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BKH Black Hills

Filed: 6 Nov 18, 5:29pm


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

Form 10-Q
xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
 EXCHANGE ACT OF 1934
 For the quarterly period ended September 30, 2018
OR 
oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
 EXCHANGE ACT OF 1934
 For the transition period from __________ to __________.
  
 Commission File Number 001-31303
Black Hills Corporation
Incorporated in South DakotaIRS Identification Number 46-0458824
7001 Mount Rushmore Road
Rapid City, South Dakota 57702
Registrant’s telephone number (605) 721-1700
Former name, former address, and former fiscal year if changed since last report
NONE
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
 
Yes x
 
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).
 
Yes x
 
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 filer x
 
Accelerated filer o
 
     
 
Non-accelerated filer o
 
Smaller reporting company o
 
     
   
Emerging growth company o
 
     

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 o
 
No x
 

Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.
ClassOutstanding at November 1, 2018
Common stock, $1.00 par value59,974,620
shares






TABLE OF CONTENTS
   Page
 Glossary of Terms and Abbreviations 
    
PART I.FINANCIAL INFORMATION 
    
Item 1.Financial Statements 
    
 Condensed Consolidated Statements of Income - unaudited  
    Three and Nine Months Ended September 30, 2018 and 2017 
    
 Condensed Consolidated Statements of Comprehensive Income - unaudited  
    Three and Nine Months Ended September 30, 2018 and 2017 
    
 Condensed Consolidated Balance Sheets - unaudited  
    September 30, 2018, December 31, 2017 and September 30, 2017 
    
 Condensed Consolidated Statements of Cash Flows - unaudited  
    Nine Months Ended September 30, 2018 and 2017 
    
 Notes to Condensed Consolidated Financial Statements - unaudited 
    
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations 
    
Item 3.Quantitative and Qualitative Disclosures about Market Risk 
    
Item 4.Controls and Procedures 
    
PART II.OTHER INFORMATION 
    
Item 1.Legal Proceedings 
    
Item 1A.Risk Factors 
    
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds 
    
Item 4.Mine Safety Disclosures 
    
Item 5.Other Information 
    
Item 6.Exhibits 
    
 Signatures 


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)
APSCArkansas Public Service Commission
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.
BblBarrel
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 RanchBusch Ranch Wind Farm is a 29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and AltaGas. Colorado Electric has 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)
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 distributes the gas and Black Hills Energy Services is one of the Choice Gas suppliers.
CIACContribution In Aid of Construction
City of GilletteGillette, Wyoming
Colorado ElectricBlack Hills Colorado Electric, 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 and including the aggregate outstanding amount of RSNs) plus Consolidated Indebtedness (including letters of credit, certain guarantees issued and excluding RSNs) as defined within the current Credit Agreement.
CDDA 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 over a 30-year average.
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
DthDekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)

3



Equity UnitEach Equity Unit has 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 prior to the successful remarketing on August 17, 2018.
FASBFinancial Accounting Standards Board
FERCUnited States Federal Energy Regulatory Commission
FitchFitch Ratings
GAAPAccounting principles generally accepted in the United States of America
HDDA 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 over a 30-year average.
Horizon PointCorporate headquarters building in Rapid City, South Dakota, which was completed in 2017.
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)
LIBORLondon Interbank Offered Rate
MMBtuMillion British thermal units
Moody’sMoody’s Investors Service, Inc.
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)
OCAOffice of Consumer Advocate
Peak View Wind Project$109 million 60 MW wind generating project for Colorado Electric, adjacent to Busch Ranch wind farm
PCAPower Cost Adjustment
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.
RMNGRocky Mountain Natural Gas, a regulated gas utility acquired in the SourceGas Acquisition that provides regulated transmission and wholesale natural gas service to Black Hills Gas in western Colorado (doing business as Black Hills Energy)
RSNsRemarketable junior subordinated notes, issued on November 23, 2015
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 ElectricIncludes Black Hills Power 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
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


4



 

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)Three Months Ended September 30,Nine Months Ended September 30,
 2018201720182017
 (in thousands, except per share amounts)
     
Revenue$321,979
$335,611
$1,253,072
$1,224,968
     
Operating expenses:    
Fuel, purchased power and cost of natural gas sold80,244
86,281
432,544
404,222
Operations and maintenance115,477
109,258
350,099
335,707
Depreciation, depletion and amortization49,046
47,109
146,345
140,636
Taxes - property, production and severance11,905
12,408
39,181
38,866
Other operating expenses222
996
1,993
5,996
Total operating expenses256,894
256,052
970,162
925,427
     
Operating income65,085
79,559
282,910
299,541
     
Other income (expense):    
Interest charges -    
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts)(36,480)(35,287)(107,360)(105,417)
Allowance for funds used during construction - borrowed701
753
1,345
2,061
Capitalized interest100
64
177
197
Interest income382
402
1,012
700
Allowance for funds used during construction - equity193
696
503
1,982
Other income (expense), net(703)189
(2,426)(6)
Total other income (expense), net(35,807)(33,183)(106,749)(100,483)
     
Income before income taxes29,278
46,376
176,161
199,058
Income tax benefit (expense)(7,477)(13,478)11,784
(58,518)
Income from continuing operations21,801
32,898
187,945
140,540
(Loss) from discontinued operations, net of tax(857)(1,300)(5,627)(3,485)
Net income20,944
31,598
182,318
137,055
Net income attributable to noncontrolling interest(3,994)(3,935)(10,447)(10,674)
Net income available for common stock$16,950
$27,663
$171,871
$126,381
     
Amounts attributable to common shareholders:    
Net income from continuing operations$17,807
$28,963
$177,498
$129,866
Net (loss) from discontinued operations(857)(1,300)(5,627)(3,485)
Net income available for common stock$16,950
$27,663
$171,871
$126,381
     
Earnings per share of common stock:    
Earnings (loss) per share, Basic -    
Income from continuing operations, per share$0.33
$0.54
$3.33
$2.44
(Loss) from discontinued operations, per share(0.02)(0.02)(0.10)(0.06)
Earnings per share, Basic (a)
$0.32
$0.52
$3.22
$2.38
     
Earnings (loss) per share, Diluted -    
Income from continuing operations, per share$0.32
$0.52
$3.26
$2.35
(Loss) from discontinued operations, per share(0.02)(0.02)(0.10)(0.06)
Earnings per share, Diluted (a)
$0.31
$0.50
$3.15
$2.29
Weighted average common shares outstanding:    
Basic53,364
53,243
53,346
53,208
Diluted54,819
55,432
54,508
55,254
     
Dividends declared per share of common stock$0.475
$0.445
$1.425
$1.335

(a) EPS may not sum due to rounding.

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

5




BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)Three Months Ended
September 30,
Nine Months Ended
September 30,
 2018201720182017
 (in thousands)
     
Net income$20,944
$31,598
$182,318
$137,055
     
Other comprehensive income (loss), net of tax:    
Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $10 and $17 for the three months ended September 30, 2018 and 2017 and $29 and $52 for the nine months ended September 30, 2018 and 2017, respectively)(34)(32)(104)(94)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(138) and $(145) for the three months ended September 30, 2018 and 2017 and $(409) and $(445) for the nine months ended September 30, 2018 and 2017, respectively)483
269
1,456
797
Derivative instruments designated as cash flow hedges:    
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax (expense) benefit of $(152) and $(249) for the three months ended September 30, 2018 and 2017 and $(456) and $(779) for the nine months ended September 30, 2018 and 2017, respectively)560
464
1,682
1,449
Net unrealized gains (losses) on commodity derivatives (net of tax (expense) benefit of $0 and $94 for the three months ended September 30, 2018 and 2017 and $51 and $(442) for the nine months ended September 30, 2018 and 2017, respectively)30
(160)(168)755
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax (expense) benefit of $3 and $95 for the three months ended September 30, 2018 and 2017 and $(187) and $344 for the nine months ended September 30, 2018 and 2017, respectively)21
(166)615
(590)
Other comprehensive income, net of tax1,060
375
3,481
2,317
     
Comprehensive income22,004
31,973
185,799
139,372
Less: comprehensive income attributable to noncontrolling interest(3,994)(3,935)(10,447)(10,674)
Comprehensive income available for common stock$18,010
$28,038
$175,352
$128,698

See Note 14 for additional disclosures.

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

6



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)As of
 September 30,
2018
 December 31, 2017 September 30,
2017
 (in thousands)
ASSETS     
Current assets:     
Cash and cash equivalents$10,001
 $15,420
 $13,449
Restricted cash3,241
 2,820
 2,683
Accounts receivable, net152,796
 248,330
 150,325
Materials, supplies and fuel122,618
 113,283
 122,866
Derivative assets, current1,392
 304
 433
Income tax receivable, net11,025
 
 
Regulatory assets, current48,302
 81,016
 61,023
Other current assets32,691
 25,367
 25,586
Current assets held for sale2,854
 84,242
 8,653
Total current assets384,920
 570,782
 385,018
      
Investments41,202
 13,090
 12,947
      
Property, plant and equipment5,819,000
 5,567,518
 5,499,557
Less: accumulated depreciation and depletion(1,118,783) (1,026,088) (1,000,875)
Total property, plant and equipment, net4,700,217
 4,541,430
 4,498,682
      
Other assets:     
Goodwill1,299,454
 1,299,454
 1,299,454
Intangible assets, net6,954
 7,559
 7,765
Regulatory assets, non-current212,048
 216,438
 239,571
Other assets, non-current17,143
 10,149
 11,626
Noncurrent assets held for sale
 
 108,685
Total other assets, non-current1,535,599
 1,533,600
 1,667,101
      
TOTAL ASSETS$6,661,938
 $6,658,902
 $6,563,748

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

7



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
(unaudited)As of
 September 30,
2018
 December 31, 2017 September 30,
2017
 (in thousands, except share amounts)
LIABILITIES AND TOTAL EQUITY     
Current liabilities:     
Accounts payable$115,900
 $160,887
 $94,790
Accrued liabilities201,353
 219,462
 206,779
Derivative liabilities, current1,154
 2,081
 1,458
Accrued income taxes, net
 1,022
 5,587
Regulatory liabilities, current41,442
 6,832
 7,042
Notes payable112,100
 211,300
 225,170
Current maturities of long-term debt255,743
 5,743
 5,743
Current liabilities held for sale2,538
 41,774
 7,701
Total current liabilities730,230
 649,101
 554,270
      
Long-term debt2,951,389
 3,109,400
 3,109,864
      
Deferred credits and other liabilities:     
Deferred income tax liabilities, net292,753
 336,520
 618,315
Regulatory liabilities, non-current508,846
 478,294
 198,189
Benefit plan liabilities151,613
 159,646
 149,803
Other deferred credits and other liabilities105,928
 105,735
 113,996
Non-current liabilities held for sale
 
 23,329
Total deferred credits and other liabilities1,059,140
 1,080,195
 1,103,632
      
Commitments and contingencies (See Notes 9, 11, 16, 17)

 
 
      
Equity:     
Stockholders’ equity —     
Common stock $1 par value; 100,000,000 shares authorized; issued 53,661,863; 53,579,986; and 53,524,529 shares, respectively53,662
 53,580
 53,525
Additional paid-in capital1,157,214
 1,150,285
 1,147,922
Retained earnings644,154
 548,617
 516,371
Treasury stock, at cost – 72,915; 39,064; and 41,457 shares, respectively(4,072) (2,306) (2,448)
Accumulated other comprehensive income (loss)(37,703) (41,202) (32,566)
Total stockholders’ equity1,813,255
 1,708,974
 1,682,804
Noncontrolling interest107,924
 111,232
 113,178
Total equity1,921,179
 1,820,206
 1,795,982
      
TOTAL LIABILITIES AND TOTAL EQUITY$6,661,938
 $6,658,902
 $6,563,748

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

8



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)Nine Months Ended September 30,
 20182017
Operating activities:(in thousands)
Net income$182,318
$137,055
Loss from discontinued operations, net of tax5,627
3,485
Income from continuing operations187,945
140,540
Adjustments to reconcile net income to net cash provided by operating activities:  
Depreciation, depletion and amortization146,345
140,636
Deferred financing cost amortization5,682
6,212
Stock compensation7,544
7,594
Deferred income taxes(14,396)65,536
Employee benefit plans10,641
8,470
Other adjustments, net7,668
(3,549)
Changes in certain operating assets and liabilities:  
Materials, supplies and fuel(8,380)(19,511)
Accounts receivable, unbilled revenues and other operating assets72,061
103,963
Accounts payable and other operating liabilities(86,604)(112,288)
Regulatory assets - current41,655
1,287
Regulatory liabilities - current21,416
(4,328)
Contributions to defined benefit pension plans(12,700)(27,700)
Other operating activities, net2,007
(1,410)
Net cash provided by operating activities of continuing operations380,884
305,452
Net cash provided by (used in) operating activities of discontinued operations(2,162)13,978
Net cash provided by operating activities378,722
319,430
   
Investing activities:  
Property, plant and equipment additions(278,132)(238,840)
Purchase of investment(24,429)
Other investing activities2,766
160
Net cash provided by (used in) investing activities of continuing operations(299,795)(238,680)
Net cash provided by (used in) investing activities of discontinued operations18,024
(17,298)
Net cash provided by (used in) investing activities(281,771)(255,978)
   
Financing activities:  
Dividends paid on common stock(76,309)(71,334)
Common stock issued1,079
3,562
Net (payments) borrowings of short-term debt(99,200)128,570
Long-term debt - issuances700,000

Long-term debt - repayments(603,307)(104,307)
Distributions to noncontrolling interest(13,755)(12,884)
Other financing activities(10,457)(6,719)
Net cash provided by (used in) financing activities(101,949)(63,112)
Net change in cash, cash equivalents and restricted cash(4,998)340
Cash, cash equivalents and restricted cash at beginning of period18,240
15,792
Cash, cash equivalents and restricted cash at end of period$13,242
$16,132

See Note 15 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

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 2017 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 2017 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.

On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. The Oil and Gas segment assets and liabilities are classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, excluding certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. As of September 30, 2018, we have sold nearly all of our oil and gas assets and we closed our oil and gas office in August. Transaction closing for the last few assets and final accounting are expected within the fourth quarter. See Note 18 for more information on discontinued operations.

Use of Estimates and Basis of Presentation

The information furnished in the accompanying Condensed Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the September 30, 2018, December 31, 2017, and September 30, 2017 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, as well as changes in market prices. In particular, the normal peak usage season for electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and nine months ended September 30, 2018 and September 30, 2017, and our financial condition as of September 30, 2018, December 31, 2017, and September 30, 2017, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

Cash and Cash Equivalents and Restricted Cash

For purposes of the cash flow statements, we consider all highly liquid investments with original maturities of three months or less at the time of purchase to be cash equivalents.

Investments

We account for investments that we do not control under the cost method of accounting as we do not have the ability to exercise significant influence over the operating and financial policies of the investee. The cost method investments are recorded at cost and we record dividend income when applicable dividends are declared.


10



Recently Issued Accounting Standards

Leases, ASU 2016-02

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement, which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Under the current guidance, lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard. The FASB also issued additional amendments to the new lease standard in July 2018, ASU No. 2018-11, allowing companies to adopt the new standard with a cumulative effect adjustment as of the beginning of the year of adoption with prior year comparative financial information and disclosures remaining as previously reported.

We expect to adopt this standard on January 1, 2019. For existing or expired land easements that were not previously accounted for as a lease, we anticipate electing the practical expedient which provides for no assessment of these easements. Further, we anticipate adopting the new standard with a cumulative effect adjustment with prior year comparative financial information remaining as previously reported when transitioning to the new standard. The standard also provides a transition practical expedient, commonly referred to as the “package of three”, that must be taken together and allows entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. We expect to elect the “package of three” practical expedient. We continue to evaluate the additional transition practical expedients available under the guidance. At this time, we do not believe the implementation of this standard will have a material impact on our financial position, results of operations or cash flows. We continue to develop our process of identifying and categorizing our lease contracts and evaluating our current business processes relating to leases. We have selected, configured, and tested a new lease software solution and will be entering lease data into the new system in preparation for the January 1, 2019 standard adoption. We also continue to monitor utility industry lease implementation guidance that may change existing and future lease classification.

