Docoh
Loading...

BKH Black Hills

Filed: 6 Aug 19, 11:55am

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934 
 For the quarterly period ended
June 30, 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 July 31, 2019
Common stock, $1.00 par value61,063,230
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
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 temperature 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
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
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
SourceGasSourceGas Holdings LLC and its subsidiaries, a gas utility owned by funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) that was acquired on February 12, 2016, and is now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy)
SourceGas AcquisitionThe acquisition of SourceGas Holdings, LLC by Black Hills Utility Holdings
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.
WPSCWyoming Public Service Commission
WRDCWyodak Resources Development Corp., 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 June 30,Six Months Ended June 30,
 2019201820192018
 (in thousands, except per share amounts)
     
Revenue$333,888
$355,704
$931,698
$931,093
     
Operating expenses:    
Fuel, purchased power and cost of natural gas sold89,826
104,661
338,605
352,300
Operations and maintenance124,931
118,282
248,844
234,378
Depreciation, depletion and amortization51,595
48,709
102,623
97,299
Taxes - property and production13,142
13,976
26,661
27,276
Other operating expenses393
525
833
2,015
Total operating expenses279,887
286,153
717,566
713,268
     
Operating income54,001
69,551
214,132
217,825
     
Other income (expense):    
Interest charges -    
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)(36,058)(35,365)(72,032)(70,803)
Allowance for funds used during construction - borrowed1,397
511
2,355
644
Interest income396
320
695
630
Allowance for funds used during construction - equity127
242
175
310
Other income (expense), net137
(1,551)(700)(1,723)
Total other income (expense)(34,001)(35,843)(69,507)(70,942)
     
Income before income taxes20,000
33,708
144,625
146,883
Income tax benefit (expense)(2,307)(6,541)(19,570)19,261
Income from continuing operations17,693
27,167
125,055
166,144
Net (loss) from discontinued operations
(2,427)
(4,770)
Net income17,693
24,740
125,055
161,374
Net income attributable to noncontrolling interest(3,110)(2,823)(6,664)(6,453)
Net income available for common stock$14,583
$21,917
$118,391
$154,921
     
Amounts attributable to common shareholders:    
Net income from continuing operations$14,583
$24,344
$118,391
$159,691
Net (loss) from discontinued operations
(2,427)
(4,770)
Net income available for common stock$14,583
$21,917
$118,391
$154,921
     
Earnings (loss) per share of common stock, Basic -    
Earnings from continuing operations$0.24
$0.46
$1.97
$2.99
(Loss) from discontinued operations
(0.05)
(0.09)
Total earnings per share of common stock, Basic$0.24
$0.41
$1.97
$2.90
     
Earnings (loss) per share of common stock, Diluted -    
Earnings from continuing operations$0.24
$0.45
$1.96
$2.94
(Loss) from discontinued operations
(0.05)
(0.09)
Total earnings per share of common stock, Diluted$0.24
$0.40
$1.96
$2.85
     
Weighted average common shares outstanding:    
Basic60,467
53,355
60,195
53,337
Diluted60,606
54,520
60,333
54,361


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
June 30,
Six Months Ended
June 30,
 2019201820192018
 (in thousands)
     
Net income$17,693
$24,740
$125,055
$161,374
     
Other comprehensive income (loss), net of tax:    
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $5, $9, $10 and $19, respectively)(15)(35)(29)(70)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax of $(52), $(135), $(105), and $(271), respectively)169
487
336
973
Derivative instruments designated as cash flow hedges:    
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(172), $(152), $(335), and $(304), respectively)541
561
1,091
1,122
Net unrealized gains (losses) on commodity derivatives (net of tax of $119, $(18), $65 and $51, respectively)(399)30
(219)(198)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $19, $(45), $147 and $(190), respectively)(64)118
(490)594
Other comprehensive income, net of tax232
1,161
689
2,421
     
Comprehensive income17,925
25,901
125,744
163,795
Less: comprehensive income attributable to noncontrolling interest(3,110)(2,823)(6,664)(6,453)
Comprehensive income available for common stock$14,815
$23,078
$119,080
$157,342

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
 June 30, 2019 December 31, 2018
 (in thousands)
ASSETS   
Current assets:   
Cash and cash equivalents$6,642
 $20,776
Restricted cash3,602
 3,369
Accounts receivable, net166,513
 269,153
Materials, supplies and fuel102,830
 117,299
Derivative assets, current405
 1,500
Income tax receivable, net13,547
 12,978
Regulatory assets, current48,925
 48,776
Other current assets27,209
 29,982
Total current assets369,673
 503,833
    
Investments41,271
 41,013
    
Property, plant and equipment6,317,112
 6,000,015
Less: accumulated depreciation and depletion(1,224,600) (1,145,136)
Total property, plant and equipment, net5,092,512
 4,854,879
    
Other assets:   
Goodwill1,299,454
 1,299,454
Intangible assets, net13,867
 14,337
Regulatory assets, non-current234,124
 235,459
Other assets, non-current30,552
 14,352
Total other assets, non-current1,577,997
 1,563,602
    
TOTAL ASSETS$7,081,453
 $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
 June 30, 2019 December 31, 2018
 (in thousands, except share amounts)
LIABILITIES AND TOTAL EQUITY   
Current liabilities:   
Accounts payable$150,508
 $210,609
Accrued liabilities188,517
 215,501
Derivative liabilities, current1,491
 947
Regulatory liabilities, current39,642
 29,810
Notes payable102,500
 185,620
Current maturities of long-term debt5,743
 5,743
Total current liabilities488,401
 648,230
    
Long-term debt3,049,672
 2,950,835
    
Deferred credits and other liabilities:   
Deferred income tax liabilities, net343,207
 311,331
Regulatory liabilities, non-current514,914
 510,984
Benefit plan liabilities146,648
 145,147
Other deferred credits and other liabilities118,613
 109,377
Total deferred credits and other liabilities1,123,382
 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 61,091,385 and 60,048,567 shares, respectively61,091
 60,049
Additional paid-in capital1,522,208
 1,450,569
Retained earnings761,222
 700,396
Treasury stock, at cost – 25,359 and 44,253 shares, respectively(1,544) (2,510)
Accumulated other comprehensive income (loss)(26,227) (26,916)
Total stockholders’ equity2,316,750
 2,181,588
Noncontrolling interest103,248
 105,835
Total equity2,419,998
 2,287,423
    
TOTAL LIABILITIES AND TOTAL EQUITY$7,081,453
 $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)Six Months Ended June 30,
 20192018
Operating activities:(in thousands)
Net income$125,055
$161,374
Loss from discontinued operations, net of tax
4,770
Income from continuing operations125,055
166,144
Adjustments to reconcile net income to net cash provided by operating activities:  
Depreciation, depletion and amortization102,623
97,299
Deferred financing cost amortization4,219
3,694
Stock compensation7,093
5,221
Deferred income taxes21,935
(21,419)
Employee benefit plans5,683
6,911
Other adjustments, net8,991
4,884
Changes in certain operating assets and liabilities:  
Materials, supplies and fuel14,911
18,492
Accounts receivable, unbilled revenues and other operating assets99,925
50,711
Accounts payable and other operating liabilities(107,563)(96,394)
Regulatory assets - current16,116
55,637
Regulatory liabilities - current(6,348)19,990
Other operating activities, net(2,861)(1,372)
Net cash provided by operating activities of continuing operations289,779
309,798
Net cash provided by operating activities of discontinued operations
903
Net cash provided by operating activities289,779
310,701
   
Investing activities:  
Property, plant and equipment additions(317,686)(156,748)
Purchase of investment
(24,429)
Other investing activities389
(373)
Net cash provided by (used in) investing activities of continuing operations(317,297)(181,550)
Net cash provided by investing activities of discontinued operations
18,024
Net cash provided by (used in) investing activities(317,297)(163,526)
   
Financing activities:  
Dividends paid on common stock(60,952)(50,879)
Common stock issued71,759
1,074
Net (payments) borrowings of short-term debt(83,120)(89,500)
Long-term debt - issuances400,000

Long-term debt - repayments(302,871)(2,871)
Distributions to noncontrolling interest(9,251)(9,998)
Other financing activities(1,948)(1,527)
Net cash provided by (used in) financing activities13,617
(153,701)
Net change in cash, cash equivalents and restricted cash(13,901)(6,526)
Cash, cash equivalents and restricted cash at beginning of period24,145
18,240
Cash, cash equivalents and restricted cash at end of period$10,244
$11,714


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
          

 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
          


10




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 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 June 30, 2019 and December 31, 2018 financial information and are of a normal recurring nature. 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 six months ended June 30, 2019 and June 30, 2018, and our financial condition as of June 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.

