to defined benefit plans, net of tax $25
$(449) $(282)$(1,352)
Total reclassifications $(647)$(1,030) $(1,555)$(3,649)


29



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, 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)
     
     
 Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
As of December 31, 2017$(19,581)$(518)$(21,103)$(41,202)
Other comprehensive income (loss)    
before reclassifications
(168)
(168)
Amounts reclassified from AOCI1,682
615
1,352
3,649
Reclassifications of certain tax effects from AOCI15

3
18
As of September 30, 2018$(17,884)$(71)$(19,748)$(37,703)



(14)    SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Nine Months EndedSeptember 30, 2019 September 30, 2018
 (in thousands)
Non-cash investing and financing activities —   
Property, plant and equipment acquired with accrued liabilities$86,661
 $49,631
    
Cash (paid) refunded during the period —   
Interest (net of amounts capitalized)$(99,375) $(104,035)
Income taxes$2,255
 $(14,842)




30



(15)    EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

The components of net periodic benefit cost for the Defined Benefit Pension Plan were as follows (in thousands):
 Three Months Ended September 30, Nine Months Ended September 30,
 20192018 20192018
Service cost$1,346
$1,708
 $4,037
$5,125
Interest cost4,344
3,867
 13,031
11,602
Expected return on plan assets(6,100)(6,185) (18,300)(18,555)
Prior service cost6
15
 19
44
Net loss (gain)941
2,158
 2,822
6,473
Net periodic benefit cost$537
$1,563
 $1,609
$4,689


Defined Benefit Postretirement Healthcare Plans

The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plans were as follows (in thousands):
 Three Months Ended September 30, Nine Months Ended September 30,
 20192018 20192018
Service cost$454
$573
 $1,362
$1,718
Interest cost560
521
 1,683
1,563
Expected return on plan assets(57)(57) (172)(170)
Prior service cost (benefit)(99)(99) (298)(297)
Net loss (gain)
54
 
162
Net periodic benefit cost$858
$992
 $2,575
$2,976


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,
 20192018 20192018
Service cost$429
$632
 $2,406
$1,347
Interest cost324
293
 972
878
Prior service cost

 1
1
Net loss (gain)134
250
 402
750
Net periodic benefit cost$887
$1,175
 $3,781
$2,976



31



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 2019 and anticipated contributions for 2019 and 2020 are as follows (in thousands):
 Contributions MadeContributions MadeAdditional ContributionsContributions
 Three Months Ended September 30, 2019Nine Months Ended September 30, 2019Anticipated for 2019Anticipated for 2020
Defined Benefit Pension Plan$12,700
$12,700
$
$12,700
Non-pension Defined Benefit Postretirement Healthcare Plans$1,109
$3,326
$1,109
$4,815
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans$366
$1,098
$366
$1,406



(16)    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 2018 Annual Report on Form 10-K except for those described below.

Future Purchase Agreement - Related Party

On August 2, 2019, Black Hills Wyoming and Wyoming Electric filed a request with FERC for approval of a new 60 MW PPA. If approved, Black Hills Wyoming will continue to deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and continuing for 20 additional years. A decision from FERC is pending.

Platte River Power Authority PPAs

On June 26, 2019, Colorado Electric entered into a PPA with Platte River Power Authority to purchase up to 60 MW of wind energy upon construction completion of a new wind project, which is expected in mid-2020. This agreement will expire May 31, 2030.

On June 26, 2019, Colorado Electric entered into a PPA with Platte River Power Authority to purchase 25 MW of unit contingent energy. This agreement was effective September 1, 2019 and will expire June 30, 2024.

The following is a schedule of unconditional purchase obligations required under the 25 MW Platte River Power Authority PPA as of September 30, 2019 (in thousands):
2019$1,369
2020$5,475
2021$5,475
2022$5,475
2023$5,475
Thereafter$2,738





32




(17)    DISCONTINUED OPERATIONS

Results of operations for discontinued operations were classified as Loss from discontinued operations, net of income taxes in the accompanying Condensed Consolidated Statements of Income. Prior periods relating to our discontinued operations were also reclassified to reflect consistency within our condensed consolidated financial statements.

Oil and Gas Segment

On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture in 2018. See Note 21 for more information.


(18)    INCOME TAXES

Income tax benefit (expense) for the Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2018.

Income tax benefit (expense) for the three months ended September 30, 2019 was $(2.5) million compared to $(7.5) million reported for the same period in 2018. The decrease in tax expense was primarily due to a prior year $(5.3) million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes.

For the three months ended September 30, 2019 the effective tax rate was 14.0% compared to 7.6% excluding the tax reform adjustments, for the same period in 2018. The higher effective tax rate is primarily due to a prior year state tax benefit.

Income tax benefit (expense) for the Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018.

Income tax benefit (expense) for the nine months ended September 30, 2019 was $(22) million compared to $12 million reported for the same period in 2018. The increase in tax expense was primarily due to a prior year $49 million tax benefit resulting from legal entity restructuring partially offset by a prior year $(7.5) million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes.

For the nine months ended September 30, 2019 the effective tax rate was 13.6% compared to 17.1% excluding the legal entity restructuring and tax reform adjustments, for the same period in 2018. The lower effective tax rate is primarily due to $5.0 million of federal production tax credits and related state investment tax credits associated with new wind assets and a $1.0 million tax benefit for deferred tax amortization related to tax reform.


(19)    ACCRUED LIABILITIES

The following amounts by major classification are included in Accrued liabilities in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 September 30, 2019December 31, 2018
Accrued employee compensation, benefits and withholdings$57,313
$63,742
Accrued property taxes38,937
42,510
Customer deposits and prepayments56,220
43,574
Accrued interest and contract adjustment payments35,100
31,759
Other (none of which is individually significant)30,262
33,916
Total accrued liabilities$217,832
$215,501




33



(20)     LEASES

Lessee
We lease from third parties certain office and operation center facilities, communication tower sites, equipment, and materials storage. Our leases have remaining terms ranging from less than one year to 37 years, including options to extend that are reasonably certain to be exercised.
The components of lease expense were as follows (in thousands):
 Income Statement LocationThree Months Ended September 30, 2019Nine Months Ended September 30, 2019
Operating lease costOperations and maintenance$380
$1,076
Finance lease cost:   
Amortization of right-of-use assetDepreciation, depletion and amortization28
72
Interest on lease liabilitiesInterest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)5
14
Total lease cost $413
$1,162




Supplemental balance sheet information related to leases was as follows (in thousands):
 Balance Sheet LocationAs of September 30, 2019
Assets:  
Operating lease assetsOther assets, non-current$4,864
Finance lease assetsOther assets, non-current493
Total lease assets $5,357
   