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

In August 2017, the FASB issued 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. This ASU is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We do not anticipate the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows.

Simplifying the Test for Goodwill Impairment, ASU 2017-04

In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment (Topic 350) 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 15, 2019, applied on a prospective basis with early adoption permitted. We do not anticipate the adoption of this standard to have any impact on our financial position, results of operations or cash flows.


11



Recently Adopted Accounting Standards

Revenue from Contracts with Customers, ASU 2014-09

Effective January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and its related amendments (collectively known as ASC 606). Under this standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. We applied the five-step method outlined in the ASU to all in-scope revenue streams and elected the modified retrospective implementation method. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Implementation of the standard did not have a significant impact on the measurement or recognition of revenue; therefore, no cumulative adoption adjustment to the opening balance of Retained earnings at the date of initial application was necessary. The additional disclosures required by the ASU are included in Note 2.

Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07

Effective January 1, 2018, we adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The standard requires employers to report the service cost component in the same line item(s) as other compensation costs, and requires the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets was applied on a prospective basis for the nine months ended September 30, 2018. Retrospective impact was not material and therefore prior year presentation was not changed. For our rate-regulated entities, we capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC-to-GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs resulted in offsetting changes to Operating income and Other income. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15

Effective January 1, 2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. We implemented this standard effective January 1, 2018 using the retrospective transition method. This standard had no impact on our financial position, results of operations or cash flows.

Statement of Cash Flows: Restricted Cash, ASU 2016-18

Effective January 1, 2018, we adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU provides guidance on the presentation of restricted cash or restricted cash equivalents and reduces the diversity in practice. This ASU requires amounts generally described as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period total amounts on the statement of cash flows. We elected, as permitted by the standard, to early adopt ASU 2016-18 retrospectively as of January 1, 2017 and have applied it to all periods presented herein. The adoption of ASU 2016-18 did not have a material impact to our condensed consolidated financial statements. The effect of the adoption of ASU 2016-18 on our Condensed Consolidated Statements of Cash Flows was to include restricted cash balances in the beginning and end of period balances of cash, cash equivalents, and restricted cash. The change in restricted cash was previously disclosed in investing activities in the Condensed Consolidated Statements of Cash Flows.

12




(2)    REVENUE

Revenue Recognition
Revenues are 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. Our primary types of revenue contracts are:

Regulated natural gas and electric utility services tariffs - Our utilities have regulated operations, as defined by ASC 980, that provide services to regulated customers under rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Collectively, these rates, charges, terms and conditions are included in a tariff, which governs all aspects of the provision of our regulated services. Our regulated services primarily encompass single performance obligations material to the context of the contract for delivery of either commodity natural gas, commodity electricity, natural gas transportation or electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the regulator-empowered statute to establish contractual rates between the utility and its customers. All of our utilities’ regulated sales are subject to regulatory-approved tariffs.

Power sales agreements - Our electric utilities and power generation segments have long-term wholesale power sales agreements with other load-serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, Black Hills also sells excess energy to other load-serving entities on a short-term basis as a member of the Western States Power Pool. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based on energy delivered.

Coal supply agreements - Our mining segment sells coal primarily under long-term contracts to utilities for use at their power generating plants, including affiliate electric utilities, and an affiliate non-regulated power generation entity. The contracts include a single promise to supply coal necessary to fuel the customers’ facilities during the contract term. The transaction price is established in the coal supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons of coal delivered.

Other non-regulated services - Our natural gas and electric utility segments also provide non-regulated services primarily comprised of appliance repair service and protection plans, electric and natural gas technical infrastructure construction and maintenance services, and in Nebraska and Wyoming, an unbundled natural gas commodity offering under the regulatory-approved Choice Gas Program. Revenue contracts for these services generally represent a single performance obligation with the price reflecting the standalone selling price stated in the agreement, and the revenue is variable based on the units delivered or services provided.


13



The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments, for the three and nine months ended September 30, 2018. Sales tax and other similar taxes are excluded from revenues.
Three Months Ended September 30, 2018 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer types:(in thousands)
Retail$157,049
$88,559
$
$16,751
$(7,941)$254,418
Transportation
30,079


(267)29,812
Wholesale8,255

14,485

(13,047)9,693
Market - off-system sales9,059
140


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


(3,693)18,390
Revenue from contracts with customers184,559
130,665
14,485
16,751
(26,297)320,163
Other revenues231
1,011
9,118
550
(9,094)1,816
Total revenues$184,790
$131,676
$23,603
$17,301
$(35,391)$321,979
       
Timing of revenue recognition:      
Services transferred at a point in time$
$
$
$16,751
$(7,941)$8,810
Services transferred over time184,559
130,665
14,485

(18,356)311,353
Revenue from contracts with customers$184,559
$130,665
$14,485
$16,751
$(26,297)$320,163
       

Nine Months Ended September 30, 2018 Electric Utilities Gas Utilities Power Generation MiningInter-company RevenuesTotal
Customer types:(in thousands)
Retail$449,482
$565,816
$
$49,653
$(23,761)$1,041,190
Transportation
100,760


(977)99,783
Wholesale25,497

41,161

(36,874)29,784
Market - off-system sales18,142
728


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


(10,967)61,885
Revenue from contracts with customers529,743
703,534
41,161
49,653
(78,110)1,245,981
Other revenues2,218
3,106
27,429
1,675
(27,337)7,091
Total revenues$531,961
$706,640
$68,590
$51,328
$(105,447)$1,253,072
       
Timing of revenue recognition:      
Services transferred at a point in time$
$
$
$49,653
$(23,761)$25,892
Services transferred over time529,743
703,534
41,161

(54,349)1,220,089
Revenue from contracts with customers$529,743
$703,534
$41,161
$49,653
$(78,110)$1,245,981
       
The majority of our revenue contracts are based on variable quantities delivered; any fixed consideration contracts with an expected duration of one year or more are immaterial to our consolidated revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer.


14



Revenue Not in Scope of ASC 606
Other revenues included in the tables above include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 840, derivative revenue under ASC 815 and alternative revenue programs revenue under ASC 980. The majority of our lease revenue is related to a 20-year power sale agreement between Colorado IPP and affiliate Colorado Electric. This agreement is accounted for as a direct financing lease whereby Colorado IPP receives revenue for energy delivered and related capacity payments. This lease revenue is eliminated in our consolidated revenues.

Significant Judgments and Estimates
TCJA Revenue Reserve

The TCJA or “tax reform” signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21% effective for tax years beginning after December 31, 2017. Black Hills has been collaborating with utility commissions in the states in which it provides utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We have received state utility commission approvals to provide the benefits of federal tax reform to utility customers in six states. We estimated and recorded a reserve to revenue of approximately $6.0 million and $29 million during the three and nine months ended September 30, 2018, respectively. As of September 30, 2018, $7.9 million has been returned to customers and approximately $21 million remains in reserve.

Unbilled Revenue

Revenues attributable to natural gas and electricity delivered to customers but not yet billed are estimated and accrued, and the related costs are charged to expense. Factors influencing the determination of unbilled revenues include estimates of delivered sales volumes based on weather information and customer consumption trends.

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 contract.

Practical Expedients
Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer, and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice.

We have revenue contract performance obligations with similar characteristics, and we reasonably expect that the financial statement impact of applying the new revenue recognition guidance to a portfolio of contracts would not differ materially from applying this guidance to the individual contracts or performance obligations within the portfolio. Therefore, we have elected the portfolio approach in applying the new revenue guidance.


15



(3)    BUSINESS SEGMENT INFORMATION

Segment information and Corporate and Other included in the accompanying Condensed Consolidated Statements of Income were as follows (in thousands):
Three Months Ended September 30, 2018External Operating Revenue Inter-company Operating Revenue  Total Revenues Net income (loss) from continuing operations
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:         
Electric Utilities$179,527
$231

$5,032
$

$184,790

$21,578
Gas Utilities130,390
1,011

275


131,676

(13,277)
Power Generation (b)
1,437
348

13,048
8,770

23,603

6,691
Mining8,809
226

7,942
324

17,301

3,572
Corporate and Other







(757)
Inter-company eliminations

 (26,297)(9,094) (35,391) 
Total$320,163
$1,816
 $
$
 $321,979
 $17,807

Under our modified retrospective adoption of ASU 2014-09, revenues for the three and nine months ended September 30, 2017 are not presented by contract type.
 Three Months Ended September 30, 2017External Operating Revenue Inter-company Operating Revenue Net income (loss) from continuing operations
 
 Segment:     
 Electric Utilities$181,238
 $2,333
 $27,324
 Gas Utilities142,821
 73
 (4,329)
 
Power Generation (b)
1,810
 21,117
 6,155
 Mining9,742
 7,751
 3,477
 Corporate and Other
 
 (3,664)
 Inter-company eliminations
 (31,274) 
 Total$335,611
 $
 $28,963

          
Nine Months Ended September 30, 2018
External Operating
Revenue
 Inter-company Operating Revenue Total Revenues Net income (loss) from continuing operations
 Contract Customers Other Revenues Contract Customers Other Revenues
Segment:         
Electric Utilities$513,270
$2,218
 $16,473
$
 $531,961
 $63,313
Gas Utilities (a)
702,532
3,106
 1,002

 706,640
 93,182
Power Generation (b)
4,287
1,066
 36,874
26,363
 68,590
 17,319
Mining25,892
701
 23,761
974
 51,328
 9,561
Corporate and Other

 

 
 (5,877)
Inter-company eliminations

 (78,110)(27,337) (105,447) 
Total$1,245,981
$7,091
 $
$
 $1,253,072
 $177,498

16



       
 Nine Months Ended September 30, 2017External Operating Revenue 
Inter-company
Operating
Revenue
 Net income (loss) from continuing operations
 
 Segment:     
 Electric Utilities$518,925
 $9,123
 $68,386
 Gas Utilities674,161
 90
 41,409
 
Power Generation (b)
5,382
 62,907
 18,017
 Mining26,500
 22,485
 9,048
 
Corporate and Other (c)

 
 (6,994)
 Inter-company eliminations
 (94,605) 
 Total$1,224,968
 $
 $129,866
___________
(a)
Net income from continuing operations available for common stock for the nine months ended September 30, 2018 included a $49 million tax benefit resulting from legal entity restructuring. See Note 19 Income Taxes of the Notes to Condensed Consolidated Financial Statements for more information.
(b)Net income from continuing operations available for common stock for the three and nine months ended September 30, 2018 and September 30, 2017 reflects net income attributable to noncontrolling interests of $4.0 million and $10.4 million, and $3.9 million and $10.6 million, respectively.
(c)Net income (loss) from continuing operations available for common stock for the nine months ended September 30, 2017 included a $1.4 million tax benefit recognized from carryback claims for specified liability losses involving prior tax years.

Segment information and Corporate and Other balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):
Total Assets (net of inter-company eliminations) as of:September 30, 2018 December 31, 2017 September 30, 2017
Segment:     
Electric Utilities (a)
$2,853,414
 $2,906,275
 $2,911,919
Gas Utilities3,433,316
 3,426,466
 3,288,104
Power Generation (a)
122,428
 60,852
 64,357
Mining72,602
 65,455
 66,700
Corporate and Other177,324
 115,612
 115,330
Discontinued operations2,854
 84,242
 117,338
Total assets$6,661,938
 $6,658,902
 $6,563,748
__________
(a)The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation Station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric as a capital lease.


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
September 30, 2018Receivable, TradeRevenue Doubtful AccountsReceivable, net
Electric Utilities$43,108
$31,381
$(386)$74,103
Gas Utilities48,638
24,768
(2,188)71,218
Power Generation1,696


1,696
Mining3,749


3,749
Corporate2,030


2,030
Total$99,221
$56,149
$(2,574)$152,796

 AccountsUnbilledLess Allowance forAccounts
December 31, 2017Receivable, TradeRevenue Doubtful AccountsReceivable, net
Electric Utilities$39,347
$36,384
$(586)$75,145
Gas Utilities81,256
88,967
(2,495)167,728
Power Generation1,196


1,196
Mining2,804


2,804
Corporate1,457


1,457
Total$126,060
$125,351
$(3,081)$248,330

 AccountsUnbilledLess Allowance forAccounts
September 30, 2017Receivable, TradeRevenue Doubtful AccountsReceivable, net
Electric Utilities$42,716
$29,762
$(494)$71,984
Gas Utilities49,842
24,516
(1,190)73,168
Power Generation1,010


1,010
Mining3,534


3,534
Corporate629


629
Total$97,731
$54,278
$(1,684)$150,325


18



(5)    REGULATORY ACCOUNTING

We had the following regulatory assets and liabilities (in thousands) as of:
 September 30, 2018December 31, 2017September 30, 2017
Regulatory assets   
Deferred energy and fuel cost adjustments (a)
$29,976
$20,187
$20,559
Deferred gas cost adjustments (a)
720
31,844
12,833
Gas price derivatives (a)
6,192
11,935
11,297
Deferred taxes on AFUDC (b)
7,804
7,847
15,645
Employee benefit plans (c)
106,734
109,235
105,671
Environmental (a)
972
1,031
1,051
Asset retirement obligations (a)
526
517
514
Loss on reacquired debt (a)
21,431
20,667
21,067
Renewable energy standard adjustment (a)
1,131
1,088
1,956
Deferred taxes on flow through accounting (c) (e)
29,342
26,978
41,900
Decommissioning costs (b)
11,052
13,287
13,989
Gas supply contract termination (a)
15,745
20,001
21,402
Other regulatory assets (a)
28,725
32,837
32,710
Total regulatory assets260,350
297,454
300,594
Less current regulatory assets(48,302)(81,016)(61,023)
Regulatory assets, non-current$212,048
$216,438
$239,571
    
Regulatory liabilities   
Deferred energy and gas costs (a)
$15,980
$3,427
$3,780
Employee benefit plan costs and related deferred taxes (c) (e)
39,332
40,629
66,620
Cost of removal (a)
146,177
130,932
125,360
Excess deferred income taxes (c) (d)
316,625
301,553
52
TCJA revenue reserve20,592


Other regulatory liabilities (c)
11,582
8,585
9,419
Total regulatory liabilities550,288
485,126
205,231
Less current regulatory liabilities(41,442)(6,832)(7,042)
Regulatory liabilities, non-current$508,846
$478,294
$198,189
__________
(a)Recovery of costs, but we are not allowed a rate of return.
(b)In addition to recovery of costs, we are allowed a rate of return.
(c)In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base.
(d)The increase in the regulatory tax liability is primarily related to the revaluation of deferred income tax balances at the lower income tax rate. As of September 30, 2018 and December 31, 2017, all of the liability was classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions or other revenue offsets.
(e)The variance to the prior periods is primarily due to the decrease in federal income tax from 35% to 21% as a result of the TCJA.

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 2017 Annual Report on Form 10-K.


19



TCJA revenue reserve - The TCJA signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21%. Effective January 1, 2018, the key impact of tax reform on existing utility revenues/tariffs established prior to tax reform results primarily from the change in the federal tax rate from 35% to 21% (including the effects of tax gross-ups not yet approved) affecting current income tax expense embedded in those tariffs. Black Hills has been collaborating with utility commissions in the states in which it provides utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We have received state utility commission approvals to provide the benefits of federal tax reform to utility customers in six states. We estimated and recorded a reserve to revenue of approximately $6.0 million and $29 million during the three and nine months ended September 30, 2018, respectively. As of September 30, 2018, $7.9 million has been returned to customers.

A list of states where benefits to customers of federal tax reform have been approved is summarized below.

StateApproximate 2018 Benefit for CustomersStart Date for Customer Benefits
Arkansas$9.7 millionOctober 2018
Colorado$10.8 millionJuly 2018
Iowa$2.4 millionJune 2018
Kansas$1.9 millionApril 2018
Nebraska$3.8 millionJuly 2018
South Dakota$7.7 millionOctober 2018

In support of returning benefits to customers, the three rate review requests filed in 2017 for Arkansas Gas, Wyoming Gas (Northwest Wyoming) and Rocky Mountain Natural Gas (a pipeline system in Colorado) were adjusted to include the benefits to customers of federal tax reform as discussed below.

