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, 2017March 31, 2019
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 1-7978
Black Hills Power, Inc.
Incorporated in South DakotaIRS Identification Number 46-0111677
625 Ninth Street7001 Mount Rushmore Road
Rapid City, South Dakota 5770157702
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 and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted 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 and post 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 filero Accelerated filero
     
Non-accelerated filerx(Do not check if a smaller reporting company)
     
   Smaller reporting companyo
     
   Emerging growth companyo


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

Securities registered pursuant to Section 12(b) of the Act:  None


As of October 31, 2017,April 30, 2019, there were issued and outstanding 23,416,396 shares of the Registrant’s common stock, $1.00 par value, all of which were held beneficially and of record by Black Hills Corporation.


Reduced Disclosure


The Registrant meets the conditions set forth in General Instruction H (1) (a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format.





TABLE OF CONTENTS


  Page
 GLOSSARY OF TERMS AND ABBREVIATIONS
3
   
PART 1.FINANCIAL INFORMATION 
   
Item 1.Financial Statements 
   
 Condensed Statements of Income and Comprehensive Income - unaudited
4
 Three and Nine Months Ended September 30, 2017March 31, 2019 and 20162018 
   
 Condensed Balance Sheets - unaudited
5
 September 30, 2017March 31, 2019 and December 31, 20162018 
   
 Condensed Statements of Cash Flows - unaudited
7
 NineThree Months Ended September 30, 2017March 31, 2019 and 20162018 
   
 Notes to Condensed Financial Statements - unaudited
8
   
Item 2.Managements’ Discussion and Analysis of Financial Condition and Results of Operations
1516
   
Item 4.Controls and Procedures
1920
   
PART II.OTHER INFORMATION
2021
   
Item 1.Legal Proceedings
2021
   
Item 1A.Risk Factors
2021
   
Item 6.Exhibits
2021
   
 Signatures
2122






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
ASCAccounting Standards Codification
ASUAccounting Standards Update issued by the FASB
BHCBlack Hills Corporation; the Parent Company
Black Hills EnergyThe name used to conduct the business of BHC utility companies
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 Service CompanyBlack Hills Service Company, LLC, a direct, wholly-owned subsidiary of BHC
Cheyenne LightCheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Cooling Degree Daydegree day (CDD)A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.
DSMDemand Side Management
ECAEnergy Cost Adjustment - adjustments that allow us to pass the prudently-incurred cost of fuel and purchased energy through to customers.locations.
FASBFinancial Accounting Standards Board
FERCUnited States Federal Energy Regulatory Commission
FitchFitch Ratings
GAAPAccounting principles generally accepted in the United States of America
Global Settlement
Settlement with a utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders.

Happy JackHappy Jack Wind Farms, LLC, a subsidiary of Duke Energy Generation Services
Heating degree day (HDD)A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.locations.
kVHorizon PointKilovoltBHC Corporate headquarters building in Rapid City, South Dakota, which was completed in 2017.
LIBORLondon Interbank Offered Rate
Moody’sMoody’s Investors Service, Inc.
MWParentMegawatts
SDPUCSouth Dakota Public Utilities CommissionBlack Hills Corporation
SECU. S. Securities and Exchange Commission
Silver SageSilver Sage Windpower, LLC, a subsidiary of Duke Energy Generation Services
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 by BHC on February 12, 2016, and is now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy)
South Dakota ElectricIncludes Black Hills Power operations in South Dakota, Wyoming and Montana
S&PStandard & Poor’s, a division of The McGraw-Hill Companies, Inc.
TCATCJATransmission Cost Adjustment - adjustments passed through to the customer based on transmission costs that are higher or lower than the costs approved in the rate case.
Winter Storm AtlasAn October 2013 blizzard that impacted South Dakota Electric. It was the second most severe blizzard in Rapid City’s history.Tax Cuts and Jobs Act enacted December 22, 2017
WRDCWyodak Resources Development Corp., an indirect, wholly-owned subsidiary of BHC
Wyoming Electric
Includes Cheyenne Light’s electric utility operations