Liabilities:  
Current:  
Operating leasesAccrued liabilities$970
Finance leaseAccrued liabilities80
   
Noncurrent:  
Operating leasesOther deferred credits and other liabilities4,252
Finance leaseOther deferred credits and other liabilities419
Total lease liabilities $5,721



34



Supplemental cash flow information related to leases was as follows (in thousands):
 Nine Months Ended September 30, 2019
Cash paid included in the measurement of lease liabilities: 
Operating cash flows from operating leases$895
Operating cash flows from finance lease$14
Financing cash flows from finance lease$66
Right-of-use assets obtained in exchange for lease obligations: 
Operating leases$2,775
Finance lease$67


 As of September 30, 2019
Weighted average remaining lease term (years): 
Operating leases8 years
Finance lease4 years
  
Weighted average discount rate: 
Operating leases4.27%
Finance lease4.19%


As of September 30, 2019, scheduled maturities of lease liabilities for future years were as follows (in thousands):
 Operating LeasesFinance LeaseTotal
2019 (a)
$368
$32
$400
2020992
126
1,118
2021855
126
981
2022736
126
862
2023714
126
840
Thereafter2,682
10
2,692
Total lease payments (b)
$6,347
$546
$6,893
Less imputed interest1,125
47
1,172
Present value of lease liabilities$5,222
$499
$5,721

(a)Includes lease liabilities for the remaining three months of 2019.
(b)Lease payments exclude payments to landlords for common area maintenance, real estate taxes, and insurance.

As previously disclosed in Note 14 of the Notes to the Consolidated Financial Statements in our 2018 Annual Report on Form 10-K, prior to the adoption of ASU 2016-02, Leases (Topic 842), the future minimum payments required under operating lease agreements as of December 31, 2018 were as follows (in thousands):
 Operating Leases
2019$1,052
2020464
2021344
2022224
2023216
Thereafter1,776
Total lease payments 
$4,076


35




Lessor

We lease to third parties certain generating station ground leases, communication tower sites, and a natural gas pipeline. These leases have remaining terms ranging from less than one year to 35 years.

The components of lease revenue were as follows (in thousands):
 Income Statement LocationThree Months Ended September 30, 2019Nine Months Ended September 30, 2019
Operating lease incomeRevenue$544
$1,749



As of September 30, 2019, scheduled maturities of lease receivables for future years were as follows (in thousands):
 Operating Leases
2019 (a)
$551
20202,035
20211,857
20221,793
20231,799
Thereafter55,481
Total lease receivables$63,516

(a)Includes lease receivables for the remaining three months of 2019.


(21)     INVESTMENTS

In February 2018, we made a contribution of $28 million of assets in exchange for equity securities in a privately held oil and gas company as we divested from 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 and nine months ended September 30, 2019, which was the difference between the carrying amount and the fair value of the investment.

The following table presents the carrying value of our investments (in thousands) as of:
 September 30, 2019 December 31, 2018
Investment in privately held oil and gas company$8,359
 $28,100
Cash surrender value of life insurance contracts12,907
 12,812
Other investments317
 101
Total investments$21,583
 $41,013




36



(22)    SUBSEQUENT EVENTS

There are no subsequent events, other than those disclosed in Note 8.


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

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

Electric Utilities: Our Electric Utilities segment generates, transmits and distributes electricity to approximately 212,000 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 own distribution systems. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates.

Gas Utilities: Our Gas Utilities conduct natural gas utility operations through our Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming subsidiaries. Our Gas Utilities distribute and transport natural gas through our pipeline network to approximately 1,054,000 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.

Our Gas Utilities also provide non-regulated services through Black Hills Energy Services. Black Hills Energy Services provides approximately 47,000 retail distribution customers in Nebraska and Wyoming with unbundled natural gas commodity offerings under the regulator-approved Choice Gas Program. We also sell, install and service air conditioning, heating and water-heating equipment, and provide associated repair service and protection plans under various trade names. Service Guard and CAPP provide appliance repair services to approximately 62,000 and 28,000 residential customers, respectively, through Company technicians and third-party service providers, typically through on-going monthly service agreements. Tech Services serves gas transportation customers throughout our service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.

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

Mining: Our Mining segment extracts coal at our coal 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.

Effective January 1, 2019, we changed our measure of segment performance to adjusted operating income, which impacted our segment disclosures for all periods presented. See Note 3 of the Notes to Condensed Consolidated Financial Statements for more 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 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, 2019 and 2018, and our financial condition as of September 30, 2019 and December 31, 2018, 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 58.

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

37




Results of Operations

Executive Summary, Significant Events and Overview

 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
(in millions, except per share amounts)IncomeEPS IncomeEPS IncomeEPS IncomeEPS
            
Net income from continuing operations available for common stock$11.7
$0.19
 $17.8
$0.32
 $130.1
$2.15
 $177.5
$3.26
Net (loss) from discontinued operations

 (0.9)(0.02) 

 (5.6)(0.10)
Net income available for common stock$11.7
$0.19
 $17.0
$0.31
 $130.1
$2.15
 $171.9
$3.15


Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018.

The variance to the prior year included the following:

Electric Utilities’ adjusted operating income increased $7.3 million primarily due to the prior year Wyoming Electric PCA settlement, warmer summer weather in Colorado and Wyoming, increased industrial demand, and increased rider revenues partially offset by higher operating expenses driven by outside services and employee costs;
Gas Utilities’ adjusted operating income increased $0.5 million primarily due to new rates, increased transport and transmission, and customer growth partially offset by lower heating demand from warmer weather, reduced irrigation demand due to heavy precipitation and higher operating expenses driven by outside services and employee costs;
Power Generation’s adjusted operating income decreased $1.3 million primarily due to higher depreciation and property taxes from new wind assets partially offset by higher revenue from increased wind MWh sold and higher PPA prices;
Mining’s adjusted operating income decreased $1.2 million primarily due to lower tons sold driven by unplanned generating facility outages partially offset by lower operating expenses;
A $20 million non-cash impairment of our investment in equity securities of a privately held oil and gas company; and
A prior year $5.3 million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.