11




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 fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. We are currently assessing the impacts of adopting this standard.


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.

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.




12




(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 six months ended June 30, 2019 and 2018. Sales tax and other similar taxes are excluded from revenues.

Three Months Ended June 30, 2019 Electric Utilities Gas Utilities
 Power Generation (a)
 MiningInter-company RevenuesTotal
Customer types:(in thousands)
Retail$139,732
$123,630
$
$12,428
$(7,041)$268,749
Transportation
28,623


(276)28,347
Wholesale6,781

15,062

(13,296)8,547
Market - off-system sales3,448
161


(1,335)2,274
Transmission/Other14,416
11,612


(4,199)21,829
Revenue from contracts with customers$164,377
$164,026
$15,062
$12,428
$(26,147)$329,746
Other revenues1,977
1,443
9,646
617
(9,541)4,142
Total revenues$166,354
$165,469
$24,708
$13,045
$(35,688)$333,888
       
Timing of revenue recognition:      
Services transferred at a point in time$
$
$
$12,428
$(7,041)$5,387
Services transferred over time164,377
164,026
15,062

(19,106)324,359
Revenue from contracts with customers$164,377
$164,026
$15,062
$12,428
$(26,147)$329,746
       

Three Months Ended June 30, 2018 Electric Utilities Gas Utilities
 Power Generation (a)
 MiningInter-company RevenuesTotal
Customer Types:      
Retail$145,377
$135,863
$
$16,345
$(7,979)$289,606
Transportation
29,011


(301)28,710
Wholesale8,191

13,603

(12,473)9,321
Market - Off-System Sales4,938
162


(1,660)3,440
Transmission/Other13,356
11,672


(3,644)21,384
Revenue from contracts with customers$171,862
$176,708
$13,603
$16,345
$(26,057)$352,461
Other Revenues1,754
912
9,141
554
(9,118)3,243
Total Revenues$173,616
$177,620
$22,744
$16,899
$(35,175)$355,704
       
Timing of Revenue Recognition:      
Services transferred at a point in time$
$
$
$16,345
$(7,978)$8,367
Services transferred over time171,862
176,708
13,603

(18,079)344,094
Revenue from Contracts with Customers$171,862
$176,708
$13,603
$16,345
$(26,057)$352,461
       

13



Six Months Ended June 30, 2019 Electric Utilities Gas Utilities
 Power Generation (a)
 Mining
Inter-company Revenues (a)
Total
Customer types:(in thousands)
Retail$293,195
$477,905
$
$28,257
$(15,169)$784,188
Transportation
73,140


(708)72,432
Wholesale15,124

30,531

(26,509)19,146
Market - off-system sales10,140
378


(3,559)6,959
Transmission/Other28,591
24,802


(8,402)44,991
Revenue from contracts with customers$347,050
$576,225
$30,531
$28,257
$(54,347)$927,716
Other revenues2,231
324
19,422
1,217
(19,212)3,982
Total revenues$349,281
$576,549
$49,953
$29,474
$(73,559)$931,698
       
Timing of revenue recognition:      
Services transferred at a point in time$
$
$
$28,257
$(15,169)$13,088
Services transferred over time347,050
576,225
30,531

(39,178)914,628
Revenue from contracts with customers$347,050
$576,225
$30,531
$28,257
$(54,347)$927,716
       




Six Months Ended June 30, 2018 Electric Utilities Gas Utilities
 Power Generation (a)
 Mining
Inter-company Revenues (a)
Total
Customer Types:      
Retail$292,434
$477,257
$
$32,902
$(15,821)$786,772
Transportation
70,681


(710)69,971
Wholesale17,241

28,371

(25,521)20,091
Market - Off-System Sales9,082
589


(4,182)5,489
Transmission/Other26,427
24,341


(7,275)43,493
Revenue from contracts with customers$345,184
$572,868
$28,371
$32,902
$(53,509)$925,816
Other Revenues1,987
2,096
18,311
1,125
(18,242)5,277
Total Revenues$347,171
$574,964
$46,682
$34,027
$(71,751)$931,093
       
Timing of Revenue Recognition:      
Services transferred at a point in time$
$
$
$32,902
$(15,820)$17,082
Services transferred over time345,184
572,868
28,371

(37,689)908,734
Revenue from contracts with customers$345,184
$572,868
$28,371
$32,902
$(53,509)$925,816
       

(a)Due to the changes in our segment disclosures discussed in Note 3, Power Generation Wholesale revenue was revised for the three and six months ended June 30, 2018, which resulted in an increase of $0.9 million and $1.7 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.




14



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.

(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 requires 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 by 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 adjustments 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 June 30, 2019External Operating Revenue Inter-company Operating Revenue  Total Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:       
Electric Utilities$159,140
$1,977

$5,237
$

$166,354
Gas Utilities163,303
1,443

723


165,469
Power Generation (a)
1,765
434

13,297
9,212

24,708
Mining5,538
288

6,890
329

13,045
Inter-company eliminations (a)


 (26,147)(9,541) (35,688)
Total$329,746
$4,142
 $
$
 $333,888
        
Three Months Ended June 30, 2018External Operating Revenue Inter-company Operating Revenue  Total Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:       
Electric Utilities$166,565
$1,754
 $5,297
$
 $173,616
Gas Utilities176,399
912
 309

 177,620
Power Generation (a)
1,130
348
 12,473
8,793
 22,744
Mining8,367
229
 7,978
325
 16,899
Inter-company eliminations (a)


 (26,057)(9,118) (35,175)
Total$352,461
$3,243
 $
$
 $355,704

15



Six Months Ended June 30, 2019
External Operating
Revenue
 Inter-company Operating Revenue Total Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:       
Electric Utilities$335,803
$2,231
 $11,247
$
 $349,281
Gas Utilities574,803
324
 1,422

 576,549
Power Generation (a)
4,022
870
 26,509
18,552
 49,953
Mining13,088
557
 15,169
660
 29,474
Inter-company eliminations (a)


 (54,347)(19,212) (73,559)
Total$927,716
$3,982
 $
$
 $931,698
        
Six Months Ended June 30, 2018External Operating Revenue Inter-company Operating Revenue  Total Revenues
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:       
Electric Utilities$333,743
$1,987
 $11,441
$
 $347,171
Gas Utilities572,141
2,096
 727

 574,964
Power Generation (a)
2,850
718
 25,521
17,593
 46,682
Mining17,082
476
 15,820
649
 34,027
Inter-company eliminations (a)


 (53,509)(18,242) (71,751)
Total$925,816
$5,277
 $
$
 $931,093


(a)Due to the changes in our segment disclosures, Power Generation Inter-company Operating Revenue for Contract Customers was revised for the three and six months ended June 30, 2018 which resulted in an increase of $0.9 million and $1.7 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.

16



     
 Three Months Ended June 30,Six Months Ended June 30,
 2019201820192018
Adjusted operating income:    
Electric Utilities (a)
$33,546
$41,200
$74,566
$79,680
Gas Utilities8,557
16,485
111,871
111,928
Power Generation (a)
10,156
8,877
22,123
20,652
Mining1,640
3,825
5,977
8,096
Corporate and Other (a)
102
(836)(405)(2,531)
Operating income54,001
69,551
214,132
217,825
     
Interest expense, net(34,265)(34,534)(68,982)(69,529)
Other income (expense), net264
(1,309)(525)(1,413)
Income tax benefit (expense) (b)
(2,307)(6,541)(19,570)19,261
Income from continuing operations17,693
27,167
125,055
166,144
Net (loss) from discontinued operations
(2,427)
(4,770)
Net income17,693
24,740
125,055
161,374
Net income attributable to noncontrolling interest(3,110)(2,823)(6,664)(6,453)
Net income available for common stock$14,583
$21,917
$118,391
$154,921
___________
(a)Due to the changes in our segment disclosures, Adjusted operating income was revised for the three and six months ended June 30, 2018, which resulted in an increase (decrease) as follows (in millions):
SegmentThree Months Ended June 30, 2018Six Months Ended June 30, 2018
Electric Utilities$1.6
$3.3
Power Generation(1.4)(3.0)
Corporate and Other(0.2)(0.3)
 $
$


(b)
Income tax benefit (expense) for the six months ended June 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:June 30, 2019 December 31, 2018
Segment:   
Electric Utilities (a)
$2,777,803
 $2,707,695
Gas Utilities3,645,840
 3,623,475
Power Generation (a)
379,140
 342,085
Mining62,491
 80,594
Corporate and Other216,179
 209,478
Total assets$7,081,453
 $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.