Rate Reviews

RMNG
In Colorado, new rates for RMNG went into effect June 1, 2018 after an administrative law judge recommended approval of a settlement agreement and the CPUC took no further action. The settlement included $1.1 million in annual revenue increases and an extension of the SSIR to recover costs from 2018 through December 31, 2021. The annual increase is based on a return on equity of 9.9% and a capital structure of 46.63% equity and 53.37% debt. New rates are inclusive of customer benefits related to the TCJA.

Wyoming Gas
On July 16, 2018, the WPSC reached a bench decision approving our Wyoming Gas (Northwest Wyoming) settlement and stipulation with the OCA. We received the final order in the third quarter of 2018. The settlement provides for $1.0 million of new revenue, a return on equity of 9.6%, and a capital structure of 54.0% equity and 46.0% debt. New rates, inclusive of customer benefits related to the TCJA, were effective September 1, 2018.

Arkansas Gas
On October 5, 2018, Arkansas Gas received approval from the APSC for a general rate increase. The new rates will generate approximately $12 million of new annual revenue. The APSC’s approval also allows Arkansas Gas to include $11 million of revenue that is currently being collected through certain rider mechanisms in the new base rates. The new revenue increase is based on a return on equity of 9.61% and a capital structure of 49.1% equity and 50.9% debt. New rates, inclusive of customer benefits related to the TCJA, were effective October 15, 2018.

Wyoming Electric
On October 31, Wyoming Electric received approval from the WPSC for a comprehensive, multi-year settlement regarding its PCA Application filed earlier in 2018. Wyoming Electric’s PCA permits the recovery of costs associated with fuel, purchased electricity and other specified costs, including the portion of the company’s energy that is delivered from the Wygen I PPA with Black Hills Wyoming. Wyoming Electric will provide an aggregate $7.0 million in customer credits through the PCA mechanism in 2018, 2019 and 2020 to resolve all outstanding issues relating to its current and prior PCA filings. The settlement also stipulates the adjustment for the variable cost segment of the Wygen I PPA with Wyoming Electric will escalate by 3.0% annually through 2022, providing price certainty for Wyoming Electric and its customers. As of September 30, 2018, we have recorded a liability of $4.5 million related to the PCA.

20




Nebraska Gas
On June 1, 2018, Nebraska Gas Distribution filed an application with the NPSC requesting a continuation of the SSIR beyond the expiration date of October 31, 2019. On September 5, 2018, the NSPC approved continuation of the SSIR tariff to December 31, 2020. The SSIR provides approximately $6.0 million of revenue annually on investments made prior to January 1, 2018, with investments after that date to be recovered through other methods. If a base rate review is filed prior to expiration of the rider, that rate request will include the remaining investment to be recovered.

Kansas Gas
On June 19, 2018, Kansas Gas received approval from the Kansas Corporation Commission to double annual eligible investments up to $8.0 million for safety related integrity investments under the Gas System Reliability rider.


(6)    MATERIALS, SUPPLIES AND FUEL

The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 September 30, 2018 December 31, 2017 September 30, 2017
Materials and supplies$73,777
 $69,732
 $70,284
Fuel - Electric Utilities2,750
 2,962
 2,993
Natural gas in storage held for distribution46,091
 40,589
 49,589
Total materials, supplies and fuel$122,618
 $113,283
 $122,866



(7)    INVESTMENTS

In February 2018, we contributed $28 million of assets in exchange for equity securities in a privately held company. The carrying value of our investment in the equity securities was determined using the cost method. We review this investment on a periodic basis to determine whether a significant event or change in circumstances has occurred that may have an adverse effect on the value of the investment. We estimate that the fair value of this cost method investment approximated or exceeded its carrying value as of September 30, 2018.

The following table presents the carrying value of our investments (in thousands) as of:
 September 30, 2018 December 31, 2017 September 30, 2017
Cost method investment$28,134
 $
 $
Cash surrender value of life insurance contracts13,068
 13,090
 12,947
Total investments$41,202
 $13,090
 $12,947


(8)    EARNINGS PER SHARE

A reconciliation of share amounts used to compute Earnings (loss) per share in the accompanying Condensed Consolidated Statements of Income was as follows (in thousands):
 Three Months Ended September 30, Nine Months Ended September 30,
 20182017 20182017
      
Net income available for common stock$16,950
$27,663
 $171,871
$126,381
      
Weighted average shares - basic53,364
53,243
 53,346
53,208
Dilutive effect of:     
Equity Units (a)
1,344
2,015
 1,060
1,872
Equity compensation111
174
 102
174
Weighted average shares - diluted54,819
55,432
 54,508
55,254
__________
(a)Calculated using the treasury stock method.

The following outstanding securities were excluded in the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands):
 Three Months Ended September 30, Nine Months Ended September 30,
 20182017 20182017
      
Equity compensation12

 15

Anti-dilutive shares12

 15



(9)    NOTES PAYABLE, CURRENT MATURITIES AND DEBT

We had the following notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 September 30, 2018December 31, 2017September 30, 2017
 Balance OutstandingLetters of CreditBalance OutstandingLetters of CreditBalance OutstandingLetters of Credit
Revolving Credit Facility$
$15,203
$
$26,848
$
$25,391
CP Program112,100

211,300

225,170

Total$112,100
$15,203
$211,300
$26,848
$225,170
$25,391

Revolving Credit Facility and CP Program

On July 30, 2018, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 30, 2023 with two one-year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our Corporate credit rating from S&P, Fitch, and Moody's for our senior unsecured long-term debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.125%, 1.125%, and 1.125%, respectively, at September 30, 2018. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at September 30, 2018. Margins and the commitment fee rate decreased in August 2018 due to our upgraded credit rating from S&P.

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.

21



Our net payments under the CP Program during the nine months ended September 30, 2018 were $99 million and our notes outstanding as of September 30, 2018 were $112 million. As of September 30, 2018, the weighted average interest rate on CP Program borrowings was 2.42%.

Debt Covenants

Under our Revolving Credit Facility and term loan agreement (before each was amended and restated), we were required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. At September 30, 2018, our Consolidated Indebtedness to Capitalization Ratio was calculated by dividing (i) Consolidated Indebtedness (which included letters of credit and certain guarantees issued but excluded the RSNs), by (ii) Capital, which is Consolidated Indebtedness plus Consolidated Net Worth (which excluded noncontrolling interests in subsidiaries and included the aggregate outstanding amount of the RSNs). Under our amended and restated revolving Credit Facility and amended and restated term loan agreement, we are also required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00, but as of September 30, 2018 only, Consolidated Net Worth will include the amount receivable by the Company in connection with the common stock settlement under the purchase contracts which are part of the Equity Units, rather than the outstanding amount of the RSNs.

Our Revolving Credit Facility and term loans require compliance with the following financial covenant at the end of each quarter:
 As of September 30, 2018 Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio61.4% Less than65%

As of September 30, 2018, we were in compliance with this covenant.

Current Maturities

As of September 30, 2018, our $250 million senior unsecured notes due January 11, 2019 and $5.7 million of principal due in the next twelve months on our Corporate term loan due June 7, 2021 are classified as Current maturities of long-term debt on our Condensed Consolidated Balance Sheets.

Long-Term Debt

On August 17, 2018, we issued $400 million principal amount, 4.350% senior unsecured notes due 2033. A portion of these notes were issued in a private exchange that resulted in the retirement of all $299 million principal amount of our RSNs due 2028. The remainder of the notes were sold for cash in a public offering, with the net proceeds being used to pay down short-term debt.

The issuance of these new senior notes was the culmination of a series of transactions that also included the contractually required remarketing of such RSNs on behalf of the holders of our Equity Units, with the proceeds being deposited as collateral to secure the obligations of those holders under the purchase contracts included in the Equity Units (see subsequent event in Note 10). As a result of the remarketing, the annual interest rate on such RSNs was automatically reset to 4.579% (however, because the RSNs were then immediately retired, no interest accrued at this reset rate).

On July 30, 2018, we amended and restated our unsecured term loan due August 2019. This amended and restated term loan, with $300 million outstanding at September 30, 2018, will now mature on July 30, 2020 and has substantially similar terms and covenants as the amended and restated Revolving Credit Facility. 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 September 30, 2018.


22



(10)    EQUITY

A summary of the changes in equity is as follows:

Nine Months Ended September 30, 2018Total Stockholders’ EquityNoncontrolling InterestTotal Equity
  (in thousands) 
Balance at December 31, 2017$1,708,974
$111,232
$1,820,206
Net income (loss)171,871
10,447
182,318
Other comprehensive income3,481

3,481
Dividends on common stock(76,309)
(76,309)
Share-based compensation4,871

4,871
Dividend reinvestment and stock purchase plan220

220
Other stock transactions147

147
Distribution to noncontrolling interest
(13,755)(13,755)
Balance at September 30, 2018$1,813,255
$107,924
$1,921,179

Nine Months Ended September 30, 2017Total Stockholders’ EquityNoncontrolling InterestTotal Equity
  (in thousands) 
Balance at December 31, 2016$1,614,639
$115,495
$1,730,134
Net income (loss)126,381
10,567
136,948
Other comprehensive income2,317

2,317
Dividends on common stock(71,334)
(71,334)
Share-based compensation5,853

5,853
Dividend reinvestment and stock purchase plan2,300

2,300
Redeemable noncontrolling interest(886)
(886)
Cumulative effect of ASU 2016-09 implementation3,714

3,714
Other stock transactions(180)
(180)
Distribution to noncontrolling interest
(12,884)(12,884)
Balance at September 30, 2017$1,682,804
$113,178
$1,795,982

At-the-Market Equity Offering Program

On August 4, 2017, we renewed our ATM equity offering program which reset the size of the program to an aggregate value of up to $300 million. The renewed program, which allows us to sell shares of our common stock, is the same as the prior program other than the aggregate value increased from $200 million 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. We did not issue any common shares during the nine months ended September 30, 2018 or September 30, 2017 under the ATM equity offering program.


23



Subsequent Event - Equity Units Settlement

On October 29, 2018, we announced the settlement rate for the stock purchase contracts that are components of the Equity Units issued November 23, 2015. The settlement rate was based upon the minimum settlement rate, as adjusted to account for past dividends, because the average of the closing price per share of Black Hills Corporation common stock on the New York Stock Exchange for the 20 consecutive trading days ending on October 29, 2018 exceeded the threshold appreciation price. Each holder of the Equity Units on that date, following payment of $50.00 for each unit which it holds, received 1.0655 shares of Black Hills Corporation common stock for each such unit. The holders' obligations to make such payments were satisfied with proceeds generated by the successful remarketing on August 17, 2018, of the RSNs that formerly constituted a component of the Equity Units.

Upon settlement of all outstanding stock purchase obligations, the Company received gross proceeds of approximately $299 million in exchange for approximately 6.372 million shares of common stock. Proceeds will be used to pay down the $250 million senior unsecured notes due January 11, 2019, with the balance used to pay down short-term debt.

As of November 1, 2018, after the Equity Units settlement, we had shares outstanding of approximately 59.97 million.


(11)    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 Policies and Procedures as discussed in our 2017 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 the following market risks including, 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; and

Interest rate risk associated with our variable rate debt.

Credit Risk

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

For production and generation 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 12.


24



Utilities

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

For our regulated utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Condensed Consolidated Balance Sheets in accordance with state commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Condensed Consolidated Statements of Income.

We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/or sales during time frames ranging from October 2018 through May 2020; 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 effective portion of the gain or loss on these designated derivatives is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Fuel, purchased power and cost of natural gas sold in the accompanying Condensed Consolidated Statements of Income. Effectiveness of our hedging 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:
 September 30, 2018 December 31, 2017 September 30, 2017
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
Natural gas futures purchased5,300,000
 27 8,330,000
 36 10,250,000
 39
Natural gas options purchased, net9,670,000
 16 3,540,000
 14 7,360,000
 17
Natural gas basis swaps purchased5,140,000
 27 8,060,000
 36 9,170,000
 39
Natural gas over-the-counter swaps, net (b)
4,370,000
 20 3,820,000
 29 4,600,000
 20
Natural gas physical contracts, net (c)
19,539,851
 33 12,826,605
 35 21,071,714
 38
__________
(a)Term reflects the maximum forward period hedged.
(b)
As of September 30, 2018, 2,236,000 MMBtus were designated as cash flow hedges for the natural gas over-the-counter swaps purchased.
(c)Volumes exclude contracts that qualify for the normal purchase, normal sales exception.

Based on September 30, 2018 prices, a $0.1 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At September 30, 2018, the Company posted $0.7 million related to such provisions, which is included in Other current assets on the Condensed Consolidated Balance Sheets.


25



Financing Activities

At September 30, 2018, we had no outstanding interest rate swap agreements. Our last interest rate swap agreement with a $50 million notional value, which was designated to borrowings on our Revolving Credit Facility, expired in January 2017.

Discontinued Operations

Our Oil and Gas segment was exposed to risks associated with changes in the market prices of oil and gas. Through December 2017, we used exchange traded futures, swaps and options to hedge portions of our crude oil and natural gas production to mitigate commodity price risk and preserve cash flows. Hedge accounting was elected on the swaps and futures contracts. These transactions were designated upon inception as cash flow hedges, documented under accounting standards for derivatives and hedging and initially met prospective effectiveness testing. As a result of divesting our Oil and Gas assets, these activities were discontinued and there were no outstanding derivative agreements as of September 30, 2018 or December 31, 2017. At September 30, 2017, we had outstanding crude oil futures and swap contracts with notional volumes of 54,000 Bbls, crude oil option contracts with notional volumes of 9,000 Bbls and natural gas futures and swap contracts with notional volumes of 540,000 MMBtus.

Cash Flow Hedges

The impacts of cash flow hedges on our Condensed Consolidated Statements of Income is presented below for the three and nine months ended September 30, 2018 and 2017 (in thousands). Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.
Three Months Ended September 30, 2018
Derivatives in Cash Flow Hedging Relationships 
Location of
Reclassifications from AOCI into Income
 
Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
(Settlements)
 
Location of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
 
Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps Interest expense $(712) Interest expense $
Commodity derivatives Fuel, purchased power and cost of natural gas sold (18) Fuel, purchased power and cost of natural gas sold 
Total   $(730)   $

Three Months Ended September 30, 2017
Derivatives in Cash Flow Hedging Relationships 
Location of
Reclassifications from AOCI into Income
 
Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
(Settlements)
 
Location of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
 
Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps Interest expense $(713) Interest expense $
Commodity derivatives Net (loss) from discontinued operations 295
 Net (loss) from discontinued operations 
Commodity derivatives Fuel, purchased power and cost of natural gas sold (34) Fuel, purchased power and cost of natural gas sold 
Total   $(452)   $


26



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

         
Nine Months Ended September 30, 2017
Derivatives in Cash Flow Hedging Relationships 
Location of
Reclassifications from AOCI into Income
 
Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
(Settlements)
 
Location of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
 
Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps Interest expense $(2,228) Interest expense $
Commodity derivatives Net (loss) from discontinued operations 954
 Net (loss) from discontinued operations 
Commodity derivatives Fuel, purchased power and cost of natural gas sold (20) Fuel, purchased power and cost of natural gas sold 
Total   $(1,294)   $

The following tables summarize the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the three and nine months ended September 30, 2018 and 2017. The amounts included in the tables below exclude gains and losses arising from ineffectiveness because these amounts, if any, are immediately recognized in the Condensed Consolidated Statements of Income as incurred.
 Three Months Ended September 30,
 2018 2017
 (in thousands)
Increase (decrease) in fair value:   
Forward commodity contracts$30
 $(254)
Recognition of (gains) losses in earnings due to settlements:   
Interest rate swaps712
 713
Forward commodity contracts18
 (261)
Total other comprehensive income (loss) from hedging$760
 $198
    
 Nine Months Ended September 30,
 2018 2017
 (in thousands)
Increase (decrease) in fair value:   
Forward commodity contracts$(219) $1,197
Recognition of (gains) losses in earnings due to settlements:   
Interest rate swaps2,138
 2,228
Forward commodity contracts802
 (934)
Total other comprehensive income (loss) from hedging$2,721
 $2,491


27



Derivatives Not Designated as Hedge Instruments

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2018 and 2017 (in thousands). Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.
  Three Months Ended September 30,
  2018 2017
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 derivativesNet (loss) from discontinued operations$
 $(53)
Commodity derivativesFuel, purchased power and cost of natural gas sold(96) (322)
  $(96) $(375)

  Nine Months Ended September 30,
  2018 2017
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 derivativesNet (loss) from discontinued operations$
 $90
Commodity derivativesFuel, purchased power and cost of natural gas sold929
 (1,822)
  $929
 $(1,732)

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 assets or Regulatory liability accounts related to the hedges in our utilities were $6.2 million, $12 million and $11 million at September 30, 2018, December 31, 2017 and September 30, 2017, respectively.