BLACK HILLS POWER, INC.
CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

Three Months Ended September 30, Nine Months Ended September 30,Three Months Ended March 31,
(unaudited)2017 2016 2017 201620192018
(in thousands)(in thousands)
Revenue$73,938
 $66,728
 $213,785
 $197,389
$79,041
$73,815
        
Operating expenses:        
Fuel and purchased power22,843
 18,421
 64,604
 55,375
22,733
22,440
Operations and maintenance16,747
 15,601
 52,589
 49,538
19,557
19,151
Depreciation and amortization9,053
 8,547
 26,578
 25,363
10,077
9,884
Taxes - property1,597
 1,749
 5,228
 4,987
2,032
1,976
Total operating expenses50,240
 44,318
 148,999
 135,263
54,399
53,451
        
Operating income23,698
 22,410
 64,786
 62,126
24,642
20,364
        
Other income (expense):        
Interest expense(5,483) (5,454) (16,873) (16,322)
AFUDC - borrowed369
 319
 953
 840
Interest charges - 
Interest expense incurred (including amortization of debt issuance costs, premiums, and discounts)(5,830)(5,587)
Allowance for funds used during construction - borrowed283
48
Interest income335
 510
 704
 1,004
115
115
AFUDC - equity676
 606
 1,864
 1,595
Allowance for funds used during construction - equity—
34
Other income (expense), net3
 48
 (119) 75
(375)(151)
Total other income (expense)(4,100) (3,971) (13,471) (12,808)
Total other income (expense), net(5,807)(5,541)
        
Income before income taxes19,598
 18,439
 51,315
 49,318
18,835
14,823
Income tax expense(5,772) (6,429) (15,632) (16,316)(3,338)(3,063)
Net income13,826
 12,010
 35,683
 33,002
15,497
11,760
        
Other comprehensive income (loss):       
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax (expense) benefit of $(6) and $(6) for the three months ended September 30, 2017 and 2016, and $(17) and $(17) for the nine months ended September 30, 2017 and 2016, respectively)10
 10
 31
 31
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(8) and $(8) for the three months ended September 30, 2017 and 2016 and $(23) and $(21) for the nine months ended September 30, 2017 and 2016, respectively)14
 14
 42
 41
Other comprehensive income24
 24
 73
 72
Other comprehensive income (loss), net of tax: 
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $0 and $(6), respectively)—
10
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(4) and $(9), respectively)12
17
Other comprehensive income (loss), net of tax12
27
        
Comprehensive income$13,850
 $12,034
 $35,756
 $33,074
$15,509
$11,787

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



BLACK HILLS POWER, INC.
CONDENSED BALANCE SHEETS

(unaudited)September 30, 2017December 31, 2016
 (in thousands)
ASSETS  
Current assets:  
Cash and cash equivalents$1,171
$234
Receivables - customers, net27,579
30,614
Receivables - affiliates5,498
9,526
Other receivables, net335
351
Money pool notes receivable, net8,881
28,409
Materials, supplies and fuel23,622
22,389
Regulatory assets, current18,819
18,119
Other, current assets3,432
3,876
Total current assets89,337
113,518
   
Investments4,902
4,841
   
Property, plant and equipment1,298,855
1,236,387
Less accumulated depreciation and amortization(354,788)(338,828)
Total property, plant and equipment, net944,067
897,559
   
Other assets:  
Regulatory assets, non-current73,178
74,015
Other, non-current assets3,545
3,816
Total other assets76,723
77,831
TOTAL ASSETS$1,115,029
$1,093,749


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






BLACK HILLS POWER, INC.
CONDENSED BALANCE SHEETS


(unaudited)September 30, 2017December 31, 2016
 (in thousands, except common stock par value and share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY  
Current liabilities:  
Accounts payable$14,701
$14,158
Accounts payable - affiliates26,828
31,799
Accrued liabilities50,337
37,436
Regulatory liabilities, current825
84
Total current liabilities92,691
83,477
   