17



(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
June 30, 2019Receivable, TradeRevenue Doubtful AccountsReceivable, net
Electric Utilities$39,982
$31,573
$(526)$71,029
Gas Utilities67,686
23,753
(4,391)87,048
Power Generation2,867


2,867
Mining2,505


2,505
Corporate3,233

(169)3,064
Total$116,273
$55,326
$(5,086)$166,513

 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

     



18



(5)    REGULATORY ACCOUNTING

We had the following regulatory assets and liabilities (in thousands) as of:
 June 30, 2019December 31, 2018
Regulatory assets  
Deferred energy and fuel cost adjustments (a)
$34,257
$29,661
Deferred gas cost adjustments (a)
2,342
3,362
Gas price derivatives (a)
3,945
6,201
Deferred taxes on AFUDC (b)
7,716
7,841
Employee benefit plans (c)
109,899
110,524
Environmental (a)
931
959
Loss on reacquired debt (a)
20,140
21,001
Renewable energy standard adjustment (a)
1,994
1,722
Deferred taxes on flow through accounting (c)
36,552
31,044
Decommissioning costs (b)
11,518
11,700
Gas supply contract termination (a)
11,413
14,310
Other regulatory assets (a)
42,342
45,910
Total regulatory assets283,049
284,235
Less current regulatory assets(48,925)(48,776)
Regulatory assets, non-current$234,124
$235,459
   
Regulatory liabilities  
Deferred energy and gas costs (a)
$16,808
$6,991
Employee benefit plan costs and related deferred taxes (c)
41,814
42,533
Cost of removal (a)
158,477
150,123
Excess deferred income taxes (c)
307,871
310,562
TCJA revenue reserve11,436
18,032
Other regulatory liabilities (c)
18,150
12,553
Total regulatory liabilities554,556
540,794
Less current regulatory liabilities(39,642)(29,810)
Regulatory liabilities, non-current$514,914
$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.

Regulatory Activity

Renewable Ready Service Tariffs and Corriedale Wind Energy Project

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 and industrial customers and governmental agencies. The project is expected to be in service in 2020.




19





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 Gas

On June 13, 2019, we received approval from the WPSC for a request 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, and Wyoming Gas (Northwest Wyoming) will be 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 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 safety and integrity investments in its system.

Blockchain Interruptible Service Tariff

On April 30, 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.

Nebraska

On March 29, 2019, Nebraska Gas filed an application with the NPSC requesting approval to merge its two gas distribution companies in Nebraska. A rate review is expected to be filed in 2020 to consolidate the rates, tariffs and services of its two existing natural gas distribution companies.

Colorado

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 safety and integrity investments in its system.


(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:
 June 30, 2019 December 31, 2018
Materials and supplies$80,639
 $75,081
Fuel - Electric Utilities2,350
 2,850
Natural gas in storage held for distribution19,841
 39,368
Total materials, supplies and fuel$102,830
 $117,299





20



(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 June 30, Six Months Ended June 30,
 20192018 20192018
      
Net income available for common stock$14,583
$21,917
 $118,391
$154,921
      
Weighted average shares - basic60,467
53,355
 60,195
53,337
Dilutive effect of:     
Equity Units (a)

1,057
 
904
Equity compensation139
108
 138
120
Weighted average shares - diluted60,606
54,520
 60,333
54,361

__________
(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 June 30, Six Months Ended June 30,
 20192018 20192018
      
Equity compensation
15
 
17
Anti-dilutive shares
15
 
17



21




(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:
 June 30, 2019December 31, 2018
 Balance OutstandingLetters of CreditBalance OutstandingLetters of Credit
Revolving Credit Facility$
$10,429
$
$22,311
CP Program102,500

185,620

Total$102,500
$10,429
$185,620
$22,311


Our $750 million corporate Revolving Credit Facility extends through July 30, 2023 with two, 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 June 30, 2019. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at June 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 payments under the CP Program during the six months ended June 30, 2019 were $83 million. At June 30, 2019, the weighted average interest rate on CP Program borrowings was 2.60%.

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 June 30, 2019, we were in compliance with these covenants.

Long-Term Debt

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 has 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. The interest cost associated with this term loan is 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 and Eurodollar borrowings were 0.000% and 0.700%, respectively, at June 30, 2019.




22



(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 June 30, 2019, we issued a total of 658,598 shares of common stock under the ATM equity offering program for proceeds of $49 million, net of $0.5 million in commissions. During the six months ended June 30, 2019, we issued a total of 939,095 shares of common stock under the ATM equity offering program for proceeds of $69 million, net of $0.7 million in commissions. As of June 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 guarantees, 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.



23



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 July 2019 through May 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.

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:
 June 30, 2019 December 31, 2018
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
Natural gas futures purchased2,480,000
 18 4,000,000
 24
Natural gas options purchased, net2,160,000
 9 4,320,000
 13
Natural gas basis swaps purchased2,360,000
 18 3,960,000
 24
Natural gas over-the-counter swaps, net (b)
6,020,000
 23 3,660,000
 24
Natural gas physical contracts, net (c)
1,717,075
 9 18,325,852
 30

__________
(a)Term reflects the maximum forward period hedged.
(b)As of June 30, 2019, 2,130,000 MMBtus were designated as cash flow hedges.
(c)Volumes exclude contracts that qualify for the normal purchase, normal sales exception.

Based on June 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 June 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 six months ended June 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 June 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 83
Total   $(630)


24



Three Months Ended June 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 $(713)
Commodity derivatives Fuel, purchased power and cost of natural gas sold (163)
Total   $(876)

Six Months Ended June 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 $(1,426)
Commodity derivatives Fuel, purchased power and cost of natural gas sold 637
Total   $(789)

Six Months Ended June 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 $(1,426)
Commodity derivatives Fuel, purchased power and cost of natural gas sold (784)
Total   $(2,210)

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 six months ended June 30, 2019 and 2018.
    
 Three Months Ended June 30,
 2019 2018
 (in thousands)
Increase (decrease) in fair value:   
Forward commodity contracts$(518) $48
Recognition of (gains) losses in earnings due to settlements:   
Interest rate swaps713
 713
Forward commodity contracts(83) 163
Total other comprehensive income (loss) from hedging$112
 $924

25



 Six Months Ended June 30,
 2019 2018
 (in thousands)
Increase (decrease) in fair value:   
Forward commodity contracts$(284) $(249)
Recognition of (gains) losses in earnings due to settlements:   
Interest rate swaps1,426
 1,426
Forward commodity contracts(637) 784
Total other comprehensive income (loss) from hedging$505
 $1,961

Derivatives Not Designated as Hedge Instruments

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Condensed Consolidated Statements of Income for the three and six months ended June 30, 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 June 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$(1,185) $771
  $(1,185) $771

  Six Months Ended June 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$(1,160) $1,025
  $(1,160) $1,025


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 $3.9 million and $6.2 million for June 30, 2019 and December 31, 2018, respectively.



26



(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 component 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.

Recurring Fair Value Measurements

 As of June 30, 2019
 Level 1Level 2Level 3 
Cash Collateral and Counterparty
Netting
Total
 (in thousands)
Assets:      
Commodity derivatives — Utilities$
$986
$
 $(575)$411
Total$
$986
$
 $(575)$411
       
Liabilities:      
Commodity derivatives — Utilities$
$5,567
$
 $(3,945)$1,622
Total$
$5,567
$
 $(3,945)$1,622



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 June 30, 2019December 31, 2018
Derivatives designated as hedges:    
Asset derivative instruments:    
Current commodity derivativesDerivative assets — current $
$415
Noncurrent commodity derivativesOther assets, non-current 4
18
Liability derivative instruments:    
Current commodity derivativesDerivative liabilities — current (449)(114)
Noncurrent commodity derivativesOther deferred credits and other liabilities (58)(4)
Total derivatives designated as hedges  $(503)$315
     
Derivatives not designated as hedges:    
Asset derivative instruments:    
Current commodity derivativesDerivative assets — current $405
$1,085
Noncurrent commodity derivativesOther assets, non-current 2
1
Liability derivative instruments:    
Current commodity derivativesDerivative liabilities — current (1,042)(833)
Noncurrent commodity derivativesOther deferred credits and other liabilities (73)(56)
Total derivatives not designated as hedges  $(708)$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:
 June 30, 2019 December 31, 2018
 