28



(12)    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 2017 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

Discontinued Operations:

Oil and gas derivative instruments are included in assets and liabilities held for sale discussed in Note 18.

Utilities Segments:

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.

Corporate Activities:

As of September 30, 2018, we no longer have derivatives within our corporate activities as our last interest rate swaps matured in January 2017.

Recurring Fair Value Measurements

There have been no significant transfers between Level 1 and Level 2 derivative balances. Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties.

Oil and gas derivative instruments are included in assets and liabilities held for sale discussed in Note 18. The following tables set forth by level within the fair value hierarchy present gross assets and gross liabilities and related offsetting cash collateral and counterparty netting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments.


29



 As of September 30, 2018
 Level 1Level 2Level 3 
Cash Collateral and Counterparty
Netting
Total
 (in thousands)
Assets:      
Commodity derivatives — Utilities$
$5,882
$
 $(4,469)$1,413
Total$
$5,882
$
 $(4,469)$1,413
       
Liabilities:      
Commodity derivatives — Utilities$
$10,033
$
 $(8,777)$1,256
Total$
$10,033
$
 $(8,777)$1,256

 As of December 31, 2017
 Level 1Level 2Level 3 
Cash Collateral and Counterparty
Netting
Total
 (in thousands)
Assets:      
Commodity derivatives — Utilities$
$1,586
$
 $(1,282)$304
Total$
$1,586
$
 $(1,282)$304
       
Liabilities:      
Commodity derivatives — Utilities$
$13,756
$
 $(11,497)$2,259
Total$
$13,756
$
 $(11,497)$2,259

 As of September 30, 2017
 Level 1Level 2Level 3 
Cash Collateral and Counterparty
Netting
Total
 (in thousands)
Assets:      
Commodity derivatives — Utilities$
$2,880
$
 $(2,448)$432
Total$
$2,880
$
 $(2,448)$432
       
Liabilities:      
Commodity derivatives — Utilities$
$12,647
$
 $(11,125)$1,522
Total$
$12,647
$
 $(11,125)$1,522

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.


30



The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands):
As of September 30, 2018
 Balance Sheet Location 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:    
Commodity derivativesDerivative assets — current $142
$
Commodity derivativesOther assets, non-current 21

Commodity derivativesDerivative liabilities — current 
273
Commodity derivativesOther deferred credits and other liabilities 
10
Total derivatives designated as hedges  $163
$283
     
Derivatives not designated as hedges:    
Commodity derivativesDerivative assets — current $1,250
$
Commodity derivativesDerivative liabilities — current 
881
Commodity derivativesOther deferred credits and other liabilities 
92
Total derivatives not designated as hedges  $1,250
$973

As of December 31, 2017
 Balance Sheet Location 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:    
Commodity derivativesDerivative liabilities — current $
$817
Commodity derivativesOther deferred credits and other liabilities 
67
Total derivatives designated as hedges  $
$884
     
Derivatives not designated as hedges:    
Commodity derivativesDerivative assets — current $304
$
Commodity derivativesDerivative liabilities — current 
1,264
Commodity derivativesOther deferred credits and other liabilities 
111
Total derivatives not designated as hedges  $304
$1,375


31



As of September 30, 2017
 Balance Sheet Location 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:    
Commodity derivativesDerivative assets — current $2
$
Commodity derivativesCurrent assets held for sale 225

Commodity derivativesDerivative liabilities — current 
422
Commodity derivativesCurrent liabilities held for sale 
89
Commodity derivativesOther deferred credits and other liabilities 
49
Commodity derivativesNoncurrent liabilities held for sale 
10
Total derivatives designated as hedges  $227
$570
     
Derivatives not designated as hedges:    
Commodity derivativesDerivative assets — current $430
$
Commodity derivativesDerivative liabilities — current 
1,036
Commodity derivativesOther deferred credits and other liabilities 
15
Commodity derivativesNoncurrent liabilities held for sale 
15
Total derivatives not designated as hedges  $430
$1,066

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 2017 Annual Report on Form 10-K.

(13)    FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 12, were as follows (in thousands) as of:
 September 30, 2018 December 31, 2017 September 30, 2017
 
Carrying
Amount
Fair Value 
Carrying
Amount
Fair Value 
Carrying
Amount
Fair Value
Cash and cash equivalents (a)
$10,001
$10,001
 $15,420
$15,420
 $13,449
$13,449
Restricted cash (a)
$3,241
$3,241
 $2,820
$2,820
 $2,683
$2,683
Notes payable (b)
$112,100
$112,100
 $211,300
$211,300
 $225,170
$225,170
Long-term debt, including current maturities (c) (d)
$3,207,132
$3,289,770
 $3,115,143
$3,350,544
 $3,115,607
$3,362,971
__________
(a)Carrying value approximates fair value due to either the short-term length of maturity or variable interest rates that approximate prevailing market rates, and therefore is classified in Level 1 in the fair value hierarchy.
(b)Notes payable consist of commercial paper borrowings and borrowings on our Revolving Credit Facility. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy.
(c)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.
(d)Carrying amount of long-term debt is net of deferred financing costs.


32



(14)
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 Nine Months Ended
September 30, 2018September 30, 2017 September 30, 2018September 30, 2017
Gains and (losses) on cash flow hedges:      
Interest rate swapsInterest expense$(712)$(713) $(2,138)$(2,228)
Commodity contractsNet (loss) from discontinued operations
295
 
954
Commodity contracts
Fuel, purchased power and cost of natural gas sold

(18)(34) (802)(20)
  (730)(452) (2,940)(1,294)
Income taxIncome tax benefit (expense)149
154
 643
435
Total reclassification adjustments related to cash flow hedges, net of tax $(581)$(298) $(2,297)$(859)
       
Amortization of components of defined benefit plans:      
Prior service costOperations and maintenance$44
$49
 $133
$146
       
Actuarial gain (loss)Operations and maintenance(621)(414) (1,865)(1,242)
  (577)(365) (1,732)(1,096)
Income taxIncome tax benefit (expense)128
128
 380
393
Total reclassification adjustments related to defined benefit plans, net of tax $(449)$(237) $(1,352)$(703)
Total reclassifications $(1,030)$(535) $(3,649)$(1,562)


33



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, 2017$(19,581)$(518)$(21,103)$(41,202)
Other comprehensive income (loss)    
before reclassifications
(168)
(168)
Amounts reclassified from AOCI1,682
615
1,352
3,649
Reclassifications of certain tax effects from AOCI15

3
18
Ending Balance September 30, 2018$(17,884)$(71)$(19,748)$(37,703)
     
     
 Interest Rate SwapsCommodity DerivativesEmployee Benefit PlansTotal
Balance as of December 31, 2016$(18,109)$(233)$(16,541)$(34,883)
Other comprehensive income (loss)    
before reclassifications
755

755
Amounts reclassified from AOCI1,449
(590)703
1,562
Ending Balance September 30, 2017$(16,660)$(68)$(15,838)$(32,566)

(15)    SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Nine Months EndedSeptember 30, 2018 September 30, 2017
 (in thousands)
Non-cash investing and financing activities —   
Property, plant and equipment acquired with accrued liabilities$49,631
 $33,409
Increase (decrease) in capitalized assets associated with asset retirement obligations$155
 $1,362
    
Cash (paid) refunded during the period —   
Interest (net of amounts capitalized)$(104,035) $(102,008)
Income taxes (paid) refunded$(14,842) $1



34



(16)    EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

The components of net periodic benefit cost for the Defined Benefit Pension Plan were as follows (in thousands):
 Three Months Ended September 30, Nine Months Ended September 30,
 20182017 20182017
Service cost$1,708
$1,759
 $5,125
$5,276
Interest cost3,867
3,880
 11,602
11,640
Expected return on plan assets(6,185)(6,130) (18,555)(18,388)
Prior service cost15
15
 44
44
Net loss (gain)2,158
1,002
 6,473
3,005
Net periodic benefit cost$1,563
$526
 $4,689
$1,577

Defined Benefit Postretirement Healthcare Plans

The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plans were as follows (in thousands):
 Three Months Ended September 30, Nine Months Ended September 30,
 20182017 20182017
Service cost$573
$575
 $1,718
$1,725
Interest cost521
533
 1,563
1,600
Expected return on plan assets(57)(79) (170)(237)
Prior service cost (benefit)(99)(109) (297)(327)
Net loss (gain)54
125
 162
375
Net periodic benefit cost$992
$1,045
 $2,976
$3,136

Supplemental Non-qualified Defined Benefit and Defined Contribution Plans

The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands):
 Three Months Ended September 30, Nine Months Ended September 30,
 20182017 20182017
Service cost$632
$612
 $1,347
$2,048
Interest cost293
319
 878
957
Prior service cost

 1
1
Net loss (gain)250
251
 750
751
Net periodic benefit cost$1,175
$1,182
 $2,976
$3,757

For the three and nine months ended September 30, 2018, service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other income (expense), net, on the Condensed Consolidated Statements of Income. For the three and nine months ended September 30, 2017, service costs and non-service costs were recorded in Operations and maintenance expense. Because prior years’ costs were not considered material, they were not reclassified on the Condensed Consolidated Statements of Income. See Note 1 for additional information.

35



Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. On July 25, 2018, we made a contribution of approximately $13 million (included in the table below) to the Defined Benefit Pension Plan. Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made in 2018 and anticipated contributions for 2018 and 2019 are as follows (in thousands):
 Contributions MadeContributions MadeAdditional ContributionsContributions
 Three Months Ended September 30, 2018Nine Months Ended September 30, 2018Anticipated for 2018Anticipated for 2019
Defined Benefit Pension Plan$12,700
$12,700
$
$12,700
Non-pension Defined Benefit Postretirement Healthcare Plans$1,234
$3,702
$1,234
$3,821
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans$343
$1,029
$343
$1,623

(17)    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 2017 Annual Report on Form 10-K except for those described below.

Busch Ranch I

Busch Ranch Wind Farm is a 29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and AltaGas. Colorado Electric has a 50% ownership interest in the wind farm. On September 20, 2018, Black Hills Electric Generation agreed to purchase AltaGas’s 50% interest in Busch Ranch for $16 million. The purchase, which is subject to FERC approval, is expected to be finalized by the end of 2018.

Dividend Restrictions

Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of September 30, 2018, we were in compliance with the debt covenants.

Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our stockholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries.

Our utilities are generally limited to the amount of dividends allowed to be paid to us as a utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions and financing agreements. As of September 30, 2018, the restricted net assets at our Electric Utilities and Gas Utilities were approximately $257 million.


(18)    DISCONTINUED OPERATIONS

Results of operations for discontinued operations have been classified as Loss from discontinued operations, net of income taxes in the accompanying Condensed Consolidated Statements of Income. Current assets, noncurrent assets, current liabilities and non-current liabilities of the discontinued operations have been reclassified and reflected on the accompanying Condensed Consolidated Balance Sheets as “Current assets held for sale,” “Noncurrent assets held for sale,” “Current liabilities held for sale,” and “Noncurrent liabilities held for sale”, respectively. Prior periods relating to our discontinued operations have also been 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. As of September 30, 2018, we have sold nearly all of our oil and gas assets and we closed our oil and gas office in August. Transaction closing for the last few assets and final accounting are expected within the fourth quarter. We expect to transfer any associated liabilities, and settle substantially all remaining liabilities by December 31, 2018.

36




In the process of divesting our Oil and Gas segment, we performed a fair value assessment of the assets and liabilities classified as held for sale. We evaluated our disposal groups classified as held for sale based on the lower of carrying value or fair value less cost to sell. The market approach was based on our recent sales of assets and pending sale transactions of our other properties.

There is risk involved when determining the fair value of assets, as there may be unforeseen events and changes in circumstances and market conditions that have a material impact on the estimated amount and timing of future cash flows. In addition, the fair value of the assets and liabilities could be different using different estimates and assumptions in the valuation techniques used. We believe that the estimates used in calculating the fair value of our assets and liabilities held for sale are reasonable based on the information that was known when the estimates were made and how they compared with the additional property sales occurring after December 31, 2017.

At December 31, 2017, the fair value of our held for sale assets was less than our carrying value, which required an after-tax write down of $13 million. There were no further adjustments made to the fair value of our held for sale assets at September 30, 2018.

During the nine months ended September 30, 2018, we recorded $2.9 million of expenses comprised of royalty payments and reclamation costs related to final closing on the sale of BHEP assets.

Total assets and liabilities of the Oil and Gas segment at September 30, 2018 and December 31, 2017 have been classified as Current assets held for sale and Current liabilities held for sale on the accompanying Condensed Consolidated Balance Sheets due to the expected final disposals occurring by the end of 2018. Held for sale assets and liabilities at September 30, 2017 are classified as current and non-current (in thousands):
 September 30, 2018December 31, 2017September 30, 2017
Other current assets$75
$10,360
$8,457
Derivative assets, current and noncurrent

225
Deferred income tax assets, noncurrent, net


16,966
12,571
Property, plant and equipment, net2,779
56,916
96,085
Other current liabilities(2,138)(18,966)(7,597)
Derivative liabilities, current and noncurrent

(114)
Deferred income tax liabilities, noncurrent, net

(400)

Other noncurrent liabilities
(22,808)(23,319)
Net assets (liabilities)$316
$42,468
$86,308

At September 30, 2018, December 31, 2017 and September 30, 2017, the Oil and Gas segment’s net deferred tax assets and liabilities were primarily comprised of basis differences on oil and gas properties.

The Oil and Gas segment’s other current liabilities at September 30, 2018 consisted primarily of accrued royalties, payroll and property taxes. Current liabilities at December 31, 2017 consisted primarily of a liability contingent on final approval from the Bureau of Indian Affairs on the Jicarilla property sale, accrued royalties, payroll and property taxes. Current liabilities at September 30, 2017 consisted primarily of accrued royalties, payroll and property taxes. Other noncurrent liabilities at December 31, 2017 and September 30, 2017 consisted primarily of asset retirement obligations relating to plugging and abandonment of oil and gas wells.


37



(19)    INCOME TAXES

The effective tax rate differs from the federal statutory rate as follows:
 Three Months Ended September 30,
Tax (benefit) expense20182017
Federal statutory rate21.0 %35.0 %
State income tax (net of federal tax effect) (a)
(6.3)(3.4)
Percentage depletion in excess of cost(0.5)(0.9)
Accounting for uncertain tax positions adjustment
(0.6)
Noncontrolling interest (b)
(1.3)(3.0)
Tax credits (c)
(5.3)(1.6)
Effective tax rate adjustment (d)

3.9
Flow-through adjustments(1.5)(1.6)
TCJA change in estimate (e)
17.6

AFUDC equity(0.1)
Other tax differences1.9
1.3
 25.5 %29.1 %
__________
(a)Adjustment to the deferred state rate and reduced state tax expense for the quarter.
(b)The adjustment reflects the noncontrolling interest attributable to the sale in April 2016 of 49.9% of the membership interests of COIPP LLC.
(c)The tax credits are due to the production tax credits for the Peak View wind farm.
(d)Adjustment to reflect our projected annual effective tax rate, pursuant to ASC 740-270.
(e)The TCJA was signed into law on December 22, 2017. In accordance with ASC 740, net deferred tax assets and liabilities were revalued as of December 31, 2017 due to the reduction in the federal income tax rate from 35% to 21%. During the three months ended September 30, 2018, we recorded an additional $5.3 million of tax expense associated with changes in the prior estimated impacts of tax reform on deferred income taxes.