The variance to the prior year included the following:

Electric Utilities’ adjusted operating income increased $2.1 million primarily due to reduced power capacity charges, the prior year Wyoming Electric PCA settlement and increased rider revenues partially offset by higher operating expenses driven by outside services and employee costs;
Gas Utilities’ adjusted operating income increased $0.4 million primarily due to new rates offset by higher operating expenses driven by outside services and employee costs;
Power Generation’s adjusted operating income increased $0.2 million primarily due to higher revenue from increased wind MWh sold partially offset by higher depreciation and property taxes from new wind assets;
Mining’s adjusted operating income decreased $3.3 million primarily due to lower tons sold driven by planned and unplanned generating facility outages partially offset by lower operating expenses;
Corporate and Other expenses decreased $2.3 million primarily due to prior year expenses related to the oil and gas segment that were not reclassified to discontinued operations;
A $20 million non-cash impairment of our investment in equity securities of a privately held oil and gas company;
A prior year $49 million tax benefit resulting from legal entity restructuring partially offset by a prior year $7.5 million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes; and
A lower current year effective tax rate primarily due to $5.0 million of federal production tax credits and related state investment tax credits associated with new wind assets and a $1.0 million tax benefit for deferred tax amortization related to tax reform.



38



The following table summarizes select financial results by operating segment and details significant items (in thousands):
 Three Months Ended September 30,Nine Months Ended September 30,
 20192018Variance20192018Variance
Revenue      
Revenue$363,491
$358,258
$5,233
$1,368,748
$1,361,102
$7,646
Inter-company eliminations(37,943)(36,279)(1,664)(111,502)(108,030)(3,472)
 $325,548
$321,979
$3,569
$1,257,246
$1,253,072
$4,174
Adjusted operating income (a)
      
Electric Utilities$50,653
$43,393
$7,260
$125,219
$123,073
$2,146
Gas Utilities4,736
4,240
496
116,607
116,168
439
Power Generation11,822
13,079
(1,257)33,945
33,731
214
Mining3,374
4,551
(1,177)9,351
12,647
(3,296)
Corporate and Other(34)(178)144
(439)(2,709)2,270
Operating income70,551
65,085
5,466
284,683
282,910
1,773
   
   
Interest expense, net(33,487)(35,297)1,810
(102,469)(104,826)2,357
Impairment of investment(19,741)
(19,741)(19,741)
(19,741)
Other income (expense), net580
(510)1,090
55
(1,923)1,978
Income tax benefit (expense)(2,508)(7,477)4,969
(22,078)11,784
(33,862)
Income from continuing operations15,395
21,801
(6,406)140,450
187,945
(47,495)
Net (loss) from discontinued operations
(857)857

(5,627)5,627
Net income15,395
20,944
(5,549)140,450
182,318
(41,868)
Net income attributable to noncontrolling interest(3,655)(3,994)339
(10,319)(10,447)128
Net income available for common stock$11,740
$16,950
$(5,210)$130,131
$171,871
$(41,740)
__________
(a)In 2019, we changed our measure of segment performance to adjusted operating income, which impacted our segment disclosures for all periods presented. See Note 3 of the Notes to Condensed Consolidated Financial Statements for additional information.

Overview of Business Segments and Corporate Activity

Electric Utilities Segment

Cooling degree days for the three and nine months ended September 30, 2019 were 27% and 14% higher than normal compared to 9% and 29% higher than normal for the same periods in 2018.

Heating degree days for the three and nine months ended September 30, 2019 were 36% lower and 6% higher than normal, compared to 20% and 3% lower than normal for the same periods in 2018.

On September 17, 2019, South Dakota Electric completed construction on the final 94-mile segment of a 175-mile electric transmission line from Rapid City, South Dakota, to Stegall, Nebraska. The first 48-mile segment was placed in service on July 25, 2018, and the second 33-mile segment was placed in service on November 20, 2018.

Colorado Electric and Wyoming Electric set new all-time and summer peak loads:

On July 19, 2019, Colorado Electric set a new peak load of 422 MW, exceeding the previous peak of 413 MW set in June 2018.

On July 19, 2019, Wyoming Electric set a new peak load of 265 MW, exceeding the previous peak of 254 MW set in July 2018.

39




South Dakota Electric and Wyoming Electric received approvals for the Renewable Ready Service Tariffs and related jointly-filed CPCN to construct the $57 million, 40 MW Corriedale Wind Energy 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 in service by the end of 2020. In September 2019, the customer subscription period was completed with customer interest fulfilling the 40 MW of available energy. On November 1, 2019, South Dakota Electric filed with the SDPUC an amendment seeking approval to increase the generating capacity under the tariff for the South Dakota portion by 12.5 MW to a total of 32.5 MW.

Gas Utilities Segment

Heating degree days for the three and nine months ended September 30, 2019 were 62% lower and 7% higher than normal, compared to 27% lower and 0% higher than normal for the same periods in 2018.

Regulatory activity:

On October 29, 2019, Nebraska Gas received approval from the NPSC to merge its two gas distribution companies in Nebraska. A rate review is expected to be filed by mid-year 2020 to consolidate the rates, tariffs and services of its two existing gas distribution companies.

On June 3, 2019, Wyoming Gas filed a rate review application with the WSPC to consolidate the rates, tariffs and services of its four existing gas distribution territories in Wyoming. The rate review requests $16 million in new revenue to recover investments in safety, reliability and system integrity. Wyoming Gas is also requesting a new rider mechanism to recover future safety and integrity investments in its system. A settlement was recently reached with the intervening parties in the rate review filing and filed with the WPSC on November 1, 2019. The stipulation and agreement are subject to review and approval by the WPSC, with a decision expected by the end of 2019. See Note 5 of the Notes to Condensed Consolidated Financial Statements for additional details.

On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate rates, tariffs and services of its two existing gas distribution territories in Colorado. The rate review requests $2.5 million in new revenue to recover investments in safety, reliability and system integrity. Colorado Gas is also requesting a new rider mechanism to recover future safety and integrity investments in its system. A decision from the CPUC is expected by March 2020.

On May 10, 2019, Wyoming Gas commenced construction on the $54 million, 35-mile Natural Bridge pipeline project to enhance supply reliability and delivery capacity for customers in central Wyoming. The new 12-inch steel pipeline will interconnect from a supply point near Douglas, Wyoming, to existing facilities near Casper, Wyoming. Construction of the pipeline is nearly complete and the project is expected to be in service by the end of 2019, with the associated investment included in the Wyoming Gas rate review filed on June 3, 2019.

Power Generation Segment

On August 2, 2019 Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for approval of a new 60 MW PPA. If approved, Black Hills Wyoming will continue to deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and for 20 additional years. A decision from FERC is pending.

On March 11, 2019, Black Hills Electric Generation commenced construction on the $71 million, 60 MW Busch Ranch II Wind Farm. The project is expected to be fully in service by mid-November 2019.


Mining

In October, negotiations were completed for the price reopener in the contract with Wyodak Plant. The new price was reset at $17.94 per ton effective July 1, 2019, compared to the prior contract price of $18.25 per ton.