Carrying
Amount
Fair Value 
Carrying
Amount
Fair Value
Long-term debt, including current maturities (a) (b)
$3,055,415
$3,337,314
 $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, net of tax (in thousands):
 Location on the Condensed Consolidated Statements of IncomeAmount Reclassified from AOCI
Three Months Ended Six Months Ended
June 30, 2019June 30, 2018 June 30, 2019June 30, 2018
Gains and (losses) on cash flow hedges:      
Interest rate swapsInterest expense$(713)$(713) $(1,426)$(1,426)
Commodity contracts
Fuel, purchased power and cost of natural gas sold

83
(163) 637
(784)
  (630)(876) (789)(2,210)
Income taxIncome tax benefit (expense)153
197
 188
494
Total reclassification adjustments related to cash flow hedges, net of tax $(477)$(679) $(601)$(1,716)
       
Amortization of components of defined benefit plans:      
Prior service costOperations and maintenance$20
$44
 $39
$89
       
Actuarial gain (loss)Operations and maintenance(221)(622) (441)(1,244)
  (201)(578) (402)(1,155)
Income taxIncome tax benefit (expense)47
126
 95
252
Total reclassification adjustments related to defined benefit plans, net of tax $(154)$(452) $(307)$(903)
Total reclassifications $(631)$(1,131) $(908)$(2,619)


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
(219)
(219)
Amounts reclassified from AOCI1,091
(490)307
908
As of June 30, 2019$(16,216)$(381)$(9,630)$(26,227)
     
     
 Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
Balance as of December 31, 2017$(19,581)$(518)$(21,103)$(41,202)
Other comprehensive income (loss)    
before reclassifications
(198)
(198)
Amounts reclassified from AOCI1,122
594
903
2,619
Reclassifications of certain tax effects from AOCI15

3
18
As of June 30, 2018$(18,444)$(122)$(20,197)$(38,763)



(14)    SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Six Months EndedJune 30, 2019 June 30, 2018
 (in thousands)
Non-cash investing and financing activities —   
Property, plant and equipment acquired with accrued liabilities$83,486
 $37,168
    
Cash (paid) refunded during the period —   
Interest (net of amounts capitalized)$(67,624) $(67,119)
Income taxes$1,790
 $(14,837)




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 June 30, Six Months Ended June 30,
 20192018 20192018
Service cost$1,345
$1,709
 $2,691
$3,417
Interest cost4,344
3,868
 8,687
7,735
Expected return on plan assets(6,100)(6,185) (12,200)(12,370)
Prior service cost7
14
 13
29
Net loss (gain)940
2,157
 1,881
4,315
Net periodic benefit cost$536
$1,563
 $1,072
$3,126


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 June 30, Six Months Ended June 30,
 20192018 20192018
Service cost$454
$572
 $908
$1,145
Interest cost563
521
 1,123
1,042
Expected return on plan assets(58)(56) (115)(113)
Prior service cost (benefit)(100)(99) (199)(198)
Net loss (gain)
54
 
108
Net periodic benefit cost$859
$992
 $1,717
$1,984


Supplemental Non-qualified Defined Benefit and Defined Contribution Plans

The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands):
 Three Months Ended June 30, Six Months Ended June 30,
 20192018 20192018
Service cost$692
$435
 $1,977
$715
Interest cost324
292
 648
585
Prior service cost1
1
 1
1
Net loss (gain)134
250
 268
500
Net periodic benefit cost$1,151
$978
 $2,894
$1,801



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 June 30, 2019Six Months Ended June 30, 2019Anticipated for 2019Anticipated for 2020
Defined Benefit Pension Plan$
$
$12,700
$12,700
Non-pension Defined Benefit Postretirement Healthcare Plans$1,108
$2,217
$2,217
$4,271
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans$366
$732
$732
$1,562


(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.

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 is 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 (in thousands):
2019$1,831
2020$5,490
2021$5,475
2022$5,475
2023$5,475
Thereafter$2,729




(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.




32



(18)    INCOME TAXES

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

Income tax benefit (expense) for the three months ended June 30, 2019 was $(2.3) million compared to $(6.5) million reported for the same period in 2018. The decrease is driven by a lower 2019 forecasted annual effective tax rate primarily due to an increase of federal production tax credits and related state investment credits associated with new wind assets; and a current year $1.6 million flow-through discrete tax benefit related to repair costs and certain indirect costs.


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

Income tax benefit (expense) for the six months ended June 30, 2019 was $(20) million compared to $19 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 $(2.3) million income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes.

For the six months ended June 30, 2019 the effective tax rate was 13.5% compared to 19.0% excluding the legal entity restructuring and tax reform adjustments, for the same period in 2018. The lower effective tax rate is primarily due to $3.5 million of federal production tax credits and related state investment credits associated with new wind assets, a $1.7 million tax benefit for deferred tax amortization related to tax reform and a $1.6 million flow-through discrete tax benefit related to repair costs and certain indirect costs.


(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:
 June 30, 2019December 31, 2018
Accrued employee compensation, benefits and withholdings$50,996
$63,742
Accrued property taxes34,966
42,510
Customer deposits and prepayments40,716
43,574
Accrued interest and contract adjustment payments32,213
31,759
CIAC current portion1,485
1,485
Other (none of which is individually significant)28,141
32,431
Total accrued liabilities$188,517
$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 June 30, 2019Six Months Ended June 30, 2019
Operating lease costOperations and maintenance$385
$696
Finance lease cost:   
Amortization of right-of-use assetDepreciation, depletion and amortization27
44
Interest on lease liabilitiesInterest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)6
9
Total lease cost $418
$749




Supplemental balance sheet information related to leases was as follows (in thousands):
 Balance Sheet LocationAs of June 30, 2019
Assets:  
Operating lease assetsOther assets, non-current$5,161
Finance lease assetsOther assets, non-current521
Total lease assets $5,682
   
Liabilities:  
Current:  
Operating leasesAccrued liabilities$1,003
Finance leaseAccrued liabilities106
   
Noncurrent:  
Operating leasesOther deferred credits and other liabilities4,470
Finance leaseOther deferred credits and other liabilities419
Total lease liabilities $5,998


Supplemental cash flow information related to leases was as follows (in thousands):
 Six Months Ended June 30, 2019
Cash paid included in the measurement of lease liabilities: 
Operating cash flows from operating leases$528
Operating cash flows from finance lease$9
Financing cash flows from finance lease$40
Right-of-use assets obtained in exchange for lease obligations: 
Operating leases$2,738
Finance lease$67



34



 As of June 30, 2019
Weighted average remaining lease term (years): 
Operating leases8 years
Finance lease5 years
  
Weighted average discount rate: 
Operating leases4.25%
Finance lease4.20%


As of June 30, 2019, scheduled maturities of lease liabilities for future years were as follows (in thousands):
 Operating LeasesFinance LeaseTotal
2019 (a)
$705
$63
$768
2020976
126
1,102
2021858
126
984
2022736
126
862
2023708
126
834
Thereafter2,654
10
2,664
Total lease payments (b)
$6,637
$577
$7,214
Less imputed interest1,164
52
1,216
Present value of lease liabilities$5,473
$525
$5,998

(a)Includes lease liabilities for the remaining six 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


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 June 30, 2019Six Months Ended June 30, 2019
Operating lease incomeRevenue$567
$1,205



35




As of June 30, 2019, scheduled maturities of lease receivables for future years were as follows (in thousands):
 Operating Leases
2019 (a)
$1,085
20202,010
20211,843
20221,793
20231,799
Thereafter55,481
Total lease receivables$64,011

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

(21)     SUBSEQUENT EVENTS

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 deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and continuing for 20 years. A decision from FERC is expected by the end of 2019.


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 regulatory-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 produces 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 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 six months ended June 30, 2019 and 2018, and our financial condition as of June 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 57.


36



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.

Results of Operations

Executive Summary, Significant Events and Overview

 Three Months Ended June 30, Six Months Ended June 30,
 2019 2018 2019 2018
(in millions, except per share amounts)IncomeEPS IncomeEPS IncomeEPS IncomeEPS
            
Net income from continuing operations available for common stock$14.6
$0.24
 $24.3
$0.45
 $118.4
$1.96
 $159.7
$2.94
Net (loss) from discontinued operations

 (2.4)(0.05) 

 (4.8)(0.09)
Net income available for common stock$14.6
$0.24
 $21.9
$0.40
 $118.4
$1.96
 $154.9
$2.85

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

The variance to the prior year included the following:

Electric Utilities’ adjusted operating income decreased $7.7 million primarily due to cooler spring weather compared to prior year and higher operating expenses driven by outside services and employee costs;
Gas Utilities’ adjusted operating income decreased $7.9 million primarily due to direct and indirect impacts from significant rainfall and flooding in our service territories and higher operating expenses driven by outside services and employee costs;
Power Generation’s adjusted operating income increased $1.3 million primarily due to higher revenue from increased wind MWh sold and higher power purchase agreement prices partially offset by higher depreciation from new wind assets;
Mining’s adjusted operating income decreased $2.2 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 $0.9 million primarily due to prior year expenses related to the oil and gas segment that were not reclassified to discontinued operations; and
A current year $1.6 million flow-through discrete tax benefit related to repair costs and certain indirect costs.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018.