38



   
 Nine Months Ended September 30,
Tax (benefit) expense20182017
Federal statutory rate21.0 %35.0 %
State income tax (net of federal tax effect)0.4
0.3
Percentage depletion in excess of cost(0.4)(0.6)
Accounting for uncertain tax positions adjustment
(0.2)
Noncontrolling interest(1.1)(1.9)
IRC 172(f) carryback claim (a)

(1.0)
Tax credits (b)
(2.6)(1.6)
Effective tax rate adjustment
0.3
Flow-through adjustments(0.8)(1.2)
TCJA change in estimate (c)
4.3

AFUDC equity(0.1)
Jurisdictional simplification project (d)
(28.1)
Other tax differences0.7
0.3
 (6.7)%29.4 %
__________
(a)During the first quarter of 2017, the Company filed amended income tax returns for the years 2006 through 2008 to carryback specified liability losses in accordance with IRC172(f). As a result of filing the amended returns, the Company’s accrued tax liability interest decreased, certain valuation allowances increased and the previously recorded domestic production activities deduction decreased.
(b)The tax credits are due to the production tax credits for the Peak View wind farm.
(c)The TCJA was signed into law on December 22, 2017. In accordance with ASC 740, net deferred tax assets and liabilities were revalued as of December 31, 2017 due to the reduction in the federal income tax rate from 35% to 21%. During the nine months ended September 30, 2018, we recorded an additional $7.5 million of tax expense associated with changes in the prior estimated impacts of tax reform on deferred income taxes.
(d)Tax benefit from legal restructuring associated with amortizable goodwill as part of jurisdictional simplification.

Tax benefit related to legal restructuring

As part of the Company’s ongoing efforts to continue to integrate the legal entities that the Company has acquired in recent years, certain legal entity restructuring transactions occurred on March 31, 2018.  As a result of these transactions, $49 million of deferred income tax assets, related to goodwill that is amortizable for tax purposes, were recorded and deferred tax benefits of $49 million were recorded to income tax benefit (expense) on the Condensed Consolidated Statements of Income. Due to this being a common control transaction, it had no effect on the other assets and liabilities of these entities.

TCJA - Deferred Taxes

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. The Company remeasured deferred income taxes at the 21% federal tax rate as of December 31, 2017, which reflected our provisional estimate of the impact of the TCJA, under SEC Staff Accounting Bulletin No. 118. The entities subject to regulatory construct have made their best estimate regarding the probability of settlements of net regulatory liabilities established pursuant to the TCJA. The amount of the settlements may change based on decisions and actions by the state regulatory commissions. In addition to current year utility revenue reserves as disclosed in Note 5, we recorded additional changes in estimates of the provisional amounts recorded at December 31, 2017, primarily related to bonus depreciation and other plant and property items, after filing our 2017 tax returns which increased tax expense by $5.3 million for the three months, and decreased tax benefit by $7.5 million for the nine months ended September 30, 2018. We will continue to evaluate subsequent regulations, clarifications and interpretations of the assumptions made, which could change our estimates related to the TCJA, which we expect to finalize in the fourth quarter.


(20)    ACCRUED LIABILITIES

The following amounts by major classification are included in Accrued liabilities in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 September 30, 2018December 31, 2017September 30, 2017
Accrued employee compensation, benefits and withholdings$57,600
$52,467
$52,841
Accrued property taxes37,660
42,029
36,993
Customer deposits and prepayments42,002
44,420
41,012
Accrued interest and contract adjustment payments31,139
33,822
30,977
CIAC current portion1,552
1,552
1,575
Other (none of which is individually significant)31,400
45,172
43,381
Total accrued liabilities$201,353
$219,462
$206,779


(21)    SUBSEQUENT EVENTS

There are no subsequent events, other than those disclosed in Note 5 and Note 10.

39



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 210,000 customers in South Dakota, Wyoming, Colorado and Montana. 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 1,042,000 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 52,000 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 63,000 and 31,000 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.

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, as well as changes in market prices. In particular, the normal peak usage season for our electric utilities is June through August while the normal peak usage season for our gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and nine months ended September 30, 2018 and 2017, and our financial condition as of September 30, 2018, December 31, 2017 and September 30, 2017, 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 66.

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.


40



Results of Operations

Executive Summary, Significant Events and Overview

Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017. Net income from continuing operations available for common stock for the three months ended September 30, 2018 was $18 million, or $0.32 per diluted share, compared to $29 million, or $0.52 per diluted share, reported for the same period in 2017. The variance to the prior year included the following:

Electric Utilities’ earnings decreased $5.7 million primarily due a settlement agreement with the WPSC which decreased gross margins by $3.4 million, unfavorable summer weather compared to prior year, higher operating expenses driven by outside services and employee costs and $2.8 million of tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes;
Gas Utilities’ earnings decreased $8.9 million primarily due to unfavorable weather compared to prior year, higher operating expenses driven by employee costs and outside services and $2.6 million of tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes;
Power Generation’s earnings increased $0.5 million primarily due to the reduction in the federal tax rate from 35% to 21% from the TCJA; and
Corporate and Other expenses decreased $2.9 million due to lower interest expense and higher prior year operating costs previously allocated to our Oil and Gas segment which were not reclassified to discontinued operations, largely allocated to operating segments in 2018.

Net income available for common stock for the three months ended September 30, 2018 was $17 million, or $0.31 per diluted share, compared to $28 million, or $0.50 per diluted share reported for the same period in 2017. (Loss) from discontinued operations for the three months ended September 30, 2018 was $(0.9) million, or $(0.02) per diluted share compared to $(1.3) million or $(0.02) per diluted share reported for the same period in 2017.

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017. Net income from continuing operations available for common stock for the nine months ended September 30, 2018 was $177 million, or $3.26 per diluted share, compared to $130 million, or $2.35 per diluted share, reported for the same period in 2017. The variance to the prior year included the following:

Gas Utilities’ earnings increased $52 million primarily due to the recognition of a deferred tax benefit of $49 million resulting from legal entity restructuring associated with amortizable goodwill for tax purposes; earnings also benefited from colder winter weather and increased sales of natural gas, partially offset by an increase in operating expenses;
Electric Utilities’ earnings decreased $5.1 million due primarily to a settlement agreement with the WPSC which decreased gross margins by $3.7 million; other variances to the prior year were due to higher operating expenses driven by outside services and employee costs and $3.2 million of tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes, partially offset by higher rider revenues from recent transmission investments, higher power marketing and wholesale margins, and favorable weather;
Power Generation’s earnings decreased $0.7 million primarily due to higher operating expenses;
Mining earnings increased $0.5 million primarily due to higher coal sales from increased price per ton sold, partially offset by higher operating expenses and tax expense.
Corporate and other expenses decreased $1.1 million primarily due to higher tax benefits recognized in the prior year and higher prior year operating costs previously allocated to our Oil and Gas segment which were not reclassified to discontinued operations, largely allocated to operating segments in 2018.

Net income available for common stock for the nine months ended September 30, 2018 was $172 million, or $3.15 per diluted share, compared to $126 million, or $2.29 per diluted share reported for the same period in 2017. (Loss) from discontinued operations for the nine months ended September 30, 2018 was $(5.6) million, or $(0.10) per diluted share compared to $(3.5) million or $(0.06) per diluted share reported for the same period in 2017.


41



The following table summarizes select financial results by operating segment and details significant items (in thousands):
 Three Months Ended September 30,Nine Months Ended September 30,
 20182017Variance20182017Variance
Revenue      
Revenue$357,370
$366,885
$(9,515)$1,358,519
$1,319,573
$38,946
Inter-company eliminations(35,391)(31,274)(4,117)(105,447)(94,605)(10,842)
 $321,979
$335,611
$(13,632)$1,253,072
$1,224,968
$28,104
Net income (loss) from continuing operations available for common stock      
Electric Utilities (b)
$21,578
$27,324
$(5,746)$63,313
$68,386
$(5,073)
Gas Utilities (a) (b)
(13,277)(4,329)(8,948)93,182
41,409
51,773
Power Generation (b)
6,691
6,155
536
17,319
18,017
(698)
Mining (b)
3,572
3,477
95
9,561
9,048
513
 18,564
32,627
(14,063)183,375
136,860
46,515
Corporate and Other (b)
(757)(3,664)2,907
(5,877)(6,994)1,117
Net income from continuing operations17,807
28,963
(11,156)177,498
129,866
47,632
(Loss) from discontinued operations, net of tax(857)(1,300)443
(5,627)(3,485)(2,142)
Net income available for common stock$16,950
$27,663
$(10,713)$171,871
$126,381
$45,490
__________
(a)
Net income (loss) from continuing operations for the nine months ended September 30, 2018 included a $49 million tax benefit resulting from legal entity restructuring. See Note 19 of the Notes to Condensed Consolidated Financial Statements for more information.
(b)Net income (loss) from continuing operations for the three and nine months ended September 30, 2018 included approximately $5.3 million and $7.5 million of income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes. The impact to our operating segments and Corporate and Other for the three and nine months ended September 30, 2018 was: Electric Utilities $2.8 million and $3.2 million; Gas Utilities $2.6 million and $2.6 million, Mining ($0.0) million and $0.5 million; Power Generation ($0.0) million and $0.7 million; and Corporate and Other ($0.1) million and $0.6 million, respectively.

Overview of Business Segments and Corporate Activity

Electric Utilities Segment

On October 31, Wyoming Electric received approval from the WPSC for a comprehensive, multi-year settlement regarding its PCA Application filed earlier in 2018. Wyoming Electric will provide a total of $7.0 million in customer credits through the PCA mechanism in 2018, 2019 and 2020 to resolve several years of disputed issues related to PCA dockets before the commission. The settlement also stipulates that the adjustment for the variable cost segment of the Wygen I Power Purchase Agreement with Wyoming Electric (an affiliate company) will escalate by 3% annually through 2022.

On October 3, 2018, Colorado Electric set a new winter peak load of 313 MW, exceeding the previous summer peak of 310 MW set in February 2011.

Cooling degree days for the three and nine months ended September 30, 2018 were 9% higher and 29% higher than the 30-year average (normal) compared to 15% higher than normal for the same periods in 2017.

Heating degree days for the three and nine months ended September 30, 2018 were 20% lower and 5% higher than normal compared to 8% and 11% lower than normal for the same periods in 2017.

Wyoming Electric and Colorado Electric set new summer peak loads:

On July 10, 2018, Wyoming Electric set a new all-time peak load of 254 MW, exceeding the previous summer peak of 249 MW set in July 2017.

On June 27, 2018, Colorado Electric set a new all-time peak load of 413 MW, exceeding the previous summer peak of 412 MW set in July 2016.

42




On July 25, 2018, South Dakota Electric placed in service the first 48-mile segment of a $70 million, 175-mile, 230-kilovolt transmission line from Rapid City, South Dakota, to Stegall, Nebraska. The remaining segment is expected to be in service by the end of 2019.

On April 25, 2018, Colorado Electric received approval from the CPUC to contract with Black Hills Electric Generation for the 60 megawatt Busch Ranch II wind project. The project is currently under construction and is expected to be in service by the end of 2019. This renewable energy will enable Colorado Electric to comply with Colorado's Renewable Energy Standard.

Gas Utilities Segment

Rate Review updates:

On October 5, 2018, Arkansas Gas received approval from the APSC for a general rate increase. The new rates will generate approximately $12 million of new revenue. The APSC’s approval also allows Arkansas Gas to include $11 million of revenue that is currently being collected through certain rider mechanisms in the new base rates. The new revenue increase is based on a return on equity of 9.61% and a capital structure of 49.1% equity and 50.9% debt. New rates, inclusive of customer benefits related to the TCJA, were effective October 15, 2018.

On July 16, 2018, the WPSC reached a bench decision approving our Wyoming Gas (Northwest Wyoming) settlement and stipulation with the OCA. We received the final order in the third quarter of 2018. The settlement provides for $1.0 million of new revenue, a return on equity of 9.6%, and a capital structure of 54.0% equity and 46.0% debt. New rates, inclusive of customer benefits related to the TCJA, were effective September 1, 2018.

In Colorado, new rates for RMNG went into effect June 1, 2018 after an administrative law judge recommended approval of a settlement agreement and the CPUC took no further action. The settlement included $1.1 million in annual revenue increases and an extension of SSIR to recover costs from 2018 through 2021. The annual increase is based on a return on equity of 9.9% and a capital structure of 46.63% equity and 53.37% debt. New rates are inclusive of customer benefits related to the TCJA.

Wyoming Gas filed for a CPCN on May 18, 2018 with the WPSC to construct a new $54 million, 35-mile natural gas pipeline (Natural Bridge Pipeline) to enhance reliability of supply for approximately 57,000 customers in its Casper division in central Wyoming.

Certain legal entity restructuring transactions occurred on March 31, 2018 as part of the Company’s ongoing efforts to continue to integrate the legal entities that the Company has acquired in recent years.  As a result of these transactions, additional deferred income tax assets of $49 million, related to goodwill that is amortizable for tax purposes, were recorded with a corresponding deferred tax benefit recorded on the Condensed Consolidated Statements of Income.

Heating degree days at the Gas Utilities for the three and nine months ended September 30, 2018 were 27% lower and comparable to the 30-year average (normal), respectively, compared to 22% and 12% lower than normal for the same periods in 2017.

Power Generation

On April 25, 2018, Black Hills Electric Generation was selected to provide 60 megawatts of renewable energy to Colorado Electric from the Busch Ranch II wind project, which is expected to be in service by the end of 2019.

Corporate and Other

On November 1, 2018, we completed settlement of the stock purchase contracts that are components of the Equity Units issued in November 2015. Upon settlement of all outstanding stock purchase obligations, the Company received gross proceeds of $299 million in exchange for approximately 6.372 million shares of common stock.

On October 11, 2018, Fitch affirmed Black Hills’ credit rating at BBB+ and maintained a Stable outlook.

43




On August 17, 2018, we completed a public debt offering of $400 million principal amount of 4.350% senior unsecured notes. The proceeds were used to repay the $299 million principal amount of our RSNs due 2028 and pay down short-term debt.

On August 9, 2018, S&P upgraded Black Hills’ credit rating to BBB+ with a Stable outlook and South Dakota Electric’s credit rating to A.

On July 30, 2018, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 30, 2023 with two one-year extension options (subject to consent from lenders). This facility is similar to the former Revolving Credit Facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and the banks increasing or providing new commitments, to increase total commitments of the facility up to $1.0 billion.

On July 30, 2018, we amended and restated our unsecured term loan due August 2019. This amended and restated term loan, with $300 million outstanding at September 30, 2018, matures on July 30, 2020.

On July 19, 2018, Fitch affirmed South Dakota Electric’s credit rating at A.


Discontinued Operations

On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. As of September 30, 2018, we have sold nearly all of our oil and gas assets and we closed our oil and gas office in August. Transaction closing for the last few assets and final accounting are expected within the fourth quarter. See Note 18 of the Notes to Condensed Consolidated Financial Statements for more information.

Operating Results

A discussion of operating results from our segments and Corporate activities follows. 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 purchases and natural gas 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.