Long-term debt339,860
339,756
   
Deferred credits and other liabilities:  
Deferred income tax liability, net, non-current220,857
211,443
Regulatory liabilities, non-current55,822
53,866
Benefit plan liabilities15,721
19,544
Other, non-current liabilities1,393
1,001
Total deferred credits and other liabilities293,793
285,854
   
Commitments and contingencies (Notes 4, 5 and 8)

   
Stockholder’s equity:  
Common stock $1 par value; 50,000,000 shares authorized; 23,416,396 shares issued23,416
23,416
Additional paid-in capital39,575
39,575
Retained earnings326,883
322,933
Accumulated other comprehensive loss(1,189)(1,262)
Total stockholder’s equity388,685
384,662
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY$1,115,029
$1,093,749
 As of
(unaudited)March 31, 2019December 31, 2018
 (in thousands)
ASSETS  
Current assets:  
Cash$5
$112
Accounts receivable, net28,354
28,431
Accounts receivable from affiliates9,903
8,119
Materials, supplies and fuel25,275
24,853
Regulatory assets, current23,215
19,052
Other current assets4,692
4,538
Total current assets91,444
85,105
   
Investments4,973
4,889
   
Property, plant and equipment1,399,901
1,381,045
Less: accumulated depreciation and amortization(383,681)(376,160)
Total property, plant and equipment, net1,016,220
1,004,885
   
Other assets:  
Regulatory assets, non-current53,141
56,680
Other assets, non-current24,616
9,729
Total other assets, non-current77,757
66,409
   
TOTAL ASSETS$1,190,394
$1,161,288


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





BLACK HILLS POWER, INC.
CONDENSED STATEMENTS OF CASH FLOWSBALANCE SHEETS

(Continued)
(unaudited)Nine Months Ended September 30,
 20172016
 (in thousands)
Operating activities:  
Net income$35,683
$33,002
Adjustments to reconcile net income to net cash provided by operating activities-  
Depreciation and amortization26,578
25,363
Deferred income tax6,188
22,267
Employee benefits613
1,327
AFUDC(2,817)(1,595)
Other adjustments, net2,298
118
Change in operating assets and liabilities -  
Accounts receivable and other current assets6,567
5,499
Accounts payable and other current liabilities3,077
(501)
Regulatory assets - current1,543
(4,029)
Contributions to defined benefit pension plan(4,000)(820)
Other operating activities, net(1,097)(3,994)
Net cash provided by (used in) operating activities74,633
76,637
   
Investing activities:  
Property, plant and equipment additions(61,537)(65,062)
Change in money pool notes receivable, net(12,472)(10,966)
Other investing activities313
(81)
Net cash provided by (used in) investing activities(73,696)(76,109)
   
Financing activities:  
Net cash provided by (used in) financing activities—
—
   
Net change in cash and cash equivalents937
528
   
Cash and cash equivalents, beginning of period234
297
Cash and cash equivalents, end of period$1,171
$825
 As of
(unaudited)March 31, 2019December 31, 2018
 (in thousands, except share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY  
Current liabilities:  
Accounts payable$19,434
$25,122
Accounts payable to affiliates26,966
25,804
Accrued liabilities40,428
34,193
Money pool notes payable33,300
38,690
Regulatory liabilities, current2,079
2,574
Total current liabilities122,207
126,383
   
Long-term debt340,070
340,035
   
Deferred credits and other liabilities:  
Deferred income tax liabilities, net116,499
114,009
Regulatory liabilities, non-current161,714
160,642
Benefit plan liabilities14,631
14,606
Other deferred credits and other liabilities15,525
1,368
Total deferred credits and other liabilities308,369
290,625
   
Commitments and contingencies (Notes 5, 6 and 9)


   
Stockholder’s equity:  
Common stock $1 par value; 50,000,000 shares authorized; 23,416,396 shares issued23,416
23,416
Additional paid-in capital39,575
39,575
Retained earnings357,636
342,145
Accumulated other comprehensive loss(879)(891)
Total stockholder’s equity419,748
404,245
   
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY$1,190,394
$1,161,288

See Note 7 for supplemental cash flow information.