The variance to the prior year included the following:

Electric Utilities’ adjusted operating income decreased $5.1 million primarily due to cooler spring weather compared to prior year and higher operating expenses driven by outside services and employee costs;
Gas Utilities’ adjusted operating income decreased $0.1 million primarily due to higher operating expenses driven by outside services and employee costs offset by new rates and favorable winter weather compared to prior year;
Power Generation’s adjusted operating income increased $1.5 million primarily due to higher revenue from increased wind MWh sold partially offset by higher depreciation from new wind assets;
Mining’s adjusted operating income decreased $2.1 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 $2.1 million primarily due to prior year expenses related to the oil and gas segment that were not reclassified to discontinued operations;
A prior year $49 million tax benefit resulting from legal entity restructuring partially offset by a prior year $2.3 million income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes; and
A lower current year effective tax rate primarily due to $3.5 million of federal production tax credits and related state investment credits associated with new wind assets, a $1.7 million tax benefit for deferred tax amortization related to tax reform and a $1.6 million flow-through discrete tax benefit related to repair costs and certain indirect costs.



37



The following table summarizes select financial results by operating segment and details significant items (in thousands):
 Three Months Ended June 30,Six Months Ended June 30,
 20192018Variance20192018Variance
Revenue      
Revenue$369,576
$390,879
$(21,303)$1,005,257
$1,002,844
$2,413
Inter-company eliminations(35,688)(35,175)(513)(73,559)(71,751)(1,808)
 $333,888
$355,704
$(21,816)$931,698
$931,093
$605
Adjusted operating income (a)
      
Electric Utilities$33,546
$41,200
$(7,654)$74,566
$79,680
$(5,114)
Gas Utilities8,557
16,485
(7,928)111,871
111,928
(57)
Power Generation10,156
8,877
1,279
22,123
20,652
1,471
Mining1,640
3,825
(2,185)5,977
8,096
(2,119)
Corporate and Other102
(836)938
(405)(2,531)2,126
Operating income54,001
69,551
(15,550)214,132
217,825
(3,693)
   
   
Interest expense, net(34,265)(34,534)269
(68,982)(69,529)547
Other income (expense), net264
(1,309)1,573
(525)(1,413)888
Income tax benefit (expense)(2,307)(6,541)4,234
(19,570)19,261
(38,831)
Income from continuing operations17,693
27,167
(9,474)125,055
166,144
(41,089)
Net (loss) from discontinued operations
(2,427)2,427

(4,770)4,770
Net income17,693
24,740
(7,047)125,055
161,374
(36,319)
Net income attributable to noncontrolling interest(3,110)(2,823)(287)(6,664)(6,453)(211)
Net income available for common stock$14,583
$21,917
$(7,334)$118,391
$154,921
$(36,530)
__________
(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

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.

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 and industrial customers and governmental agencies. The project is expected to be in service in 2020.

38




Electric Utilities experienced cooler spring weather during the three and six months ended June 30, 2019 compared to the same periods in 2018. Cooling degree days for the three and six months ended June 30, 2019 were 38% lower than normal compared to 109% higher than normal for the same periods in 2018.

Heating degree days for the three and six months ended June 30, 2019 were 12% and 8% higher than normal, compared to 12% lower and 7% higher than normal for the same periods in 2018.

South Dakota Electric continued construction on a 175-mile electric transmission line from Rapid City, South Dakota, to Stegall, Nebraska. The 94-mile final segment of the transmission line is expected to be in service in the fall of 2019.


Gas Utilities Segment

Gas Utilities experienced colder winter and spring weather during the three and six months ended June 30, 2019 compared to the same periods in 2018. Heating degree days for the three and six months ended June 30, 2019 were 5% and 10% higher than normal, compared to 1% lower and 1% higher than normal for the same periods in 2018.

Regulatory activity:

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 also 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 safety and integrity investments in its system. See Note 5 of the Notes to Condensed Consolidated Financial Statements for additional details.

On March 29, 2019, Nebraska Gas filed an application with the NPSC requesting approval to merge its two natural gas distribution companies in Nebraska. A rate review is expected to be filed in 2020 to consolidate the rates, tariffs and services of its two existing natural gas distribution companies.

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 also requests $2.5 million in new revenue to recover costs and investments in safety, reliability and system integrity. Colorado Gas is also requesting a new rider mechanism to recover safety and integrity investments in its system.

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. The pipeline is expected to be in service in late 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 deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and continuing for 20 years. A decision from FERC is expected later this year.

On March 11, 2019, Black Hills Electric Generation commenced construction on the $71 million, 60 MW Busch Ranch II Wind Farm. The wind generation project remains on schedule to be in service in the fall of 2019.



39



Corporate and Other

On July 23, 2019, Fitch affirmed South Dakota Electric’s credit rating at A.

During the six months ended June 30, 2019, we issued a total of 939,095 shares of common stock under the ATM equity offering program for net proceeds of $69 million.

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 on substantially similar terms and covenants. The net proceeds were used to pay down short-term debt.

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.


40



Electric Utilities

 Three Months Ended June 30,Six Months Ended June 30,
 20192018Variance20192018Variance
 (in thousands)
Revenue$166,354
$173,616
$(7,262)$349,281
$347,171
$2,110
       
Total fuel and purchased power62,128
65,942
(3,814)135,411
134,680
731
       
Gross margin (non-GAAP)104,226
107,674
(3,448)213,870
212,491
1,379
       
Operations and maintenance48,734
45,101
3,633
95,878
90,194
5,684
Depreciation and amortization21,947
21,373
574
43,427
42,617
810
Total operating expenses70,681
66,474
4,207
139,305
132,811
6,494
       
Adjusted operating income (a)
$33,545
$41,200
$(7,655)$74,565
$79,680
$(5,115)
________________
(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 six months ended June 30, 2018, which resulted in an increase of $1.6 million and $3.3 million, respectively.

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

Gross margin for the three months ended June 30, 2019 decreased as a result of the following:
 (in millions)
Weather$(2.5)
Lower commercial demand(1.8)
Lower residential customer usage(1.5)
Reduction in purchased power capacity charges1.6
Rider recovery0.2
Other0.6
Total decrease in Gross margin (non-GAAP)$(3.4)

Operations and maintenance increased primarily due to $1.5 million of higher employee costs driven by additional headcount and $1.2 million of higher outside services expenses. Various other expenses comprise the remainder of the increase compared to the same period in the prior year.



41



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

Gross margin for the six months ended June 30, 2019 increased as a result of the following:
 (in millions)
Reduction in purchased power capacity charges$3.2
Higher off-system power marketing and ancillary wheeling0.7
Rider recovery0.7
Weather(1.9)
Lower commercial demand(1.9)
Lower residential customer usage(1.4)
Other2.0
Total increase in Gross margin (non-GAAP)$1.4

Operations and maintenance increased primarily due to $2.8 million of higher outside services expenses and $2.6 million of higher employee costs driven by additional headcount.


Operating Statistics
  Electric Revenue (in thousands) Quantities sold (MWh)
  Three Months Ended
June 30,
Six Months Ended
June 30,
 Three Months Ended
June 30,
Six Months Ended
June 30,
  2019201820192018 2019201820192018
Residential $45,700
$50,116
$103,338
$105,857
 301,481
328,638
690,659
711,908
Commercial 59,739
64,902
120,702
126,886
 490,329
509,984
995,902
1,010,120
Industrial 31,697
31,220
64,137
62,020
 445,837
418,596
872,451
819,305
Municipal 4,253
4,666
8,392
8,807
 38,283
42,657
74,919
78,981
Subtotal Retail Revenue - Electric 141,389
150,904
296,569
303,570
 1,275,930
1,299,875
2,633,931
2,620,314
Contract Wholesale 6,781
8,191
15,124
17,241
 194,222
218,132
417,242
455,836
Off-system/Power Marketing Wholesale 3,448
4,939
10,140
9,083
 135,091
178,854
275,941
307,895
Other 14,736
9,582
27,448
17,277
 



Total Revenue and Energy Sold 166,354
173,616
349,281
347,171
 1,605,243
1,696,861
3,327,114
3,384,045
Other Uses, Losses or Generation, net 



 89,866
125,606
186,866
216,461
Total Revenue and Energy 166,354
173,616
349,281
347,171
 1,695,109
1,822,467
3,513,980
3,600,506
Less cost of fuel and purchased power (a)
 62,128
65,942
135,411
134,680
     
Gross Margin (non-GAAP) (a)
 $104,226
$107,674
$213,870
$212,491
     
________________
(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 six months ended June 30, 2018, which resulted in an increase of $1.7 million and $3.3 million, respectively. There were corresponding decreases to Gross margin for each period.