44



Electric Utilities
 Three Months Ended September 30,Nine Months Ended September 30,
 20182017Variance20182017Variance
 (in thousands)
Revenue (a)
$184,790
$183,571
$1,219
$531,961
$528,048
$3,913
       
Total fuel and purchased power72,928
68,733
4,195
204,334
199,398
4,936
       
Gross margin (b)
111,862
114,838
(2,976)327,627
328,650
(1,023)
       
Operations and maintenance45,307
40,204
5,103
135,501
125,302
10,199
Depreciation and amortization24,720
23,446
1,274
73,873
69,427
4,446
Total operating expenses70,027
63,650
6,377
209,374
194,729
14,645
       
Operating income41,835
51,188
(9,353)118,253
133,921
(15,668)
       
Interest expense, net(12,923)(12,744)(179)(39,423)(39,049)(374)
Other income (expense), net(450)649
(1,099)(1,121)1,579
(2,700)
Income tax benefit (expense)(6,884)(11,769)4,885
(14,396)(28,065)13,669
Net income$21,578
$27,324
$(5,746)$63,313
$68,386
$(5,073)
________________
(a)The three and nine months ended September 30, 2018 include Horizon Point shared facility revenues of approximately $2.8 million and $8.1 million, respectively, which are allocated to all of our operating segments as facility expenses. This shared facility agreement is new in 2018 and has no impact on BHC’s consolidated operating results.
(b)Non-GAAP measure

Results of Operations for the Electric Utilities for the Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2017: Net income from continuing operations available for common stock for the Electric Utilities was $22 million for the three months ended September 30, 2018, compared to Net income from continuing operations available for common stock of $27 million for the three months ended September 30, 2017, as a result of:

Gross margin for the three months ended September 30, 2018 decreased $3.0 million compared to the same period in the prior year as a result of:
 (in millions)
TCJA revenue reserve$(5.7)
Wyoming Electric PCA Stipulation(3.4)
Weather(0.8)
Commercial and industrial demand(0.4)
Horizon Point shared facility revenue (b)
2.8
Power Marketing, ancillary wheeling and Tech Services2.6
Residential customer growth1.0
Rider recovery0.9
Total (decrease) in Gross margin (a)
$(3.0)
________________
(a)Non-GAAP measure
(b)Horizon Point shared facility revenue is offset by facility expenses at our operating segments and has no impact on consolidated results.

Operations and maintenance increased primarily due to $1.2 million higher facility costs, $1.3 million higher outside services primarily from distribution and transmission line surveying expenses and $1.5 million higher employee related expenses driven primarily by labor and benefits.


45



Depreciation and amortization increased primarily due to a higher asset base driven by the prior year additions of Horizon Point and the Teckla-Lange transmission line.

Interest expense, net was comparable to the same period in the prior year.

Other income (expense), net decreased due to the presentation change of non-service pension costs to Other income (expense) in the current year, previously reported in Operations and maintenance, and higher prior year AFUDC associated with higher prior year capital spend.

Income tax benefit (expense): The effective tax rate decreased from the prior year due to the reduction in the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018, partially offset by $2.8 million of tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes.


Results of Operations for the Electric Utilities for the Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017: Net income from continuing operations available for common stock for the Electric Utilities was $63 million for the nine months ended September 30, 2018, compared to Net income from continuing operations available for common stock of $68 million for the nine months ended September 30, 2017, as a result of:

Gross margin for the nine months ended September 30, 2018 decreased $1.0 million compared to the same period in the prior year as a result of:
 (in millions)
TCJA revenue reserve$(17.2)
Wyoming Electric PCA Stipulation(3.7)
Horizon Point shared facility revenue (b)
8.1
Rider recovery5.0
Weather2.6
Power Marketing, ancillary wheeling and Tech Services2.3
Residential customer growth1.5
Commercial and industrial demand0.4
Total (decrease) in Gross margin (a)
$(1.0)
________________
(a)Non-GAAP measure
(b)Horizon Point shared facility revenue is offset by facility expenses at our operating segments and has no impact on consolidated results.

Operations and maintenance increased primarily due to $2.8 million of higher vegetation management expenses, $3.6 million of shared facility costs and $1.5 million of outside service costs primarily from distribution and transmission line surveying expenses. Higher employee costs and property taxes 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 the prior year additions of Horizon Point and the Teckla-Lange transmission line.

Interest expense, net was comparable to the same period in the prior year.

Other income (expense), net decreased due to the presentation change of non-service pension costs to Other income (expense) in the current year, previously reported in Operations and maintenance, and higher prior year AFUDC associated with higher prior year capital spend.

Income tax benefit (expense): The effective tax rate decreased from the prior year due to the reduction in the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018, partially offset by $3.2 million of tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes.



46



Operating Statistics
  Electric Revenue (in thousands) Quantities sold (MWh)
  Three Months Ended
September 30,
Nine Months Ended
September 30,
 Three Months Ended
September 30,
Nine Months Ended
September 30,
  2018201720182017 2018201720182017
Residential $58,122
$55,866
$163,979
$158,017
 372,623
369,466
1,084,531
1,038,437
Commercial 65,794
68,044
192,680
195,495
 550,791
557,975
1,560,911
1,547,254
Industrial 31,939
30,564
93,959
91,583
 429,133
406,946
1,248,438
1,192,316
Municipal 4,582
4,958
13,389
13,934
 43,972
47,389
122,953
125,065
Subtotal Retail Revenue - Electric 160,437
159,432
464,007
459,029
 1,396,519
1,381,776
4,016,833
3,903,072
Contract Wholesale 8,256
8,048
25,497
22,593
 221,327
185,723
677,163
537,720
Off-system/Power Marketing Wholesale 9,059
5,932
18,142
15,110
 206,791
159,425
514,686
477,283
Other 7,038
10,159
24,315
31,316
 



Total Revenue and Energy Sold 184,790
183,571
531,961
528,048
 1,824,637
1,726,924
5,208,682
4,918,075
Other Uses, Losses or Generation, net 



 121,478
134,595
337,939
354,572
Total Revenue and Energy 184,790
183,571
531,961
528,048
 1,946,115
1,861,519
5,546,621
5,272,647
Less cost of fuel and purchased power 72,928
68,733
204,334
199,398
     
Gross Margin (a)
 $111,862
$114,838
$327,627
$328,650
     
________________
(a)Non-GAAP measure

Three Months Ended September 30, Electric Revenue (in thousands) 
Gross Margin (a)       (in thousands)
 
Quantities Sold (MWh) (b)
  20182017 20182017 20182017
South Dakota Electric $78,067
$73,939
 $52,860
$51,096
 874,962
835,285
Wyoming Electric 38,671
40,670
 18,843
22,990
 461,074
434,945
Colorado Electric 68,052
68,962
 40,159
40,752
 610,079
591,289
Total Electric Revenue, Gross Margin, and Quantities Sold $184,790
$183,571
 $111,862
$114,838
 1,946,115
1,861,519
________________
(a)Non-GAAP measure
(b)Total MWh includes Other Uses, Losses or Generation, net, which are approximately 5%, 7%, and 7% for South Dakota Electric, Wyoming Electric, and Colorado Electric, respectively.
          
Nine Months Ended September 30, Electric Revenue (in thousands) 
Gross Margin (a) (in thousands)
 
Quantities Sold (MWh) (b)
  20182017 20182017 20182017
South Dakota Electric $222,558
$213,785
 $154,158
$149,182
 2,541,082
2,399,995
Wyoming Electric 120,466
123,299
 62,489
68,215
 1,365,932
1,298,009
Colorado Electric 188,937
190,964
 110,980
111,253
 1,639,607
1,574,643
Total Electric Revenue, Gross Margin, and Quantities Sold $531,961
$528,048
 $327,627
$328,650
 5,546,621
5,272,647
________________
(a)Non-GAAP measure
(b)Total MWh includes Other Uses, Losses or Generation, net, which are approximately 5%, 6%, and 7% for South Dakota Electric, Wyoming Electric, and Colorado Electric, respectively.


47



 Three Months Ended
September 30,
Nine Months Ended
September 30,
Quantities Generated and Purchased (MWh)2018201720182017
     
Coal-fired608,417
625,590
1,772,750
1,663,935
Natural Gas and Oil199,351
156,465
345,978
249,065
Wind54,450
38,773
196,932
167,429
Total Generated862,218
820,828
2,315,660
2,080,429
Purchased1,083,897
1,040,691
3,230,961
3,192,218
Total Generated and Purchased1,946,115
1,861,519
5,546,621
5,272,647

 Three Months Ended
September 30,
Nine Months Ended
September 30,
Quantities Generated and Purchased (MWh)2018201720182017
Generated:    
South Dakota Electric469,680
478,232
1,293,713
1,177,131
Wyoming Electric229,262
227,391
633,696
601,780
Colorado Electric163,276
115,205
388,251
301,518
Total Generated862,218
820,828
2,315,660
2,080,429
Purchased:    
South Dakota Electric405,282
357,053
1,247,369
1,222,864
Wyoming Electric231,812
207,554
732,236
696,229
Colorado Electric446,803
476,084
1,251,356
1,273,125
Total Purchased1,083,897
1,040,691
3,230,961
3,192,218
     
Total Generated and Purchased1,946,115
1,861,519
5,546,621
5,272,647

 Three Months Ended September 30,
Degree Days  2018   2017
 Actual 
Variance from
30-Year Average
 Actual Variance to Prior Year Actual 
Variance from
30-Year Average
Heating Degree Days:         
South Dakota Electric236
 5 % 17% 202
 (10)%
Wyoming Electric248
 (19)% (15)% 292
 (4)%
Colorado Electric35
 (64)% (60)% 87
 (11)%
Combined (a)
147
 (20)% (13)% 168
 (8)%
          
Cooling Degree Days:         
South Dakota Electric356
 (33)% (40)% 595
 11 %
Wyoming Electric328
 10 % (15)% 388
 30 %
Colorado Electric910
 33 % 16% 784
 14 %
Combined (a)
603
 9 % (6)% 640
 15 %
__________
(a)Combined actuals are calculated based on the weighted average number of total customers by state.

48



          
 Nine Months Ended September 30,
Degree Days2018   2017
 Actual 
Variance from
30-Year Average
 Actual Variance to Prior Year Actual 
Variance from
30-Year Average
Heating Degree Days:         
South Dakota Electric4,972
 11 % 17% 4,242
 (5)%
Wyoming Electric4,285
 (9)% 2% 4,186
 (11)%
Colorado Electric2,901
 9 % 5% 2,773
 (17)%
Combined (a)
3,888
 5 % 9% 3,559
 (11)%
          
Cooling Degree Days:         
South Dakota Electric488
 (23)% (31)% 709
 12 %
Wyoming Electric430
 24 % —% 429
 23 %
Colorado Electric1,404
 57 % 37% 1,027
 15 %
Combined (a)
895
 29 % 12% 798
 15 %
__________
(a)Combined actuals are calculated based on the weighted average number of total customers by state.

Electric Utilities Power Plant AvailabilityThree Months Ended September 30,Nine Months Ended September 30,
 201820172018 2017 
Coal-fired plants (a)
95.7% 98.3% 94.0% 88.1% 
Natural gas-fired plants and Other plants97.0% 94.6% 97.2% 95.8% 
Wind96.9% 91.0% 96.9% 92.0% 
Total availability96.6% 95.5% 96.1% 93.0% 
         
Wind capacity factor33.1% 23.6% 41.8% 34.3% 
__________
(a)2017 included planned outages at Neil Simpson II, Wygen II and Wygen III.

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 of this Quarterly Report on Form 10-Q and Part I, Items 1 and 2 and Part II, Item 8 of our 2017 Annual Report on Form 10-K filed with the SEC.



49




Gas Utilities
 Three Months Ended September 30,Nine Months Ended September 30,
 20182017Variance20182017Variance
 (in thousands)
Revenue:      
Natural gas — regulated$117,070
$123,210
$(6,140)$648,550
$602,745
$45,805
Other — non-regulated services (a)
14,606
19,684
(5,078)58,090
71,506
(13,416)
Total revenue131,676
142,894
(11,218)706,640
674,251
32,389
       
Cost of sales:      
Natural gas — regulated30,612
33,376
(2,764)298,149
255,410
42,739
Other — non-regulated services (a)
5,514
11,917
(6,403)15,716
33,615
(17,899)
Total cost of sales36,126
45,293
(9,167)313,865
289,025
24,840
       
Gross margin (b)
95,550
97,601
(2,051)392,775
385,226
7,549
       
Operations and maintenance69,746
65,390
4,356
212,319
201,105
11,214
Depreciation and amortization21,564
20,937
627
64,288
62,658
1,630
Total operating expenses91,310
86,327
4,983
276,607
263,763
12,844
       
Operating income4,240
11,274
(7,034)116,168
121,463
(5,295)
       
Interest expense, net(20,433)(19,527)(906)(59,456)(58,919)(537)
Other income (expense), net(478)(294)(184)(1,239)(342)(897)
Income tax benefit (expense)3,394
4,218
(824)37,709
(20,686)58,395
Net income (loss)(13,277)(4,329)(8,948)93,182
41,516
51,666
Net (income) loss attributable to noncontrolling interest



(107)107
Net income (loss) available for common stock$(13,277)$(4,329)$(8,948)$93,182
$41,409
$51,773
__________
(a)The three and nine months ended September 30, 2018 include certain non-utility trading activities which are reported on a net basis. These trading activities are presented on a gross basis in the prior year. This change in presentation had no impact on gross margin.
(b)Non-GAAP measure


50



Results of Operations for the Gas Utilities for the Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2017: Net (loss) from continuing operations available for common stock for the Gas Utilities was $(13.3) million for the three months ended September 30, 2018, compared to Net loss from continuing operations available for common stock of $(4.3) million for the three months ended September 30, 2017, as a result of:

Gross margin for the three months ended September 30, 2018 decreased $2.1 million compared to the same period in the prior year as a result of:
 (in millions)
Weather$(2.3)
TCJA revenue reserve(2.2)
Rate review and rider recovery(0.3)
Non-utility - Tech Services and appliance repair1.2
Customer growth - distribution0.8
Mark-to-market gains on non-utility natural gas commodity contracts0.4
Other0.3
Total increase (decrease) in Gross margin (a)
$(2.1)
________________
(a)Non-GAAP measure

Operations and maintenance increased primarily due to $1.4 million higher facility costs, higher bad debt expense of approximately $0.5 million related to increased year-to-date revenues, $1.3 million of higher outside services primarily from line locating services and $0.3 million higher employee costs driven primarily by increased headcount.

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

Interest expense, net increased due to higher corporate allocations from financing activities compared to the same period in the prior year.

Other income (expense), net decreased from the prior year due primarily to the presentation change of non-service pension costs to Other income (expense) in the current year, previously reported in Operations and maintenance.

Income tax benefit (expense) decreased from the prior year due to the lower tax rate as a result of the reduction of the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018 partially offset by $2.6 million of tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes.



51



Results of Operations for the Gas Utilities for the Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017: Net income from continuing operations available for common stock for the Gas Utilities was $93 million for the nine months ended September 30, 2018, compared to Net income from continuing operations available for common stock of $42 million for the nine months ended September 30, 2017, as a result of:

Gross margin for the nine months ended September 30, 2018 increased $7.5 million compared to the same period in the prior year as a result of:
 (in millions)
Weather$7.6
Customer growth - distribution3.6
Mark-to-market gains on non-utility natural gas commodity contracts2.9
Rate review and rider recovery2.8
Natural gas volumes sold1.9
Transportation and Transmission0.9
Non-utility - Tech Services and appliance repair0.8
Other0.5
TCJA revenue reserve(13.5)
Total increase (decrease) in Gross margin (a)
$7.5
________________
(a)Non-GAAP measure

Operations and maintenance increased primarily due to higher employee costs of approximately $2.6 million driven by labor, benefits and increased corporate allocations, higher bad debt expense of approximately $2.6 million driven by the current year increase in revenues, $1.6 million of higher outside services primarily from line locating services and an increase in facility costs of $4.2 million.

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

Interest expense, net was comparable to the same period in the prior year.

Other income (expense), net decreased from the prior year due to the presentation change of non-service pension costs to Other income (expense) in the current year, previously reported in Operations and maintenance.

Income tax benefit (expense): The 2018 tax benefit is due to legal restructuring to enable jurisdictional simplification that resulted in the recognition of a deferred tax benefit of approximately $49 million associated with amortizable goodwill for tax purposes. The current year effective tax rate also reflects the reduction of the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018.