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





BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(unaudited)Three Months Ended March 31,
 20192018
 (in thousands)
Operating activities:  
Net income$15,497
$11,760
Adjustments to reconcile net income to net cash provided by operating activities-  
Depreciation and amortization10,077
9,884
Deferred income tax1,718
(898)
Employee benefits195
380
Other adjustments, net1,044
1,018
Change in operating assets and liabilities -  
Accounts receivable and other current assets(2,437)(2,478)
Accounts payable and other current liabilities6,210
3,320
Regulatory assets - current(1,413)1,807
Regulatory liabilities - current(444)3,171
Other operating activities, net(594)35
Net cash provided by (used in) operating activities29,853
27,999
   
Investing activities:  
Property, plant and equipment additions(24,386)(13,533)
Proceeds from sale of assets—
4,994
Other investing activities(169)(3,608)
Net cash provided by (used in) investing activities(24,555)(12,147)
   
Financing activities:  
Change in money pool notes payable, net(5,390)(15,856)
Other financing activities(15)—
Net cash provided by (used in) financing activities(5,405)(15,856)
   
Net change in cash(107)(4)
   
Cash, beginning of period112
16
Cash, end of period$5
$12

See Note 8 for supplemental cash flow information.

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


BLACK HILLS POWER, INC.

Notes to Condensed Financial Statements
(unaudited)
(Reference is made to Notes to Financial Statements
included in our 20162018 Annual Report on Form 10-K)


(1)(1)    MANAGEMENT’S STATEMENT


The unaudited condensed financial statements included herein have been prepared by Black Hills Power, Inc. (the “Company,” “we,” “us,” 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 financial statements should be read in conjunction with the financial statements and the notes thereto, included in our 20162018 Annual Report on Form 10-K filed with the SEC.


The information furnished in the accompanying condensed 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, 2017, March 31, 2019, December 31, 20162018 and September 30, 2016March 31, 2018 financial information and are of a normal recurring nature. The results of operations for the three and nine months ended September 30, 2017March 31, 2019 and September 30, 2016,March 31, 2018, and our financial condition as of September 30, 2017March 31, 2019 and December 31, 20162018 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

Revisions

Certain revisions have been made to prior year’s financial information to conform to the current year presentation.

We revised our presentation of cash and certain cash transactions processed on behalf of affiliates as of December 31, 2016.  We have banking arrangements at certain financial institutions whereby if required, payments of one account are cleared with cash from other accounts at the same financial institution; therefore, book overdrafts are presented on a combined basis by bank as cash and cash equivalents. Cash collected or disbursed on behalf of affiliates is presented as Receivables - affiliates or Accounts payable - affiliates. Prior year amounts were corrected to conform to the current year presentation, which decreased cash and cash equivalents by $9.4 million as of September 30, 2016. It also decreased net cash flows provided by operations by $2.2 million for the nine months ended September 30, 2016. We assessed the materiality of these changes, taking into account quantitative and qualitative factors, and determined them to be immaterial to the balance sheet as of September 30, 2016 and to the Statements of Cash Flows for the nine months ended September 30, 2016. There is no impact to the Statements of Income or Statements of Comprehensive Income (Loss) for any period reported.


Recently IssuedAdopted Accounting Standards

Revenue from Contracts with Customers, ASU 2014-09

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017 with early adoption on January 1, 2017 permitted. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption.

We currently expect to implement the standard on a modified retrospective basis effective January 1, 2018. We have substantially completed our assessment of all sources of revenue and are currently determining the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. A majority of our revenues are from regulated tariff offerings that provide electricity with a defined contractual term. For such arrangements, we expect that revenue from contracts with the customer will be equivalent to the electricity delivered during that period. Therefore, we do not expect there will be a significant shift in the timing or pattern of revenue recognition for regulated tariff based sales. We


also continue to monitor outstanding industry implementation issues and assess the impacts to our current accounting policies and/or patterns of revenue recognition.