42



          
Three Months Ended June 30, Electric Revenue (in thousands) Gross Margin (non-GAAP) (in thousands) 
Quantities Sold (MWh) (a)
  20192018 20192018 20192018
Colorado Electric (b)
 $55,412
$62,532
 $31,051
$35,801
 485,346
542,528
South Dakota Electric 69,246
70,676
 50,865
49,922
 757,640
837,943
Wyoming Electric 41,696
40,408
 22,310
21,951
 452,123
441,996
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold $166,354
$173,616
 $104,226
$107,674
 1,695,109
1,822,467
          
  Electric Revenue (in thousands) Gross Margin (non-GAAP) (in thousands) 
Quantities Sold (MWh) (a)
Six Months Ended June 30, 20192018 20192018 20192018
Colorado Electric (b)
 $115,259
$120,885
 $62,495
$67,547
 977,028
1,029,528
South Dakota Electric 148,287
144,491
 107,173
101,298
 1,602,641
1,666,120
Wyoming Electric 85,735
81,795
 44,202
43,646
 934,311
904,858
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold $349,281
$347,171
 $213,870
$212,491
 3,513,980
3,600,506
________________
(a)Total MWh for 2019 includes Other Uses, Losses or Generation, net, which are approximately 5%, 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 six months ended June 30, 2018, which resulted in a decrease of $(1.7) million and $(3.3) million, respectively.

 Three Months Ended
June 30,
Six Months Ended
June 30,
Quantities Generated and Purchased (MWh)2019201820192018
     
Coal-fired471,840
568,733
1,057,135
1,164,333
Natural Gas and Oil86,475
105,304
211,132
146,627
Wind56,505
68,501
111,924
142,482
Total Generated614,820
742,538
1,380,191
1,453,442
Purchased1,080,289
1,079,929
2,133,789
2,147,064
Total Generated and Purchased1,695,109
1,822,467
3,513,980
3,600,506

 Three Months Ended
June 30,
Six Months Ended
June 30,
Quantities Generated and Purchased (MWh)2019201820192018
Generated:    
Colorado Electric91,886
132,927
192,416
224,975
South Dakota Electric315,925
411,839
773,294
824,033
Wyoming Electric207,009
197,772
414,481
404,434
Total Generated614,820
742,538
1,380,191
1,453,442
Purchased:    
Colorado Electric393,460
409,601
784,612
804,553
South Dakota Electric441,715
426,104
829,347
842,087
Wyoming Electric245,114
244,224
519,830
500,424
Total Purchased1,080,289
1,079,929
2,133,789
2,147,064
     
Total Generated and Purchased1,695,109
1,822,467
3,513,980
3,600,506


43



          
 Three Months Ended June 30,
Degree Days  2019   2018
 Actual 
Variance from
Normal
 Actual Variance to Prior Year Actual 
Variance from
Normal
Heating Degree Days:         
Colorado Electric603
 (5)% 31% 460
 (27)%
South Dakota Electric1,279
 25 % 23% 1,037
 1 %
Wyoming Electric1,359
 12 % 29% 1,053
 (14)%
Combined (a)
986
 12 % 27% 777
 (12)%
          
Cooling Degree Days:         
Colorado Electric147
 (30)% (70)% 494
 136 %
South Dakota Electric38
 (62)% (71)% 132
 33 %
Wyoming Electric29
 (42)% (72)% 102
 104 %
Combined (a)
86
 (38)% (71)% 292
 109 %

 Six Months Ended June 30,
 2019   2018
Heating Degree DaysActual 
Variance from
Normal
 Actual Variance to Prior Year Actual 
Variance from
Normal
          
Colorado Electric3,152
 (4)% 10% 2,866
 12 %
South Dakota Electric5,195
 23 % 10% 4,736
 12 %
Wyoming Electric4,557
 3 % 13% 4,037
 (9)%
Combined (a)
4,132
 8 % 10% 3,741
 7 %
          
Cooling Degree Days:         
Colorado Electric147
 (30)% (70)% 494
 136 %
South Dakota Electric38
 (62)% (71)% 132
 33 %
Wyoming Electric29
 (42)% (72)% 102
 104 %
Combined (a)
86
 (38)% (71)% 292
 109 %
__________
(a)Combined actuals are calculated based on the weighted average number of total customers by state.

Electric Utilities Power Plant AvailabilityThree Months Ended June 30,Six Months Ended June 30,
 2019201820192018
Coal-fired plants (a)
79.2%91.2%87.7%93.1%
Natural gas-fired plants and Other plants (b)
89.3%98.1%90.0%97.2%
Wind94.5%96.7%95.6%96.9%
Total availability86.4%95.8%89.7%95.9%
     
Wind capacity factor34.8%41.7%38.7%46.1%
__________
(a)2019 included planned outages at Neil Simpson II and Wygen III and unplanned outages at Wyodak Plant.
(b)2019 included planned outages at Neil Simpson CT and Lange CT.



44




Gas Utilities
 Three Months Ended June 30,Six Months Ended June 30,
 20192018Variance20192018Variance
 (in thousands)
Revenue:      
Natural gas - regulated$149,942
$161,212
$(11,270)$533,817
$531,480
$2,337
Other - non-regulated services15,527
16,408
(881)42,732
43,484
(752)
Total revenue165,469
177,620
(12,151)576,549
574,964
1,585
       
Cost of sales:      
Natural gas - regulated51,108
62,453
(11,345)252,158
267,537
(15,379)
Other - non-regulated services5,876
5,601
275
12,105
10,202
1,903
Total cost of sales56,984
68,054
(11,070)264,263
277,739
(13,476)
       
Gross margin (non-GAAP)108,485
109,566
(1,081)312,286
297,225
15,061
       
Operations and maintenance77,130
71,667
5,463
155,068
142,573
12,495
Depreciation and amortization22,797
21,414
1,383
45,346
42,724
2,622
Total operating expenses99,927
93,081
6,846
200,414
185,297
15,117
       
Adjusted operating income$8,558
$16,485
$(7,927)$111,872
$111,928
$(56)


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

Gross margin for the three months ended June 30, 2019 decreased as a result of:
 (in millions)
Weather (a)
$(2.4)
Lower mark-to-market on non-utility natural gas commodity contracts(2.1)
Lower transport and transmission(0.6)
New rates3.6
Higher customer growth - distribution1.0
Other(0.6)
Total decrease in Gross margin (non-GAAP)$(1.1)

(a) Weather impacts for the three months ended June 30, 2019 compared to the same period in the prior year were primarily driven by direct and indirect impacts from significant rainfall and flooding within the Gas Utilities' service territories.

Operations and maintenance increased primarily due to $2.8 million of higher outside services expenses and $1.6 million of higher employee costs driven by additional headcount. Various other expenses comprise the remainder of the increase compared to the same period in the prior year.

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


45



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

Gross margin for the six months ended June 30, 2019 increase as a result of:
 (in millions)
New rates$12.4
Weather2.8
Higher customer growth - distribution2.8
Higher transport and transmission1.1
Excess deferred taxes returned to customers(2.7)
Lower mark-to-market on non-utility natural gas commodity contracts(2.5)
Other1.2
Total increase in Gross margin (non-GAAP)$15.1

Operations and maintenance increased primarily due to $6.5 million of higher outside services expenses and $3.8 million of higher employee costs driven by additional headcount. Various other expenses comprise the remainder of the increase compared to the same period in the prior year.