40





Corporate and Other

On October 15, 2019, Moody’s affirmed South Dakota Electric’s credit rating at A1.

On October 3, 2019, we completed a public debt offering of $700 million in senior unsecured notes. Proceeds were used to repay the $400 million Corporate term loan due June 17, 2021, retire the $200 million 5.875% senior notes due July 15, 2020 and repay a portion of short-term debt.

During the nine months ended September 30, 2019, we issued a total of 1,328,332 shares of common stock under the ATM equity offering program for net proceeds of $99 million.

On August 29, 2019, Fitch affirmed our BBB+ rating and maintained a Stable outlook.

On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million and extended the term through June 17, 2021 on substantially similar terms and covenants. The net proceeds were used to pay down short-term debt. Proceeds from the October 3, 2019 debt transaction were used to repay this term loan.

On April 30, 2019, S&P affirmed South Dakota Electric’s credit rating at A.

On February 28, 2019, S&P affirmed our BBB+ rating and maintained a Stable outlook.


Operating Results

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


41



Electric Utilities

 Three Months Ended September 30,Nine Months Ended September 30,
 20192018Variance20192018Variance
 (in thousands)
Revenue$191,384
$184,790
$6,594
$540,665
$531,961
$8,704
       
Total fuel and purchased power71,593
74,638
(3,045)207,004
209,317
(2,313)
       
Gross margin (non-GAAP)119,791
110,152
9,639
333,661
322,644
11,017
       
Operations and maintenance47,172
45,307
1,865
143,049
135,501
7,548
Depreciation and amortization21,966
21,453
513
65,393
64,070
1,323
Total operating expenses69,138
66,760
2,378
208,442
199,571
8,871
       
Adjusted operating income (a)
$50,653
$43,392
$7,261
$125,219
$123,073
$2,146
________________
(a)Due to the changes in our segment disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Electric Utilities’ Adjusted operating income was revised for the three and nine months ended September 30, 2018, which resulted in an increase of $1.6 million and $4.8 million, respectively.


Results of Operations for the Electric Utilities for the Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2018:

Gross margin for the three months ended September 30, 2019 increased as a result of the following:
 (in millions)
Prior year Wyoming Electric PCA Stipulation settlement$3.4
Weather1.8
Increased industrial demand1.7
Reduction in power capacity charges1.7
Rider recovery1.3
Other(0.3)
Total increase in Gross margin (non-GAAP)$9.6

Operations and maintenance expense increased primarily due to $1.0 million of higher employee costs and $0.6 million of higher outside services expenses.




42



Results of Operations for the Electric Utilities for the Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018:

Gross margin for the nine months ended September 30, 2019 increased as a result of the following:
 (in millions)
Reduction in power capacity charges$4.9
Prior year Wyoming Electric PCA Stipulation settlement3.7
Rider recovery2.0
Decreased residential customer usage(0.9)
Decreased commercial and industrial demand(0.2)
Weather(0.1)
Other1.6
Total increase in Gross margin (non-GAAP)$11.0

Operations and maintenance expense increased primarily due to $3.6 million of higher employee costs and $3.4 million of higher outside services expenses.

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


Operating Statistics
  Electric Revenue (in thousands) Quantities sold (MWh)
  Three Months Ended
September 30,
Nine Months Ended
September 30,
 Three Months Ended
September 30,
Nine Months Ended
September 30,
  2019201820192018 2019201820192018
Residential $58,919
$58,122
$162,257
$163,979
 384,735
372,623
1,075,394
1,084,531
Commercial 65,732
65,794
186,434
192,680
 560,547
550,791
1,556,449
1,560,911
Industrial 33,937
31,939
98,074
93,959
 462,809
429,133
1,335,260
1,248,438
Municipal 4,792
4,582
13,184
13,389
 46,106
43,972
121,025
122,953
Subtotal Retail Revenue - Electric 163,380
160,437
459,949
464,007
 1,454,197
1,396,519
4,088,128
4,016,833
Contract Wholesale 8,211
8,256
23,335
25,497
 229,369
221,327
646,611
677,163
Off-system/Power Marketing Wholesale 6,452
9,059
16,592
18,142
 160,357
206,791
436,298
514,686
Other 13,341
7,038
40,789
24,315
 



Total Revenue and Energy Sold 191,384
184,790
540,665
531,961
 1,843,923
1,824,637
5,171,037
5,208,682
Other Uses, Losses or Generation, net 



 112,172
121,478
299,038
337,939
Total Revenue and Energy 191,384
184,790
540,665
531,961
 1,956,095
1,946,115
5,470,075
5,546,621
Less cost of fuel and purchased power (a)
 71,593
74,638
207,004
209,317
     
Gross Margin (non-GAAP) (a)
 $119,791
$110,152
$333,661
$322,644
     
________________
(a)Due to the changes in our segment disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, cost of fuel and purchased power was revised for the three and nine months ended September 30, 2018, which resulted in an increase of $1.6 million and $4.8 million, respectively. There were corresponding decreases to Gross margin for each period.


43



          
Three Months Ended September 30, 
Electric Revenue
(in thousands)
 Gross Margin (non-GAAP) (in thousands) 
Quantities Sold (MWh) (a)
  20192018 20192018 20192018
Colorado Electric (b)
 $70,771
$68,052
 $41,916
$38,449
 634,098
610,079
South Dakota Electric 77,022
78,067
 55,217
52,860
 835,725
874,962
Wyoming Electric 43,591
38,671
 22,658
18,843
 486,272
461,074
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold $191,384
$184,790
 $119,791
$110,152
 1,956,095
1,946,115
          
Nine Months Ended September 30, 
Electric Revenue
(in thousands)
 Gross Margin (non-GAAP) (in thousands) 
Quantities Sold (MWh) (a)
  20192018 20192018 20192018
Colorado Electric (b)
 $186,030
$188,937
 $104,411
$105,997
 1,611,126
1,639,607
South Dakota Electric 225,309
222,558
 162,390
154,158
 2,438,366
2,541,082
Wyoming Electric 129,326
120,466
 66,860
62,489
 1,420,583
1,365,932
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold $540,665
$531,961
 $333,661
$322,644
 5,470,075
5,546,621
________________
(a)Total MWh for 2019 includes Other Uses, Losses or Generation, net, which are approximately 6%, 5%, and 6% for Colorado Electric, South Dakota Electric, and Wyoming Electric, respectively.
(b)Due to the changes in our segment disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Gross margin was revised for the three and nine months ended September 30, 2018, which resulted in a decrease of $(1.6) million and $(4.8) million, respectively.