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

In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The changes to the standard require employers to report the service cost component in the same line item(s) as other compensation costs, and require 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. This ASU will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and post-retirement benefit costs in the income statement. The capitalization of the service cost component of net period pension and post-retirement benefit costs in assets will be applied on a prospective basis. This new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. We continue to assess the impact of this new standard on our financial statements and disclosures, and we monitor regulated utility industry implementation discussions and guidance. For our rate-regulated entities, we currently expect to capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities. The presentation changes required for net periodic pension and post-retirement costs will result in offsetting changes to Operating income and Other income and are not expected to be material. We will implement this standard effective January 1, 2018.

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

In August 2016, the FASB issued 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. The ASU will be effective for fiscal years beginning after December 15, 2017.We will use the retrospective transition method to adopt this standard with fiscal years beginning after December 15, 2017. This standard will not have a material impact on our financial position, results of operations or cash flows.


Leases, ASU 2016-02


In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize aincrease transparency and comparability among organizations by requiring the recognition of right-of-use assetassets and lease liabilityliabilities on the balance sheet for allmost leases, with a term greater than 12 months, whereas todaypreviously only financing typefinancing-type lease liabilities (capital leases) arewere recognized on the balance sheet. In addition,Under the definitionnew standard, disclosures are required to meet the objective of a lease has been revised in regardsenabling users of financial statements to when an arrangement conveysassess the right to control the useamount, timing and uncertainty 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 arising 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. 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.leases.


We currently expect to adopt thisadopted the standard oneffective January 1, 2019. We continueelected the option to evaluatenot recast comparative periods presented with transitioning to the impactnew lease standard and will report these comparative periods as presented under previous lease guidance. In addition, we elected the package of thispractical expedients permitted under the transition guidance with the new standard, which among other things, allowed us to carry forward the historical lease classification. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment of existing land easement agreements.

Adoption of the new standard resulted in the recording of an operating lease right-of-use asset and an off-setting operating lease obligation liability of $14 million as of January 1, 2019. The lease standard did not materially impact our net earnings and had no impact on cash flows.














(2)    REVENUE

Revenue Recognition

As of January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and its related amendments (collectively known as ASC 606). Revenue is recognized in an amount that reflects the consideration we expect to receive in exchange for goods or services, when control of the promised goods or services is transferred to our financial position, resultscustomers. The following table depicts the disaggregation of operationsrevenue, from contracts with customers by customer type and cash flows as well as monitor emerging guidance on such topics as easementstiming of revenue recognition for the three months ended March 31, 2019 and right of ways, pipeline laterals, purchase power agreements,2018. Sales tax and other industry-related areas.similar taxes are excluded from revenues.
 Three Months Ended March 31, 2019Three Months Ended March 31, 2018
 (in thousands)
Customer types:  
Retail$53,076
$50,641
Wholesale8,343
9,050
Market - off-system sales4,670
2,275
Transmission/Other12,831
11,718
Revenue from contracts with customers78,920
73,684
Other revenues121
131
Total revenues$79,041
$73,815
   
Timing of revenue recognition:  
Services transferred over time$78,920
$73,684
Revenue from contracts with customers$78,920
$73,684


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 and is further discussed in Note 3. We have begun the process of identifying and categorizing our lease contracts and evaluating our current business processes.do not typically incur costs that would be capitalized, to obtain or fulfill a revenue contract.








(2)
(3)		ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS


Following is a summary of Receivables - customers,Accounts receivable, net included in the accompanying Condensed Balance Sheets (in thousands) as of:
 March 31, 2019December 31, 2018
Accounts receivable trade$18,196
$16,236
Unbilled revenues10,356
12,333
Allowance for doubtful accounts(198)(138)
Accounts receivable, net$28,354
$28,431

 September 30, 2017December 31, 2016
Accounts receivable trade$17,356
$16,972
Unbilled revenues10,348
13,799
Allowance for doubtful accounts(125)(157)
Receivables - customers, net$27,579
$30,614




(3)
(4)		REGULATORY ACCOUNTING


Our regulated electric operations are subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of the FERC.