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


Operating Statistics
  Gas Revenue (in thousands) 
Gross Margin (non-GAAP)                                                                      (in thousands)
 Gas Utilities Quantities Sold & Transported (Dth)
  Three Months Ended
June 30,
 Three Months Ended
June 30,
 Three Months Ended
June 30,
  20192018 20192018 20192018
          
Residential $85,093
$91,000
 $52,670
$52,697
 7,919,158
8,837,588
Commercial 30,984
34,031
 14,926
14,807
 4,194,879
4,615,571
Industrial 3,980
6,565
 1,320
1,639
 997,942
1,747,702
Other (a)
 887
255
 887
255
 

Total Distribution 120,944
131,851
 69,803
69,398
 13,111,979
15,200,861
          
Transportation and Transmission 28,998
29,361
 29,031
29,361
 32,767,310
32,846,279
          
Total Regulated 149,942
161,212
 98,834
98,759
 45,879,289
48,047,140
          
Non-regulated Services 15,527
16,408
 9,651
10,807
   
          
Total Gas Revenue & Gross Margin (non-GAAP) $165,469
$177,620
 $108,485
$109,566
   


46



          
  Gas Revenue (in thousands) 
Gross Margin (non-GAAP)                                                                      (in thousands)
 Gas Utilities Quantities Sold & Transported (Dth)
  Six Months Ended
June 30,
 Six Months Ended
June 30,
 Six Months Ended
June 30,
  20192018 20192018 20192018
          
Residential $326,222
$325,751
 $157,727
$149,474
 40,757,176
38,933,825
Commercial 127,123
129,036
 50,084
47,010
 19,185,727
18,564,692
Industrial 9,994
12,547
 3,337
3,313
 2,180,469
2,931,319
Other (a)
 (3,467)(7,276) (3,467)(7,276) 

Total Distribution 459,872
460,058
 207,681
192,521
 62,123,372
60,429,836
          
Transportation and Transmission 73,945
71,422
 73,978
71,422
 79,083,470
77,579,754
          
Total Regulated 533,817
531,480
 281,659
263,943
 141,206,842
138,009,590
          
Non-regulated Services 42,732
43,484
 30,627
33,282
   
          
Total Gas Revenue & Gross Margin $576,549
$574,964
 $312,286
$297,225
   

(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
June 30,
 Three Months Ended
June 30,
 Three Months Ended
June 30,
  20192018 20192018 20192018
          
Arkansas $26,236
$27,095
 $18,617
$16,471
 4,542,917
5,282,607
Colorado 36,713
32,138
 19,755
18,562
 6,067,353
4,705,454
Iowa 23,714
27,102
 14,588
14,648
 7,484,272
7,429,328
Kansas 17,379
21,002
 11,957
11,870
 6,290,716
6,929,756
Nebraska 39,315
48,993
 27,709
32,801
 14,816,996
16,405,326
Wyoming 22,112
21,290
 15,859
15,214
 6,677,035
7,294,669
Total Gas Revenue & Gross Margin (non-GAAP) $165,469
$177,620
 $108,485
$109,566
 45,879,289
48,047,140

          
  Revenue (in thousands) 
Gross Margin (non-GAAP)                                                                        (in thousands)
 
Gas Utilities Quantities Sold & Transported (Dth)

  Six Months Ended
June 30,
 Six Months Ended
June 30,
 Six Months Ended
June 30,
  20192018 20192018 20192018
          
Arkansas $105,627
$97,483
 $62,899
$52,388
 16,967,113
17,161,233
Colorado 113,184
103,536
 57,355
51,707
 19,244,278
16,408,805
Iowa 89,355
94,986
 37,638
37,074
 23,147,959
22,932,317
Kansas 58,596
63,383
 30,076
29,767
 16,733,986
17,227,084
Nebraska 148,112
155,754
 83,782
86,661
 43,816,014
44,392,550
Wyoming 61,675
59,822
 40,536
39,628
 21,297,492
19,887,601
Total Gas Revenue & Gross Margin (non-GAAP) $576,549
$574,964
 $312,286
$297,225
 141,206,842
138,009,590

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.


47



 Three Months Ended June 30,
 2019   2018
Heating Degree DaysActual 
Variance
from Normal
 Actual Variance to Prior Year Actual 
Variance
from Normal
Arkansas (a)
246 (25)% (39)% 400 21%
Colorado1,017 6% 38% 735 (23)%
Iowa738 8% (8)% 801 17%
Kansas (a)
425 (5)% (16)% 508 14%
Nebraska664 5% (6)% 708 12%
Wyoming1,397 15% 30% 1,072 (12)%
Combined (b)
795 5% 7% 740 (1)%


          
 Six Months Ended June 30,
Degree Days2019   2018
Heating Degree Days:Actual 
Variance
from Normal
 Actual Variance to Prior Year Actual 
Variance
from Normal
Arkansas (a)
2,347 (4)% (4)% 2,448 1%
Colorado4,047 4% 18% 3,439 (12)%
Iowa4,568 13% 5% 4,332 7%
Kansas (a)
3,204 10% 8% 2,978 2%
Nebraska4,147 13% 6% 3,915 7%
Wyoming4,910 11% 14% 4,316 (2)%
Combined (b)
4,244 10% 9% 3,899 1%
__________
(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.


48



Power Generation
 Three Months Ended June 30,Six Months Ended June 30,
 20192018Variance20192018Variance
 (in thousands)
Revenue$24,708
$22,744
$1,964
$49,953
$46,682
$3,271
       
Operations and maintenance9,833
9,959
(126)18,521
18,086
435
Depreciation and amortization4,719
3,908
811
9,309
7,944
1,365
Total operating expense14,552
13,867
685
27,830
26,030
1,800
       
Adjusted operating income (a)
$10,156
$8,877
$1,279
$22,123
$20,652
$1,471
________________
(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 six months ended June 30, 2018, which resulted in a decrease of $(1.4) million and $(3.0) million, respectively.


Results of Operations for Power Generation for the Three and Six Months Ended June 30, 2019 Compared to the Three and Six Months Ended June 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 due to higher depreciation and property taxes from new wind assets.

The following table summarizes MWh for our Power Generation segment:
 Three Months Ended June 30, Six Months Ended June 30,
 20192018 20192018
Quantities Sold, Generated and Purchased
(MWh) (a)
     
Sold     
Black Hills Colorado IPP (b)
210,316
208,888
 416,289
441,263
Black Hills Wyoming (c)
149,713
144,460
 313,762
310,061
Black Hills Electric Generation (d)
47,796

 81,549

Total Sold407,825
353,348
 811,600
751,324
      
Generated     
Black Hills Colorado IPP (b)
210,316
208,888
 416,289
441,263
Black Hills Wyoming (c)
132,189
128,819
 264,782
262,848
Black Hills Electric Generation (d)
47,796

 81,549

Total Generated390,301
337,707
 762,620
704,111
      
Purchased     
Black Hills Wyoming (c)
13,761
17,122
 39,340
49,039
Total Purchased13,761
17,122
 39,340
49,039
____________
(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.


49



The following table provides certain operating statistics for our plants within the Power Generation segment:
 Three Months Ended June 30, Six Months Ended June 30,
 20192018 20192018
Contracted power plant fleet availability:     
Coal-fired plant95.8%89.1% 95.3%91.9%
Natural gas-fired plants (a)
88.7%99.5% 92.1%99.5%
Wind (b)
94.1%N/A
 92.3%N/A
Total availability91.5%96.8% 92.8%97.5%
      
Wind capacity factor (b)
23.1%N/A
 25.7%N/A
____________
(a)2019 included a planned outage at Pueblo Airport Generation.
(b)Change from the prior year is driven by Black Hills Electric Generation’s acquisition of new wind assets.

Mining

Three Months Ended June 30,Six Months Ended June 30,

20192018Variance20192018Variance

(in thousands)
Revenue$13,045
$16,899
$(3,854)$29,474
$34,027
$(4,553)
       
Operations and maintenance9,175
11,124
(1,949)19,088
22,046
(2,958)
Depreciation, depletion and amortization2,230
1,950
280
4,409
3,885
524
Total operating expenses11,405
13,074
(1,669)23,497
25,931
(2,434)
       
Adjusted operating income$1,640
$3,825
$(2,185)$5,977
$8,096
$(2,119)

The following table provides certain operating statistics for our Mining segment (in thousands, except for Revenue per ton):
 Three Months Ended June 30, Six Months Ended June 30,
 20192018 20192018
Tons of coal sold754
963
 1,751
2,041
Cubic yards of overburden moved2,045
2,380
 4,039
4,402
      
Revenue per ton$16.48
$16.97
 $16.14
$16.12

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

Current year revenue decreased due to 22% 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 major maintenance expenses.