 Three Months Ended
September 30,
Nine Months Ended
September 30,
Quantities Generated and Purchased (MWh)2019201820192018
     
Coal-fired564,220
608,417
1,621,355
1,772,750
Natural Gas and Oil234,366
199,351
445,498
345,978
Wind55,407
54,450
167,331
196,932
Total Generated853,993
862,218
2,234,184
2,315,660
Purchased1,102,102
1,083,897
3,235,891
3,230,961
Total Generated and Purchased1,956,095
1,946,115
5,470,075
5,546,621

 Three Months Ended
September 30,
Nine Months Ended
September 30,
Quantities Generated and Purchased (MWh)2019201820192018
Generated:    
Colorado Electric149,509
163,276
341,925
388,251
South Dakota Electric489,042
469,680
1,262,336
1,293,713
Wyoming Electric215,442
229,262
629,923
633,696
Total Generated853,993
862,218
2,234,184
2,315,660
Purchased:    
Colorado Electric484,589
446,803
1,269,201
1,251,356
South Dakota Electric346,683
405,282
1,176,030
1,247,369
Wyoming Electric270,830
231,812
790,660
732,236
Total Purchased1,102,102
1,083,897
3,235,891
3,230,961
     
Total Generated and Purchased1,956,095
1,946,115
5,470,075
5,546,621


44



          
 Three Months Ended September 30,
Degree Days  2019   2018
 Actual 
Variance from
Normal
 Actual Variance to Prior Year Actual 
Variance from
Normal
Heating Degree Days:         
Colorado Electric4
 (96)% (89)% 35
 (64)%
South Dakota Electric175
 (22)% (26)% 236
 5 %
Wyoming Electric120
 (77)% (52)% 248
 (19)%
Combined (a)
86
 (36)% (41)% 147
 (20)%
          
Cooling Degree Days:         
Colorado Electric1,079
 58 % 19% 910
 33 %
South Dakota Electric366
 (31)% 3% 356
 (33)%
Wyoming Electric433
 45 % 32% 328
 10 %
Combined (a)
705
 27 % 17% 603
 9 %

 Nine Months Ended September 30,
 2019   2018
Heating Degree DaysActual 
Variance from
Normal
 Actual Variance to Prior Year Actual 
Variance from
Normal
          
Colorado Electric3,156
 (6)% 9% 2,901
 (14)%
South Dakota Electric5,370
 20 % 8% 4,972
 11 %
Wyoming Electric4,677
 5 % 9% 4,285
 (9)%
Combined (a)
4,198
 6 % 8% 3,888
 (3)%
          
Cooling Degree Days:         
Colorado Electric1,226
 37 % (13)% 1,404
 57 %
South Dakota Electric404
 (36)% (17)% 488
 (23)%
Wyoming Electric462
 33 % 7% 430
 24 %
Combined (a)
791
 14 % (12)% 895
 29 %
__________
(a)Combined actuals are calculated based on the weighted average number of total customers by state.

Electric Utilities Power Plant AvailabilityThree Months Ended September 30,Nine Months Ended September 30,
 2019201820192018
Coal-fired plants (a)
94.6%95.7%90.0%94.0%
Natural gas-fired plants and Other plants (b)
89.6%97.0%89.8%97.2%
Wind93.7%96.9%95.0%96.9%
Total availability91.5%96.6%90.3%96.1%
     
Wind capacity factor33.8%33.1%37.1%41.8%
__________
(a)2019 included planned outages at Neil Simpson II and Wygen III and unplanned outages at Wyodak Plant and Wygen III.
(b)2019 included planned outages at Neil Simpson CT and Lange CT.



45




Gas Utilities
 Three Months Ended September 30,Nine Months Ended September 30,
 20192018Variance20192018Variance
 (in thousands)
Revenue:      
Natural gas - regulated$117,549
$117,070
$479
$651,366
$648,550
$2,816
Other - non-regulated services13,195
14,606
(1,411)55,927
58,090
(2,163)
Total revenue130,744
131,676
(932)707,293
706,640
653
       
Cost of sales:      
Natural gas - regulated28,154
30,612
(2,458)280,312
298,149
(17,837)
Other - non-regulated services4,870
5,514
(644)16,975
15,716
1,259
Total cost of sales33,024
36,126
(3,102)297,287
313,865
(16,578)
       
Gross margin (non-GAAP)97,720
95,550
2,170
410,006
392,775
17,231
       
Operations and maintenance70,170
69,746
424
225,239
212,319
12,920
Depreciation and amortization22,814
21,564
1,250
68,160
64,288
3,872
Total operating expenses92,984
91,310
1,674
293,399
276,607
16,792
       
Adjusted operating income$4,736
$4,240
$496
$116,607
$116,168
$439


Results of Operations for the Gas Utilities for the Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2018:

Gross margin for the three months ended September 30, 2019 increased as a result of:
 (in millions)
New rates$3.0
Customer growth - distribution0.8
Increased transport and transmission0.7
Weather (a)
(3.4)
Other1.1
Total increase in Gross margin (non-GAAP)$2.2

(a) Weather impacts for the three months ended September 30, 2019 compared to the same period in the prior year include reduced heating demand due to warmer temperatures and reduced irrigation loads to agriculture customers in our Nebraska Gas service territory due to higher precipitation.

Operations and maintenance expense increased primarily due to higher employee costs and higher outside services expenses.

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


46



Results of Operations for the Gas Utilities for the Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018:

Gross margin for the nine months ended September 30, 2019 increased as a result of:
 (in millions)
New rates$15.5
Customer growth - distribution3.7
Increased transport and transmission1.8
Decreased mark-to-market on non-utility natural gas commodity contracts(2.7)
Excess deferred taxes returned to customers(2.5)
Weather(0.6)
Other2.0
Total increase in Gross margin (non-GAAP)$17.2

Operations and maintenance expense increased primarily due to $7.2 million of higher outside services expenses, $4.1 million of higher employee costs and $1.3 million of higher property taxes due to a higher asset base driven by prior and current year capital expenditures.