52



Operating Statistics

  Gas Revenue (in thousands) 
Gross Margin (a) (in thousands)
  Three Months Ended
September 30,
Nine Months Ended
September 30,
 Three Months Ended
September 30,
Nine Months Ended
September 30,
  2018201720182017 2018201720182017
           
Residential $58,221
$57,804
$383,972
$344,407
 $42,598
$42,012
$192,072
$182,256
Commercial 19,639
21,366
148,675
134,156
 10,880
11,097
57,890
54,931
Industrial 8,258
9,472
20,805
18,699
 2,028
2,157
5,341
4,665
Other (b)
 487
2,099
(6,789)6,363
 487
2,099
(6,789)6,363
Total Distribution 86,605
90,741
546,663
503,625
 55,993
57,365
248,514
248,215
           
Transportation and Transmission 30,465
32,469
101,887
99,120
 30,465
32,470
101,887
99,121
           
Total Regulated 117,070
123,210
648,550
602,745
 86,458
89,835
350,401
347,336
           
Non-regulated Services 14,606
19,684
58,090
71,506
 9,092
7,766
42,374
37,890
           
Total Gas Revenue & Gross Margin $131,676
$142,894
$706,640
$674,251
 $95,550
$97,601
$392,775
$385,226
__________
(a)Non-GAAP measure
(b)
Includes current year reserve to revenue to reflect the reduction of the lower federal income tax rate from the TCJA on our existing rate tariffs.

  Revenue (in thousands) 
Gross Margin (a) (in thousands)
  Three Months Ended
September 30,
Nine Months Ended
September 30,
 Three Months Ended
September 30,
Nine Months Ended
September 30,
  2018201720182017 2018201720182017
           
Arkansas $18,743
$19,276
$116,226
$104,519
 $13,415
$13,485
$65,803
$66,362
Colorado 22,362
21,823
125,898
120,667
 15,210
16,068
66,917
69,241
Nebraska 40,553
47,577
196,307
191,288
 31,264
33,290
117,925
112,418
Iowa 16,982
17,709
111,968
98,619
 12,556
12,564
49,630
48,278
Kansas 18,497
20,114
81,880
77,389
 11,129
11,207
40,896
39,810
Wyoming 14,539
16,395
74,361
81,769
 11,976
10,987
51,604
49,117
Total Gas Revenue & Gross Margin $131,676
$142,894
$706,640
$674,251
 $95,550
$97,601
$392,775
$385,226
__________
(a)Non-GAAP measure

 Three Months Ended
September 30,
Nine Months Ended
September 30,
Gas Utilities Quantities Sold & Transported (Dth)2018201720182017
     
Residential3,708,196
3,682,944
42,642,021
36,052,414
Commercial2,278,304
2,445,847
20,842,996
18,111,118
Industrial2,304,098
2,722,173
5,235,417
4,690,092
Total Distribution Quantities Sold8,290,598
8,850,964
68,720,434
58,853,624
     
Transportation and Transmission29,808,567
30,577,487
107,388,321
102,314,665
     
Total Quantities Sold & Transported38,099,165
39,428,451
176,108,755
161,168,289

53



 Three Months Ended
September 30,
Nine Months Ended
September 30,
Gas Utilities Quantities Sold & Transported (Dth)2018201720182017
     
Arkansas4,022,089
3,950,107
21,183,322
18,232,131
Colorado2,893,029
3,111,653
19,301,834
19,156,708
Nebraska13,831,306
14,620,729
58,223,856
52,802,084
Iowa5,595,205
5,345,911
28,527,522
25,472,681
Kansas6,164,821
7,270,229
23,391,905
20,975,597
Wyoming5,592,715
5,129,822
25,480,316
24,529,088
Total Quantities Sold & Transported38,099,165
39,428,451
176,108,755
161,168,289

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.

 Three Months Ended September 30,
Degree Days2018   2017
Heating Degree Days:Actual 
Variance
from 30-Year
Average
 Actual Variance to Prior Year Actual 
Variance
from 30-Year
Average
Arkansas (a)
12 (72)% (20)% 15 (66)%
Colorado109 (49)% (42)% 187 (13)%
Nebraska101 (7)% 53% 66 (40)%
Iowa128 (7)% 42% 90 (35)%
Kansas (a)
54 (2)% 46% 37 (32)%
Wyoming236 (23)% (23)% 307 1%
Combined (b)
109 (27)% (7)% 117 (22)%
          
 Nine Months Ended September 30,
Degree Days2018   2017
Heating Degree Days:Actual 
Variance
from 30-Year
Average
 Actual Variance to Prior Year Actual 
Variance
from 30-Year
Average
Arkansas (a)
2,460
 (1)% 35% 1,826
 (26)%
Colorado3,548
 (14)% —% 3,541
 (14)%
Nebraska4,016
 6 % 22% 3,280
 (13)%
Iowa4,460
 6 % 22% 3,641
 (13)%
Kansas (a)
3,032
 2 % 17% 2,584
 (13)%
Wyoming4,552
 (4)% 2% 4,468
 (5)%
Combined (b)
4,008
  % 14% 3,521
 (12)%
__________
(a)Arkansas has a weather normalization mechanism in effect during the months of November through April for customers with residential and certain business rate schedules. Kansas Gas has a weather normalization mechanism within its residential and business rate structure. The weather normalization mechanism in Arkansas differs from that in Kansas in that it only uses one location to calculate the weather, compared to Kansas, which uses multiple locations. The weather normalization mechanisms in both Arkansas and Kansas minimize weather impact on gross margins.
(b)The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to its weather normalization mechanism. Arkansas Gas is partially excluded based on the weather normalization mechanism in effect from November through April.




54



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 of this Quarterly Report on Form 10-Q and Part I, Items 1 and 2 and Part II, Item 8 of our 2017 Annual Report on Form 10-K filed with the SEC.

Power Generation
 Three Months Ended September 30,Nine Months Ended September 30,
 20182017Variance20182017Variance
 (in thousands)
Revenue (a)
$23,603
$22,927
$676
$68,590
$68,289
$301
       
Operations and maintenance7,434
7,646
(212)25,520
24,228
1,292
Depreciation and amortization (a)
1,692
1,036
656
4,927
3,312
1,615
Total operating expense9,126
8,682
444
30,447
27,540
2,907
       
Operating income14,477
14,245
232
38,143
40,749
(2,606)
       
Interest expense, net(1,264)(724)(540)(3,753)(2,015)(1,738)
Other income (expense), net(34)(5)(29)(75)(36)(39)
Income tax (expense) benefit(2,494)(3,426)932
(6,549)(10,114)3,565
       
Net income10,685
10,090
595
27,766
28,584
(818)
Net income attributable to noncontrolling interest(3,994)(3,935)(59)(10,447)(10,567)120
Net income available for common stock$6,691
$6,155
$536
$17,319
$18,017
$(698)
____________
(a)The generating facility located in Pueblo, Colorado is accounted for as a capital lease under GAAP; as such, revenue and depreciation expense are impacted by the accounting for this lease. Under the lease, the original cost of the facility is recorded at Colorado Electric and is being depreciated by Colorado Electric for segment reporting purposes.

In 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Colorado IPP. Black Hills Electric Generation continues to be the majority owner and operator of the facility, which is contracted to provide capacity and energy through 2031 to Colorado Electric. Net income available for common stock for the three months ended September 30, 2018 and September 30, 2017 was reduced by $4.0 million and $3.9 million, respectively, attributable to this noncontrolling interest.

Results of Operations for Power Generation for the Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2017: Net income from continuing operations available for common stock for the Power Generation segment was $6.7 million for the three months ended September 30, 2018, compared to Net income from continuing operations available for common stock of $6.2 million for the same period in 2017. Revenue increased in the current year due to higher PPA prices and an increase in MWh sold. Operating expenses were comparable to the same period in the prior year reflecting lower maintenance expenses, offset by higher depreciation. Interest expense increased from the same period in the prior year due to higher interest rates. The variance in tax expense reflects the reduction in the federal tax rate from 35% to 21% from the TCJA, effective January 1, 2018.

Results of Operations for Power Generation for the Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017: Net income from continuing operations available for common stock for the Power Generation segment was $17 million for the nine months ended September 30, 2018, compared to Net income from continuing operations available for common stock of $18 million for the same period in 2017. Revenue increased in the current year as a result of higher PPA prices and an increase in MWh sold. Operating expenses increased from the same period in the prior year due to higher maintenance expenses primarily related to outage costs at Wygen I and higher depreciation. Interest expense increased from the same period in the prior year due to higher interest rates. The variance in tax expense reflects the reduction in the federal tax rate from 35% to 21% from the TCJA, effective January 1, 2018, partially offset by $0.7 million of additional tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes.

55





The following table summarizes MWh for our Power Generation segment:
 Three Months Ended September 30, Nine Months Ended September 30,
 20182017 20182017
Quantities Sold, Generated and Purchased
(MWh) (a)
     
Sold     
Black Hills Colorado IPP (b)
304,102
256,895
 745,365
725,919
Black Hills Wyoming (c)
160,011
163,690
 470,072
476,659
Total Sold464,113
420,585
 1,215,437
1,202,578
      
Generated     
Black Hills Colorado IPP (b)
304,102
256,895
 745,365
725,919
Black Hills Wyoming (c)
144,476
140,081
 407,324
407,775
Total Generated448,578
396,976
 1,152,689
1,133,694
      
Purchased     
Black Hills Colorado IPP

 

Black Hills Wyoming (c)
16,685
20,246
 65,724
52,463
Total Purchased16,685
20,246
 65,724
52,463
____________
(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.

The following table provides certain operating statistics for our plants within the Power Generation segment:
 Three Months Ended September 30, Nine Months Ended September 30,
 20182017 20182017
Contracted power plant fleet availability:     
Coal-fired plant97.9%97.1% 93.9%95.8%
Natural gas-fired plants99.3%99.2% 99.4%99.1%
Total availability98.9%98.7% 98.0%98.3%


56



Mining

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

20182017Variance20182017Variance

(in thousands)
Revenue$17,301
$17,493
$(192)$51,328
$48,985
$2,343
       
Operations and maintenance10,761
11,235
(474)32,807
32,162
645
Depreciation, depletion and amortization1,989
2,004
(15)5,874
6,231
(357)
Total operating expenses12,750
13,239
(489)38,681
38,393
288
       
Operating income4,551
4,254
297
12,647
10,592
2,055
       
Interest expense, net(51)(47)(4)(384)(146)(238)
Other income (expense), net(70)567
(637)(190)1,644
(1,834)
Income tax benefit (expense)(858)(1,297)439
(2,512)(3,042)530
       
Net income$3,572
$3,477
$95
$9,561
$9,048
$513

The following table provides certain operating statistics for our Mining segment (in thousands, except for Revenue per ton):

 Three Months Ended September 30, Nine Months Ended September 30,
 20182017 20182017
Tons of coal sold1,078
1,151
 3,119
3,127
Cubic yards of overburden moved2,361
2,316
 6,763
6,381
      
Revenue per ton$15.54
$15.20
 $15.92
$15.67

Results of Operations for Mining for the Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2017: Net income from continuing operations available for common stock for the Mining segment was $3.6 million for the three months ended September 30, 2018, compared to Net income from continuing operations available for common stock of $3.5 million for the same period in 2017. Revenue was comparable to the prior year reflecting a 6% decrease in tons sold and a 2% increase in price per ton sold driven by contract price adjustments based on actual mining costs. Current year revenue is also reflective of lease and rental revenue, previously reported in Other income (expense), net. During the current period, approximately 49% of the mine’s production was sold under contracts that include price adjustments based on actual mining costs, including income taxes.

Operating expenses decreased primarily due to lower royalties and production taxes on decreased revenues, and lower major maintenance expenses. Other income (expense), net decreased from the prior year due to the presentation change of lease and rental revenue to Revenue in the current year, previously reported in Other income (expense), net. The variance in tax expense to the prior year reflects the TCJA reduction in the federal corporate income tax rate from 35% to 21% , effective January 1, 2018.

Results of Operations for Mining for the Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017: Net income from continuing operations available for common stock for the Mining segment was $9.6 million for the nine months ended September 30, 2018, compared to Net income from continuing operations available for common stock of $9.0 million for the same period in 2017. Revenue increased primarily due to a 2% increase in price per ton sold. Current year revenue is also reflective of lease and rental revenue, previously reported in Other income (expense), net. During the current period, approximately 49% of the mine’s production was sold under contracts that include price adjustments based on actual mining costs, including income taxes.


57



Operating expenses increased primarily due to higher overburden removal and higher fuel expenses. Other income (expense), net decreased from the prior year due to the presentation change of lease and rental revenue to Revenue in the current year, previously reported in Other income (expense), net. The variance in tax expense to the prior year reflects the reduction in the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018, partially offset by $0.5 million of additional tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes.

Corporate and Other

 Three Months Ended September 30,Nine Months Ended September 30,
 20182017Variance20182017Variance
 (in thousands)
Operating (loss) (a)
$(16)$(1,401)$1,385
$(2,301)$(7,183)$4,882
       
Other income (expense):      
Interest (expense) income, net (a)
(626)(1,028)402
(1,810)(2,331)521
Other income (expense), net520
(31)551
702
(869)1,571
Income tax benefit (expense)(635)(1,204)569
(2,468)3,389
(5,857)
       
Net income (loss)$(757)$(3,664)$2,907
$(5,877)$(6,994)$1,117
____________
(a)Includes certain general and administrative expenses and interest expenses that are not reported as discontinued operations in 2017.

Results of Operations for Corporate and Other for the Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2017: Net loss from continuing operations available for common stock for Corporate and Other was $(0.8) million for the three months ended September 30, 2018, compared to Net income from continuing operations available for common stock of $(3.7) million for the three months ended September 30, 2017. The variance was driven by higher prior year operating costs previously allocated to our Oil and Gas segment in 2017, which were not reclassified to discontinued operations in 2017, and are allocated to our operating segments in 2018. Income tax benefit (expense) increased in the current year due to higher state income tax expense.

Results of Operations for Corporate and Other for the Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017: Net loss from continuing operations available for common stock for Corporate and Other was $(5.9) million for the nine months ended September 30, 2018, compared to Net loss from continuing operations available for common stock of $(7.0) million for the nine months ended September 30, 2017. The variance to the prior year was driven by higher prior year operating costs previously allocated to our Oil and Gas segment which were not reclassified to discontinued operations in 2017, which are allocated to our operating segments in 2018 and transition and acquisition expenses which occurred in the prior year. The variance in Income tax benefit (expense) was primarily due to a prior year tax benefit of $1.4 million comprised primarily of benefits from a carryback claim for specified liability losses involving prior tax years and current year tax expense.


58



Discontinued Operations

Results of Discontinued Operations for the Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2017: Net loss from discontinued operations was $(0.9) million for the three months ended September 30, 2018, compared to Net loss from discontinued operations of $(1.3) million for the same period in 2017. The variance to the prior year is driven by lower revenues due to property sales and higher losses on sales of operating assets, partially offset by lower oil and gas operating expenses and lower employee costs. Depreciation and depletion expense was recorded in the prior year under full cost accounting, which ceased November 1, 2017 due to reclassification to assets held for sale.

Results of Discontinued Operations for the Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017: Net loss from discontinued operations was $(5.6) million for the nine months ended September 30, 2018, compared to Net loss from discontinued operations of $(3.5) million for the same period in 2017. The variance to the prior year is driven by lower revenues due to property sales and higher losses on sales of operating assets, partially offset by lower oil and gas operating expenses and lower employee costs. Current year depreciation expense is representative of the amortization of the remaining book value of accounting software. Depreciation and depletion expense was recorded in the prior year under full cost accounting, which ceased November 1, 2017 due to reclassification to assets held for sale.

Critical Accounting Estimates

There have been no material changes in our critical accounting estimates from those reported in our 2017 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 2017 Annual Report on Form 10-K.


59



Liquidity and Capital Resources

OVERVIEW

Our Company requires significant cash to support and grow our business. Our predominant source of cash is supplied by our operations and supplemented with corporate financings. This cash is used for, among other things, working capital, capital expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations, and redemption of outstanding debt and equity securities when required or financially appropriate. As discussed in more detail below under income taxes, we expect an increase in working capital requirements as a result of complying with the TCJA and the impact of providing TCJA benefits to customers.