Results of Operations for Mining for the Six Months Ended June 30, 2019 Compared to the Six Months Ended June 30, 2018:

Current year revenue decreased due to 14% 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 major maintenance expenses.

50



Corporate and Other
 Three Months Ended June 30,Six Months Ended June 30,
 20192018Variance20192018Variance
 (in thousands)
Adjusted operating income (loss) (a)
$102
$(836)$938
$(405)$(2,531)$2,126
________________
(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 six months ended June 30, 2018, which resulted in a decrease of $(0.2) million and $(0.3) million, respectively.

Results of Operations for Corporate and Other for the Three and Six Months Ended June 30, 2019 Compared to the Three and Six Months Ended June 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, Other income (expense) and Income tax benefit (expense) for the Three Months Ended June 30, 2019 Compared to the Three Months Ended June 30, 2018.

Income Tax Benefit (Expense)

Income tax benefit (expense) for the three months ended June 30, 2019 was $(2.3) million compared to $(6.5) million for the same period in 2018. The decrease is driven by a lower 2019 forecasted annual effective tax rate primarily due to an increase of federal production tax credits and state investment credits associated with new wind assets; and a current year $1.6 million flow-through discrete tax benefit related to repair costs and certain indirect costs.
 

Consolidated interest expense, Other income (expense) and Income tax benefit (expense) for the Six Months Ended June 30, 2019 Compared to the Six Months Ended June 30, 2018.

Income Tax Benefit (Expense)

Income tax benefit (expense) for the six months ended June 30, 2019 was $(20) million compared to $19 million 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 and partially offset by a prior year $(2.3) million income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes.

For the six months ended June 30, 2019 the effective tax rate was 13.5% compared to 19.0% excluding the legal entity restructuring and tax reform adjustments, for the same period in 2018. The lower effective tax rate is primarily due to $3.5 million of federal production tax credits and related state investment credits associated with new wind assets, a $1.7 million tax benefit for deferred tax amortization related to tax reform and a $1.6 million flow-through discrete tax benefit related to repair costs and certain indirect costs.


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.


51



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 June 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 six states and are working with regulators in our seventh state, as well as 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 six months ended June 30, 2019 (in thousands):
Cash provided by (used in):20192018Variance
Operating activities$289,779
$310,701
$(20,922)
Investing activities$(317,297)$(163,526)$(153,771)
Financing activities$13,617
$(153,701)$167,318


52



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

Operating Activities

Net cash provided by operating activities was $290 million for the six months ended June 30, 2019, compared to net cash provided by operating activities of $311 million for the same period in 2018 for a decrease of $21 million. The variance was primarily attributable to:

Cash earnings (income from continuing operations plus non-cash adjustments) were $13 million higher for the six months ended June 30, 2019 compared to the same period in the prior year;

Net cash inflows from changes in operating assets and liabilities were $14 million for the six months ended June 30, 2019, compared to net cash inflows of $47 million in the same period in the prior year. This $33 million decrease was primarily due to:

Cash inflows increased by approximately $46 million primarily as a result of higher collections of accounts receivable, partially offset by higher materials inventory to support capital projects for the six months ended June 30, 2019 compared to the same period in the prior year;

Cash outflows increased by approximately $11 million as a result of decreases in accounts payable and accrued liabilities driven by higher employee costs, higher gas purchases and other working capital requirements; and

Cash inflows decreased by approximately $66 million as a result of changes in our current regulatory assets and liabilities driven by differences in 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 $317 million for the six months ended June 30, 2019, compared to net cash used in investing activities of $164 million for the same period in 2018 for a variance of $154 million. The variance was primarily attributable to:

Capital expenditures of approximately $318 million for the six months ended June 30, 2019 compared to $157 million for the same period in the prior year. Higher current year expenditures are primarily driven by the Busch Ranch II wind project at our Power Generation segment, construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota, to Stegall, Nebraska at our Electric Utilities segment and the 35-mile Natural Bridge pipeline project at our Gas Utilities segment; and

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.

Financing Activities

Net cash provided by financing activities for the six months ended June 30, 2019 was $14 million, compared to $154 million of net cash used in financing activities for the same period in 2018 for a variance of $167 million. This variance is primarily due to:

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

Current year issuance of common stock for net proceeds of approximately $69 million through our ATM equity offering program;

$10 million of higher current year dividend payments; and

Lower current year net repayments of short-term borrowings of $6 million. Repayments of short-term borrowings, driven by proceeds received from the amendment to the Corporate term loan and the ATM equity offering program, were mostly offset by higher borrowings driven by increased capital expenditures.


53



Dividends

Dividends paid on our common stock totaled $61 million for the six months ended June 30, 2019, or $0.505 per share per quarter. On July 31, 2019, our board of directors declared a quarterly dividend of $0.505 per share payable September 1, 2019, equivalent to an annual dividend of $2.02 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):
  CurrentRevolver Borrowings atCP Program Borrowings atLetters of Credit atAvailable Capacity at
Credit FacilityExpirationCapacityJune 30, 2019June 30, 2019June 30, 2019June 30, 2019
Revolving Credit FacilityJuly 30, 2023$750
$
$103
$10
$637

The weighted average interest rate on CP Program borrowings at June 30, 2019 was 2.60%. Revolving Credit Facility and CP Program financing activity for the six months ended June 30, 2019 was (dollars in millions):
 For the Six Months Ended June 30, 2019
Maximum amount outstanding - commercial paper (based on daily outstanding balances)$237
Maximum amount outstanding - revolving credit facility (based on daily outstanding balances)$
Average amount outstanding - commercial paper (based on daily outstanding balances)$160
Average amount outstanding - revolving credit facility (based on daily outstanding balances)$
Weighted average interest rates - commercial paper2.68%
Weighted average interest rates - revolving credit facility%

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 June 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 June 30, 2019, we were in compliance with these covenants.
Financing Activities

Financing activities for the six months ended June 30, 2019 consisted of the following:

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 used to pay down short-term debt. See Note 8 of the Notes to Condensed Consolidated Financial Statements for more information.

We issued a total of 939,095 shares of common stock under the ATM equity offering program for proceeds of $69 million, net of $0.7 million in commissions. As of June 30, 2019, there were no shares that were sold, but not settled.

Short-term borrowings from our CP Program.


54



Future Financing Plans

Evaluate refinancing options for our $200 million senior notes due July 15, 2020.

Continue to assess equity needs to support our capital expenditure plan.

Credit Ratings

Financing for operational needs and capital expenditure requirements not satisfied by operating cash flows depends upon the cost and availability of external funds through both short and long-term financing. The inability to raise capital on favorable terms could negatively affect our ability to maintain or expand our businesses. Access to funds is dependent upon factors such as general economic and capital market conditions, regulatory authorizations and policies, the Company’s credit ratings, cash flows from routine operations and the credit ratings of counterparties. 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. BHC notes that credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.

The following table represents the credit ratings and outlook and risk profile of BHC at June 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 October 11, 2018, Fitch affirmed our BBB+ rating and maintained a Stable outlook.

The following table represents the credit ratings of South Dakota Electric at June 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 December 12, 2018, Moody’s affirmed A1 rating.
(c)On July 23, 2019, Fitch affirmed A rating.


55



Capital Requirements

Capital Expenditures
 ActualPlannedPlannedPlannedPlannedPlanned
Capital Expenditures by Segment
Six Months Ended June 30, 2019 (a)
2019 (b)
2020202120222023
(in millions)      
Electric Utilities (c)
$87
$205
$221
$203
$170
$137
Gas Utilities (c)
185
464
323
289
277
274
Power Generation41
84
9
8
10
4
Mining5
8
7
11
10
7
Corporate and Other14
16
22
8
5
7
 $332
$777
$582
$519
$472
$429
__________
(a)    Expenditures for the six months ended June 30, 2019 include the impact of accruals for property, plant and equipment.
(b)    Includes actual capital expenditures for the six months ended June 30, 2019.
(c)    Planned capital expenditures increased for 2019 through 2023 primarily due to increased programmatic 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.


56



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 six months ended June 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 June 30, 2019. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at June 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 June 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.



57



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*
 
 
 
  
Exhibit 4.3*

58



 
 
  
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
  
__________
*Previously filed as part of the filing indicated and incorporated by reference herein.


59



SIGNATURES


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

BLACK HILLS CORPORATION
  /s/ Linden R. Evans
  Linden R. Evans, President and
    Chief Executive Officer
   
  /s/ Richard W. Kinzley
  Richard W. Kinzley, Senior Vice President and
    Chief Financial Officer
   
Dated:August 6, 2019 


60