Depreciation and amortization increased primarily due to a higher asset base driven by prior 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,
  20192018 20192018 20192018
          
Residential $57,244
$58,221
 $43,441
$42,598
 3,599,549
3,708,196
Commercial 19,629
19,639
 11,589
10,880
 2,298,919
2,278,304
Industrial 8,770
8,258
 2,493
2,028
 2,960,930
2,304,098
Other (a)
 2,499
487
 2,499
487
 

Total Distribution 88,142
86,605
 60,022
55,993
 8,859,398
8,290,598
          
Transportation and Transmission 29,407
30,465
 29,373
30,465
 31,538,815
29,808,567
          
Total Regulated 117,549
117,070
 89,395
86,458
 40,398,213
38,099,165
          
Non-regulated Services 13,195
14,606
 8,325
9,092
   
          
Total Gas Revenue & Gross Margin (non-GAAP) $130,744
$131,676
 $97,720
$95,550
   


47



          
  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,
  20192018 20192018 20192018
          
Residential $383,466
$383,972
 $201,168
$192,072
 44,356,725
42,642,021
Commercial 146,752
148,675
 61,673
57,890
 21,484,646
20,842,996
Industrial 18,764
20,805
 5,830
5,341
 5,141,399
5,235,417
Other (a)
 (968)(6,789) (968)(6,789) 

Total Distribution 548,014
546,663
 267,703
248,514
 70,982,770
68,720,434
          
Transportation and Transmission 103,352
101,887
 103,351
101,887
 110,622,285
107,388,321
          
Total Regulated 651,366
648,550
 371,054
350,401
 181,605,055
176,108,755
          
Non-regulated Services 55,927
58,090
 38,952
42,374
   
          
Total Gas Revenue & Gross Margin $707,293
$706,640
 $410,006
$392,775
   

(a)
Other revenue reflects the impact of revenue reserved in accordance with the TCJA.


  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,
  20192018 20192018 20192018
          
Arkansas $21,387
$18,743
 $16,249
$13,415
 4,094,454
4,022,089
Colorado 22,632
22,362
 15,667
15,210
 3,806,360
2,893,029
Iowa 16,381
16,982
 13,135
12,556
 5,686,772
5,595,205
Kansas 19,013
18,497
 12,309
11,129
 7,602,758
6,164,821
Nebraska 35,715
40,553
 28,046
31,264
 13,999,302
13,831,306
Wyoming 15,616
14,539
 12,314
11,976
 5,208,567
5,592,715
Total Gas Revenue & Gross Margin (non-GAAP) $130,744
$131,676
 $97,720
$95,550
 40,398,213
38,099,165

          
  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,
  20192018 20192018 20192018
          
Arkansas $127,014
$116,226
 $79,148
$65,803
 21,061,567
21,183,322
Colorado 135,816
125,898
 73,022
66,917
 23,050,638
19,301,834
Iowa 105,736
111,968
 50,773
49,630
 28,834,731
28,527,522
Kansas 77,609
81,880
 42,385
40,896
 24,336,744
23,391,905
Nebraska 183,827
196,307
 111,828
117,925
 57,815,316
58,223,856
Wyoming 77,291
74,361
 52,850
51,604
 26,506,059
25,480,316
Total Gas Revenue & Gross Margin (non-GAAP) $707,293
$706,640
 $410,006
$392,775
 181,605,055
176,108,755

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.


48



 Three Months Ended September 30,
 2019   2018
Heating Degree DaysActual 
Variance
from Normal
 Actual Variance to Prior Year Actual 
Variance
from Normal
Arkansas (a)
 (100)% (100)% 12 (72)%
Colorado68 (68)% (38)% 109 (49)%
Iowa43 (69)% (66)% 128 (7)%
Kansas (a)
 (101)% (100)% 54 (2)%
Nebraska22 (80)% (78)% 101 (7)%
Wyoming183 (37)% (22)% 236 (23)%
Combined (b)
53 (62)% (51)% 109 (27)%


          
 Nine Months Ended September 30,
 2019   2018
Heating Degree Days:Actual 
Variance
from Normal
 Actual Variance to Prior Year Actual 
Variance
from Normal
Arkansas (a)
2,347 (5)% (5)% 2,460 (1)%
Colorado4,115 —% 16% 3,548 (14)%
Iowa4,611 10% 3% 4,460 6%
Kansas (a)
3,204 8% 6% 3,032 2%
Nebraska4,169 10% 4% 4,016 6%
Wyoming5,093 9% 12% 4,552 (4)%
Combined (b)
4,297 7% 7% 4,008 —%
__________
(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 2018 Annual Report on Form 10-K filed with the SEC.


49



Power Generation
 Three Months Ended September 30,Nine Months Ended September 30,
 20192018Variance20192018Variance
 (in thousands)
Revenue$25,811
$24,491
$1,320
$75,764
$71,173
$4,591
       
Operations and maintenance9,229
7,434
1,795
27,750
25,520
2,230
Depreciation and amortization4,760
3,978
782
14,069
11,922
2,147
Total operating expense13,989
11,412
2,577
41,819
37,442
4,377
       
Adjusted operating income (a)
$11,822
$13,079
$(1,257)$33,945
$33,731
$214
________________
(a)Due to the changes in our segment disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Power Generation Adjusted operating income was revised for the three and nine months ended September 30, 2018, which resulted in a decrease of $(1.4) million and $(4.4) million, respectively.


Results of Operations for Power Generation for the Three and Nine Months Ended September 30, 2019 Compared to the Three and Nine Months Ended September 30, 2018:

Revenue increased in the current year due to increased wind MWh sold and higher PPA prices. Operating expenses increased in the current year primarily due to higher depreciation and property taxes from new wind assets.

The following table summarizes MWh for our Power Generation segment:
 Three Months Ended September 30, Nine Months Ended September 30,
 20192018 20192018
Quantities Sold, Generated and Purchased
(MWh) (a)
     
Sold     
Black Hills Colorado IPP (b)
275,867
304,102
 692,156
745,365
Black Hills Wyoming (c)
162,668
160,011
 476,430
470,072
Black Hills Electric Generation (d)
30,912

 112,461

Total Sold469,447
464,113
 1,281,047
1,215,437
      
Generated     
Black Hills Colorado IPP (b)
275,867
304,102
 692,156
745,365
Black Hills Wyoming (c)
142,219
144,476
 407,001
407,324
Black Hills Electric Generation (d)
30,912

 112,461

Total Generated448,998
448,578
 1,211,618
1,152,689
      
Purchased     
Black Hills Wyoming (c)
16,865
16,685
 56,205
65,724
Total Purchased16,865
16,685
 56,205
65,724
____________
(a)Company uses and losses are not included in the quantities sold, generated, and purchased.
(b)Decrease from the prior year is a result of the impact of Colorado Electric’s wind generation replacing natural-gas generation.
(c)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.
(d)Increase from prior year is driven by Black Hills Electric Generation’s acquisition of new wind assets.


50



The following table provides certain operating statistics for our plants within the Power Generation segment:
 Three Months Ended September 30, Nine Months Ended September 30,
 20192018 20192018
Contracted power plant fleet availability:     
Coal-fired plant98.0%97.9% 95.2%93.9%
Natural gas-fired plants (a)
97.6%99.3% 98.4%99.4%
Wind (b)
81.9%N/A
 93.4%N/A
Total availability93.6%98.9% 96.5%98.0%
      
Wind capacity factor (b)
15.0%N/A
 22.1%N/A
____________
(a)2019 included a planned outage at Pueblo Airport Generating Station.
(b)Change from the prior year is driven by Black Hills Electric Generation’s acquisition of new wind assets.