The most significant uses of cash are our capital expenditures, the purchase of natural gas for our Gas Utilities and our Power Generation segment, as well as the payment of dividends to our shareholders. We experience significant cash requirements during peak months of the winter heating season due to higher natural gas consumption and during periods of high natural gas prices, as well as during the summer construction season.

We believe that our cash on hand, operating cash flows, existing borrowing capacity and ability to complete new debt and equity financings, taken in their entirety, provide sufficient capital resources to fund our ongoing operating requirements, debt maturities, anticipated dividends, and anticipated capital expenditures discussed in this section.

Significant Factors Affecting Liquidity

Although we believe we have sufficient resources to fund our cash requirements, there are many factors with the potential to influence our cash flow position, including seasonality, commodity prices, significant capital projects and acquisitions, requirements imposed by state and federal agencies, and economic market conditions. We have implemented risk mitigation programs, where possible, to stabilize cash flow; however, the potential for unforeseen events affecting cash needs will continue to exist.

Our utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas which have performance assurance provisions that allow the counterparty to require collateral postings under certain conditions, including when requested on a reasonable basis due to a deterioration in our financial condition or nonperformance. A significant downgrade in our credit ratings, such as a downgrade to a level below investment grade, could result in counterparties requiring collateral postings under such adequate assurance provisions. The amount of credit support that we may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions and the amounts owed by or to the counterparty. At September 30, 2018, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts.

Income Tax

The TCJA legislation was signed into law on December 22, 2017. The new tax law required revaluation at December 31, 2017 of federal deferred tax assets and liabilities using the new lower corporate tax rate of 21%. As a result of the revaluation, deferred tax assets and liabilities were reduced by approximately $309 million. Of the $309 million, approximately $301 million is related to our regulated utilities and is reclassified to a regulatory liability. During the nine months ended September 30, 2018, we recorded approximately $16 million of additional regulatory liability associated with TJCA related items. This regulatory liability will generally be amortized over the remaining life of the related assets as specifically prescribed in the TCJA.

We expect an increase in working capital requirements as a result of complying with the TCJA and the impact of providing TCJA benefits to customers. We estimate the lower tax rate will negatively impact the Company’s cash flows by approximately $40 million to $45 million annually for the next several years. Each of our utilities is working with their respective regulators to address the impact of tax reform and the appropriate benefit to customers. See Note 5 for more information on regulatory matters.
 


60



Cash Flow Activities

The following table summarizes our cash flows for the three months ended September 30 (in thousands):

Cash provided by (used in):20182017Increase (Decrease)
Operating activities$378,722
$319,430
$59,292
Investing activities$(281,771)$(255,978)$(25,793)
Financing activities$(101,949)$(63,112)$(38,837)

Year-to-Date 2018 Compared to Year-to-Date 2017

Operating Activities

Net cash provided by operating activities was $379 million for the nine months ended September 30, 2018, compared to net cash provided by operating activities of $319 million for the same period in 2017 for an increase of $59 million. The variance was primarily attributable to:

Cash earnings (income from continuing operations plus non-cash adjustments) were $14 million lower for the nine months ended September 30, 2018 compared to the same period in the prior year;

Net cash inflows from changes in operating assets and liabilities were $29 million for the nine months ended September 30, 2018, compared to net cash outflows of $60 million in the same period in the prior year. This $90 million increase was primarily due to:

Cash inflows decreased by approximately $21 million primarily as a result of increases in pre-paid tax assets and lower collections of accounts receivable, partially offset by lower natural gas in storage for the nine months ended September 30, 2018 compared to the same period in the prior year;

Cash outflows decreased by approximately $26 million as a result of increases in accounts payable and accrued liabilities driven by changes in prior year accrued interest and contract payments and other working capital requirements;

Cash inflows increased by approximately $66 million as a result of changes in our current regulatory assets and liabilities driven by differences in fuel cost adjustments and cash collected from customers that will be refunded due to the TCJA tax rate change; and

Net cash outflows decreased by $15 million due to additional pension contributions made in the prior year.

Investing Activities

Net cash used in investing activities was $282 million for the nine months ended September 30, 2018, compared to net cash used in investing activities of $256 million for the same period in 2017 for a variance of $26 million. The variance was primarily attributable to:

Capital expenditures of approximately $278 million for the nine months ended September 30, 2018 compared to $239 million for the same period in the prior year. Higher current year expenditures at our gas utilities, mining and power generation segments are partially offset by higher prior year expenditures at our electric utilities which included completion of the second segment of the 144-mile long Teckla-Lange transmission line and construction of our Horizon Point facility.

A $35 million change in net cash provided by investing activities from discontinued operations primarily due to the sale of assets held for sale partially offset by a $24 million investment.


61



Financing Activities

Net cash used in financing activities for the nine months ended September 30, 2018 was $102 million, compared to $63 million of net cash used in financing activities for the same period in 2017 for a variance of $39 million. This variance is primarily due to:

Long–term borrowings increased due to the issuance of $400 million principal amount senior secured notes in 2018, a portion of which were issued in exchange for $299 million principal amount of our RSNs due 2028 (which were immediately retired) and a portion of which were sold to the public with $99 million of net proceeds used to pay down short-term debt;

We amended and restated our $300 million unsecured term loan due August 2019;

Prior year net short-term borrowings of $129 million offset by prior year long-term debt repayments of $104 million;

$5.0 million of higher current year dividend payments; and

Increased payments for other financing activities of approximately $3.7 million driven primarily by the July 30, 2018 and August 17, 2018 debt transactions.

Dividends

Dividends paid on our common stock totaled $76 million for the nine months ended September 30, 2018, or $0.475 per share per quarter. On October 30, 2018, our board of directors declared a quarterly dividend of $0.505 per share payable December 1, 2018, 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.

Debt

Financing Transactions and Short-Term Liquidity

Our principal sources to meet day-to-day operating cash requirements are cash from operations, our CP Program and our corporate Revolving Credit Facility.

Revolving Credit Facility and CP Program

On July 30, 2018, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 30, 2023 with two one-year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. See Note 9 for more information.

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. See Note 9 for more information.

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 FacilityExpirationCapacitySeptember 30, 2018September 30, 2018September 30, 2018September 30, 2018
Revolving Credit FacilityJuly 30, 2023$750
$
$112
$15
$623


62



The weighted average interest rate on CP Program borrowings at September 30, 2018 was 2.42%. Revolving Credit Facility and CP Program financing activity for the nine months ended September 30, 2018 was (dollars in millions):
 For the Nine Months Ended September 30, 2018
Maximum amount outstanding - commercial paper (based on daily outstanding balances)$231
Maximum amount outstanding - revolving credit facility (based on daily outstanding balances)$
Average amount outstanding - commercial paper (based on daily outstanding balances)$135
Average amount outstanding - revolving credit facility (based on daily outstanding balances)$
Weighted average interest rates - commercial paper2.16%
Weighted average interest rates - revolving credit facility%

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. Under the Revolving Credit Facility, our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness (which includes letters of credit and certain guarantees issued but excludes the RSNs), by (ii) Capital, which is Consolidated Indebtedness plus Consolidated Net Worth (which excludes noncontrolling interests in subsidiaries and includes the aggregate outstanding amount of the RSNs or, with respect to the calculation as of September 30, 2018 only, the amount receivable by the Company in connection with the common stock settlement under the purchase contracts which are part of the Equity Units). Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. We were in compliance with these covenants as of September 30, 2018.

The Revolving Credit Facility prohibits us from paying cash dividends if a default or an event of default exists prior to, or would result after, paying a dividend. Although these contractual restrictions exist, we do not anticipate triggering any default measures or restrictions.

Financing Activities

Financing activities for the nine months ended September 30, 2018 consisted of the following:

Short-term borrowings from our CP Program.

On August 17, 2018, we completed a public debt offering of $400 million principal amount, 4.350% senior unsecured notes due 2033. The proceeds were used to repay the $299 million principal amount of our RSNs due 2028 and pay down short-term debt. Through this offering, we successfully remarketed the $299 million principal amount of the existing subordinated notes, which were originally issued as a part of the Company's Equity Units on November 23, 2015. See Note 9 for more information.

On July 30, 2018, we amended and restated our unsecured term loan due August 2019. This amended and restated term loan, with $300 million outstanding at September 30, 2018, will now mature July 30, 2020 and has substantially similar terms and covenants as the amended and restated Revolving Credit Facility. See Note 9 for more information.

On November 1, 2018, we completed settlement of the stock purchase contracts that are components of the Equity Units issued
November 23, 2015. Upon settlement of all outstanding stock purchase obligations, the Company received gross proceeds of approximately $299 million in exchange for approximately 6.372 million shares of common stock. See Note 10 for more information.

On August 4, 2017, we renewed the ATM equity offering program which reset the size of the ATM equity offering program to an aggregate value of up to $300 million. We did not issue any shares of common stock under our ATM equity offering program for the nine months ended September 30, 2018.

Future Financing Plans

Evaluating refinancing options for our $200 million senior notes due July 15, 2020 and the $300 million senior notes due July 30, 2020.


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Dividend Restrictions

As a utility holding company which owns several regulated utilities, we are subject to various regulations that could influence our liquidity. Our utilities in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming have regulatory agreements in which they cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40% of their total capitalization; and neither Black Hills Utility Holdings nor its subsidiaries can extend credit to the Company except in the ordinary course of business and upon reasonable terms consistent with market terms. The use of our utility assets as collateral generally requires the prior approval of the state regulators in the state in which the utility assets are located. Additionally, our utility subsidiaries may generally be limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may have further restrictions under the Federal Power Act. As a result of our holding company structure, our right as a common shareholder to receive assets of any of our direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities, and guarantee holders. As of September 30, 2018, the restricted net assets at our Electric Utilities and Gas Utilities were approximately $257 million.
Our credit facilities and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be deemed to have occurred if we did not meet certain financial covenants. The only financial covenant under our Revolving Credit Facility and existing term loan is a Consolidated Indebtedness to Capitalization Ratio, which requires us to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00 at the end of any fiscal quarter. Our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness (which includes letters of credit and certain guarantees issued but excludes the RSNs), by (ii) Capital, which is Consolidated Indebtedness plus Consolidated Net Worth (which excludes noncontrolling interests in subsidiaries and includes the aggregate outstanding amount of the RSNs or, with respect to the calculation as of September 30, 2018 only, the amount receivable by the Company in connection with the common stock settlement under the purchase contracts which are part of the Equity Units). Additionally, covenants within Cheyenne Light’s financing agreements require Cheyenne Light to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of September 30, 2018, we were in compliance with these covenants.
There have been no other material changes in our financing transactions and short-term liquidity from those reported in Item 7 of our 2017 Annual Report on Form 10-K filed with the SEC.

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 September 30, 2018:
Rating AgencySenior Unsecured RatingOutlook
S&P (a)
BBB+Stable
Moody’s (b)
Baa2Stable
Fitch (c)
  BBB+Stable
__________
(a)On August 9, 2018, S&P upgraded to BBB+ rating and revised the outlook to Stable.
(b)On December 12, 2017, Moody’s affirmed our Baa2 rating and maintained a Stable outlook.
(c)On October 11, 2018, Fitch affirmed BBB+ rating and maintained a Stable outlook.


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The following table represents the credit ratings of South Dakota Electric at September 30, 2018:

Rating AgencySenior Secured Rating
S&P (a)
A
Moody’sA1
Fitch (b)
A
__________
(a)On August 9, 2018, S&P upgraded to A rating.
(b)On July 19, 2018, Fitch affirmed A rating.

Capital Requirements

Capital Expenditures

Actual and forecasted capital requirements are as follows (in thousands):
 Expenditures for the Total Total Total
 
Nine Months Ended September 30, 2018 (a)
 
2018 Planned
Expenditures (b)
 
2019 Planned
Expenditures
 
2020 Planned
Expenditures
Electric Utilities$105,295
 $141,000
 $192,000
 $165,000
Gas Utilities (c)
172,599
 270,000
 374,000
 273,000
Power Generation (d)
4,350
 46,000
 60,000
 9,000
Mining11,982
 19,000
 8,000
 7,000
Corporate and Other8,426
 12,000
 17,000
 21,000
 $302,652
 $488,000
 $651,000
 $475,000
__________
(a)    Expenditures for the nine months ended September 30, 2018 include the impact of accruals for property, plant and equipment.
(b)    Includes actual capital expenditures for the nine months ended September 30, 2018.
(c)    Planned capital expenditures for 2018, 2019 and 2020 increased primarily due to higher programmatic integrity spending.
(d)    Planned capital expenditures for 2018 increased due to purchase of AltaGas’s interest in Busch Ranch I.

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 2017 Annual Report on Form 10-K.

Guarantees

There have been no significant changes to guarantees from those previously disclosed in Note 20 of the Notes to the Consolidated Financial Statements in our 2017 Annual Report on Form 10-K.

New Accounting Pronouncements

Other than the pronouncements reported in our 2017 Annual Report on Form 10-K filed with the SEC and those discussed in Note 1 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements that are expected to have a material effect on our financial position, results of operations, or cash flows.


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FORWARD-LOOKING INFORMATION

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

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

Any forward-looking statement contained in this document speaks only as of the date the statement was made. The Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement was made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements described in our 2017 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our 2017 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

Utilities

Our utility customers are exposed to natural gas price volatility. Therefore, as allowed or required by state utility commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, options and basis swaps to reduce our customers’ underlying exposure to these fluctuations. We also reduce the commodity price risk in the unregulated area of our business by using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/or sales. The fair value of our utilities’ derivative contracts is summarized below (in thousands) as of:
 September 30, 2018 December 31, 2017 September 30, 2017
Net derivative (liabilities) assets$(1,869) $(6,644) $(6,541)
Cash collateral offset in Derivatives4,308
 7,694
 5,452
Cash collateral included in Other current assets4,677
 562
 2,841
Net asset (liability) position$7,116
 $1,612
 $1,752

Financing Activities

Historically, we have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations and anticipated debt refinancings. At September 30, 2018, December 31, 2017 and September 30, 2017, we had no outstanding interest rate swap agreements.


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ITEM 4.    CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) as of September 30, 2018. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at September 30, 2018.

Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Security Exchange Act of 1934, as amended, is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the quarter ended September 30, 2018, 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.


BLACK HILLS CORPORATION

Part II — Other Information


ITEM 1.Legal Proceedings

For information regarding legal proceedings, see Note 19 in Item 8 of our 2017 Annual Report on Form 10-K and Note 17 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 17 is incorporated by reference into this item.

ITEM 1A.Risk Factors

There are no material changes to the risk factors previously disclosed in Item 1A of Part I in our 2017 Annual Report on Form 10-K filed with the SEC.

ITEM 2.Unregistered Sales of Equity Securities and Use of Proceeds

There were no unregistered securities sold during the nine months ended September 30, 2018.
         

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 5.Other Information

None.


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ITEM 6.Exhibits

Exhibit NumberDescription
  
Exhibit 3.1*
  
Exhibit 3.2*
  
Exhibit 4.1*
 
 
 
 
 
 
 
  
Exhibit 4.2*
 
 
 
  
Exhibit 4.3*
 
 
  
Exhibit 4.4*
 
  

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Exhibit 4.5*
  
Exhibit 4.6*
  
Exhibit 10.1*
  
Exhibit 10.2*
  
Exhibit 31.1
  
Exhibit 31.2
  
Exhibit 32.1
  
Exhibit 32.2
  
Exhibit 95
  
Exhibit 101Financial Statements for XBRL Format.
__________
*Previously filed as part of the filing indicated and incorporated by reference herein.


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SIGNATURES


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

BLACK HILLS CORPORATION
  /s/ David R. Emery
  David R. Emery, Chairman and
    Chief Executive Officer
   
  /s/ Richard W. Kinzley
  Richard W. Kinzley, Senior Vice President and
    Chief Financial Officer
   
Dated:November 6, 2018 


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