Mining

Three Months Ended September 30,Nine Months Ended September 30,

20192018Variance20192018Variance

(in thousands)
Revenue$15,552
$17,301
$(1,749)$45,026
$51,328
$(6,302)
       
Operations and maintenance9,900
10,761
(861)28,988
32,807
(3,819)
Depreciation, depletion and amortization2,278
1,989
289
6,687
5,874
813
Total operating expenses12,178
12,750
(572)35,675
38,681
(3,006)
       
Adjusted operating income$3,374
$4,551
$(1,177)$9,351
$12,647
$(3,296)

The following table provides certain operating statistics for our Mining segment (in thousands, except for Revenue per ton):
 Three Months Ended September 30, Nine Months Ended September 30,
 20192018 20192018
Tons of coal sold969
1,078
 2,720
3,119
Cubic yards of overburden moved2,341
2,361
 6,380
6,763
      
Revenue per ton$15.47
$15.54
 $15.90
$15.92

Results of Operations for Mining for the Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2018:

Current year revenue decreased due to 10% fewer tons sold driven primarily by unplanned generation facility outages. Operating expenses decreased primarily due to lower royalties and production taxes on decreased revenues.


Results of Operations for Mining for the Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018:

Current year revenue decreased due to 13% fewer tons sold driven primarily by planned and unplanned generation facility outages. Operating expenses decreased primarily due to lower royalties and production taxes on decreased revenues and lower fuel, labor and major maintenance expenses.

51



Corporate and Other
 Three Months Ended September 30,Nine Months Ended September 30,
 20192018Variance20192018Variance
 (in thousands)
Adjusted operating income (loss) (a)
$(34)$(178)$144
$(439)$(2,709)$2,270
________________
(a)Due to the changes in our segment disclosures as discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Corporate and Other Adjusted operating income (loss) was revised for the three and nine months ended September 30, 2018, which resulted in a decrease of $(0.2) million and $(0.4) million, respectively.

Results of Operations for Corporate and Other for the Nine Months Ended September 30, 2019 Compared to the Three and Nine Months Ended September 30, 2018:

The variance in Adjusted operating income (loss) was primarily due to prior year expenses related to the oil and gas segment that were not reclassified to discontinued operations.


Consolidated Interest expense, Impairment of investment, Other income (expense) and Income tax benefit (expense) for the Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2018.

Impairment of Investment

For the three months ended September 30, 2019, we recorded a 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 a deterioration in earnings performance of the privately held oil and gas company and an adverse change in future natural gas prices. See Note 21 of the Notes to Condensed Consolidated Financial Statements for additional details.

Income Tax Benefit (Expense)

Income tax benefit (expense) for the three months ended September 30, 2019 was $(2.5) million compared to $(7.5) million for the same period in 2018. The decrease in tax expense was primarily due to a prior year $(5.3) million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes.

For the three months ended September 30, 2019 the effective tax rate was 14.0% compared to 7.6% excluding the tax reform adjustments, for the same period in 2018. The higher effective tax rate is primarily due to a prior year state tax benefit.
  
Consolidated Interest expense, Impairment of investment, Other income (expense) and Income tax benefit (expense) for the Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018.

Impairment of Investment

For the nine months ended September 30, 2019, we recorded a 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 a deterioration in earnings performance of the privately held oil and gas company and an adverse change in future natural gas prices. See Note 21 of the Notes to Condensed Consolidated Financial Statements for additional details.


52



Income Tax Benefit (Expense)

Income tax benefit (expense) for the nine months ended September 30, 2019 was $(22) million compared to $12 million reported for the same period in 2018. The increase in tax expense was primarily due to a prior year $49 million tax benefit resulting from legal entity restructuring partially offset by a prior year $(7.5) million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes.

For the nine months ended September 30, 2019 the effective tax rate was 13.6% compared to 17.1% excluding the legal entity restructuring and tax reform adjustments, for the same period in 2018. The lower effective tax rate is primarily due to $5.0 million of federal production tax credits and related state investment tax credits associated with new wind assets, a $1.0 million tax benefit for deferred tax amortization related to tax reform.

Critical Accounting Estimates

There have been no material changes in our critical accounting estimates from those reported in our 2018 Annual Report on Form 10-K filed with the SEC. For more information on our critical accounting estimates, see Part II, Item 7 of our 2018 Annual Report on Form 10-K.

Liquidity and Capital Resources

There have been no material changes in Liquidity and Capital Resources from those reported in Item 7 of our 2018 Annual Report on Form 10-K filed with the SEC except as described below.

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, 2019, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts.

Income Tax

The TCJA required revaluation of federal deferred tax assets and liabilities using the new lower corporate tax rate of 21%. We have reached agreements with regulators in seven states and are working with FERC regarding returning benefits to customers. Our working capital requirements increased as a result of complying with the TCJA and providing the benefits of the TCJA to customers. These agreements will negatively impact our cash flows by approximately $40 million to $45 million per year for each of the next several years.

Cash Flow Activities

The following table summarizes our cash flows for the nine months ended September 30, 2019 (in thousands):
Cash provided by (used in):20192018Variance
Operating activities$386,075
$378,722
$7,353
Investing activities$(593,272)$(281,771)$(311,501)
Financing activities$199,827
$(101,949)$301,776


53



Year-to-Date 2019 Compared to Year-to-Date 2018

Operating Activities

Net cash provided by operating activities was $386 million for the nine months ended September 30, 2019, compared to net cash provided by operating activities of $379 million for the same period in 2018 for an increase of $7 million. The variance was primarily attributable to:

Cash earnings (income from continuing operations plus non-cash adjustments) were $19 million higher for the nine months ended September 30, 2019 compared to the same period in the prior year;

Net cash inflows from changes in operating assets and liabilities were $28 million for the nine months ended September 30, 2019, compared to net cash inflows of $42 million in the same period in the prior year. This $14 million decrease was primarily due to:

Cash inflows increased by approximately $48 million primarily as a result of higher collections of accounts receivable for the nine months ended September 30, 2019 compared to the same period in the prior year;

Cash outflows increased by approximately $3 million as a result of decreases in accounts payable and accrued liabilities driven by higher employee costs and other working capital requirements; and

Cash inflows decreased by approximately $66 million as a result of changes in the timing of recovery from fuel cost adjustments as well as revenue reserved in the prior year due to the TCJA tax rate change that has subsequently been returned to customers.

Investing Activities

Net cash used in investing activities was $593 million for the nine months ended September 30, 2019, compared to net cash used in investing activities of $282 million for the same period in 2018 for a variance of $311 million. The variance was primarily attributable to:

Capital expenditures of approximately $593 million for the nine months ended September 30, 2019 compared to $278 million for the same period in the prior year. Higher current year expenditures are driven by higher programmatic safety, reliability and integrity spending at our Gas Utilities and Electric Utilities segments, the 35-mile Natural Bridge pipeline project at our Gas Utilities segment, the Busch Ranch II wind project at our Power Generation segment and construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota, to Stegall, Nebraska at our Electric Utilities segment.

A $24 million investment made in the prior year partially offset by an $18 million change in net cash provided by investing activities from discontinued operations primarily due to the prior year sale of assets held for sale.


54



Financing Activities

Net cash provided by financing activities for the nine months ended September 30, 2019 was $200 million, compared to $102 million of net cash used in financing activities for the same period in 2018 for a variance of $302 million. This variance is primarily due to:

We amended our Corporate term loan due July 30, 2020, which increased our debt to $400 million from $300 million;

Current year issuance of common stock for net proceeds of $99 million through our ATM equity offering program;

Current year net short-term borrowings of $109 million driven by increased capital expenditures;

In the prior year, $99 million of net proceeds from the August 17, 2018 debt transaction was used to repay short-term debt;

$15 million of higher current year dividend payments; and

Payments for other financing activities decreased by $8.4 million, which was primarily driven by prior year financing costs associated with the July 30, 2018 and August 17, 2018 debt transactions.

Dividends

Dividends paid on our common stock totaled $92 million for the nine months ended September 30, 2019, or $0.505 per share per quarter. On October 31, 2019, our board of directors declared a quarterly dividend of $0.535 per share payable December 1, 2019, equivalent to an annual dividend of $2.14 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 had the following borrowings, outstanding letters of credit, and available capacity (in millions):
  CurrentShort-term borrowings atLetters of Credit atAvailable Capacity at
Credit FacilityExpirationCapacitySeptember 30, 2019September 30, 2019September 30, 2019
Revolving Credit Facility and CP ProgramJuly 30, 2023$750
$295
$18
$437

The weighted average interest rate on short-term borrowings at September 30, 2019 was 2.43%. Short-term borrowing activity for the nine months ended September 30, 2019 was (dollars in millions):
 For the Nine Months Ended September 30, 2019
Maximum amount outstanding - short-term borrowing (based on daily outstanding balances)$295
Average amount outstanding - short-term borrowing (based on daily outstanding balances)$171
Weighted average interest rates - short-term borrowing2.59%


55



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, 2019. See Note 8 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, 2019, we were in compliance with these covenants.
Financing Activities

Financing activities for the nine months ended September 30, 2019 consisted of the following:

We issued a total of 1,328,332 shares of common stock under the ATM equity offering program for proceeds of $99 million, net of $1.0 million in commissions. As of September 30, 2019, there were no shares that were sold, but not settled.

On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million, extended the term through June 17, 2021 and continues to have substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The net proceeds were used to pay down short-term debt. Proceeds from the October 3, 2019 debt transaction were used to repay this term loan.

Short-term borrowings from our CP Program and Revolver.

On October 3, 2019, we completed a public debt offering of $700 million principal amount in senior unsecured notes. The debt offering consisted of $400 million of 3.05% 10-year senior notes due October 15, 2029 and $300 million of 3.875% 30-year senior notes due October 15, 2049. Proceeds were used to repay the $400 million Corporate term loan due June 17, 2021, retire the $200 million 5.875% senior notes due July 15, 2020, repay a portion of short-term debt.

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, 2019:
Rating AgencySenior Unsecured RatingOutlook
S&P (a)
BBB+Stable
Moody’s (b)
Baa2Stable
Fitch (c)
  BBB+Stable
__________
(a)On February 28, 2019, S&P affirmed our BBB+ rating and maintained a Stable outlook.
(b)On December 12, 2018, Moody’s affirmed our Baa2 rating and maintained a Stable outlook.
(c)On August 29, 2019, Fitch affirmed our BBB+ rating and maintained a Stable outlook.


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The following table represents the credit ratings of South Dakota Electric at September 30, 2019:
Rating AgencySenior Secured Rating
S&P (a)
A
Moody’s (b)
A1
Fitch (c)
A
__________
(a)On April 30, 2019, S&P affirmed A rating.
(b)On October 15, 2019, Moody’s affirmed A1 rating.
(c)On August 29, 2019, Fitch affirmed A rating.

Capital Requirements

Capital Expenditures
 ActualPlannedPlannedPlannedPlannedPlanned
Capital Expenditures by Segment
Nine Months Ended September 30, 2019 (a)
2019 (b)
2020202120222023
(in millions)      
Electric Utilities (c)
$147
$215
$229
$203
$170
$137
Gas Utilities (c)
367
490
361
297
274
303
Power Generation79
84
7
9
11
6
Mining6
8
8
12
9
9
Corporate and Other15
23
18
22
11
12
 $614
$820
$623
$543
$475
$467
__________
(a)    Expenditures for the nine months ended September 30, 2019 include the impact of accruals for property, plant and equipment.
(b)    Includes actual capital expenditures for the nine months ended September 30, 2019.
(c)    Planned capital expenditures increased for 2019 through 2023 primarily due to increased programmatic safety, reliability and integrity spending.

We continue to evaluate potential future acquisitions and other growth opportunities when they arise. As a result, capital expenditures may vary significantly from the estimates identified above.

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 2018 Annual Report on Form 10-K except for the items described in Notes 8, 16, and 20 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 2018 Annual Report on Form 10-K filed with the SEC except for the items described in Note 8 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 2018 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.


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FORWARD-LOOKING INFORMATION

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

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

Any forward-looking statement contained in this document speaks only as of the date the statement was made. The Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement was made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, 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 2018 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our 2018 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. During the nine months ended September 30, 2019, there were no material changes to our quantitative and qualitative disclosures about market risk.

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 of September 30, 2019. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at September 30, 2019.

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 Security Exchange Act of 1934, as amended, is recorded, processed, summarized and reported, within the time periods specified in the Commission’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, 2019, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.



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BLACK HILLS CORPORATION

Part II — Other Information


ITEM 1.Legal Proceedings

For information regarding legal proceedings, see Note 19 in Item 8 of our 2018 Annual Report on Form 10-K and Note 16 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 16 is incorporated by reference into this item.

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 5, 2019 


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