Our regulatory assets and liabilities were as follows (in thousands) as of:
 March 31, 2019 December 31, 2018
Regulatory assets:   
Loss on reacquired debt (a)
$1,191
 $1,259
Deferred taxes on AFUDC (b)
5,048
 5,020
Employee benefit plans and related deferred taxes (c)

20,085
 19,868
Deferred energy and fuel cost adjustments (b)
21,649
 20,334
Deferred taxes on flow through accounting (c)
9,045
 8,749
Decommissioning costs (a)
7,682
 8,196
Vegetation management (a)
9,790
 10,366
Other regulatory assets (a)
1,866
 1,940
Total regulatory assets$76,356
 $75,732
Less current regulatory assets(23,215) (19,052)
Regulatory assets, non-current$53,141
 $56,680

 
Maximum Amortization
(in years)
September 30, 2017 December 31, 2016
Regulatory assets:    
Unamortized loss on reacquired debt (a)
8$1,604
 $1,815
Deferred taxes on AFUDC (b)
4510,192
 9,367
Employee benefit plans(c)

1220,180
 20,100
Deferred energy and fuel cost adjustments - current (a)
113,754
 18,119
Deferred gas cost adjustments (a) (e)
15,324
 4,897
Deferred taxes on flow through accounting (a)
3514,906
 12,545
Decommissioning costs, net of amortization(d)
610,766
 12,456
Other regulatory assets (a) (d)
615,271
 12,835
Total regulatory assets $91,997
 $92,134


Regulatory liabilities:   
Cost of removal for utility plant (a)
$53,758
 $52,366
Employee benefit plan costs and related deferred taxes (c)
7,518
 7,518
Excess deferred income taxes (c)
99,846
 100,276
TCJA revenue reserve2,079
 2,523
Other regulatory liabilities (c)
592
 533
Total regulatory liabilities$163,793
 $163,216
Less current regulatory liabilities(2,079) (2,574)
Regulatory liabilities, non-current$161,714
 $160,642
Regulatory liabilities:    
Cost of removal for utility plant (a)
61$43,518
 $41,541
Employee benefit plan costs and related deferred taxes (c)
1212,304
 12,304
Other regulatory liabilities13825
 105
Total regulatory liabilities $56,647
 $53,950

____________________
(a)We are allowed 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)In accordance with a settlement agreement approved by the SDPUC on June 16, 2017, the amortization of South Dakota Electric’s decommissioning costs of approximately $11 million, vegetation management costs of approximately $14 million, and Winter Storm Atlas costs of approximately $2.0 million are being amortized over 6 years, effective July 1, 2017. Decommissioning costs and Winter Storm Atlas costs were previously amortized over a 10 year period ending September 30, 2024. The vegetation management costs were previously unamortized. The change in amortization periods for these costs will increase annual amortization expense by approximately $2.7 million.
(e)Our deferred energy, fuel cost, and gas cost adjustments represent the cost of electricity and gas delivered to our electric utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. We file periodic quarterly, semi-annual, and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions.



Regulatory Matters

There have been no other significant changes to our Regulatory Matters from those previously disclosed in Note 1 of the Notes to the Financial Statements in our 2018 Annual Report on Form 10-K.






(4)(5)RELATED-PARTY TRANSACTIONS


Dividend to Parent

We recorded non-cash dividends to our Parent of $16 million and decreased the utility Money pool note receivable by $16 million for the three months ended March 31, 2018. We did not record any dividends for the three months ended March 31, 2019.

Receivables and Payables


We have accounts receivable and accounts payable balances related to transactions with other BHC subsidiaries. The balances were as follows (in thousands) as of:
 March 31, 2019December 31, 2018
Accounts receivable from affiliates$9,903
$8,119
Accounts payable to affiliates$26,966
$25,804

 September 30, 2017 December 31, 2016
Receivables - affiliates$5,498
 $9,526
Accounts payable - affiliates$26,828
 $31,799


Money Pool Notes Receivable and Notes Payable


On September 1, 2017, the Utility Money Pool was transferred from Black Hills Power to our affiliate Black Hills Utility Holdings. This transfer reduced our cash by $0.7 million, reduced our Money pool notes receivable, net by $1.0 million and increased our Retained earnings by $0.3 million.

We will continue to participate in the Utility Money Pool Agreement (the Agreement). Under the Agreement, we may borrow from the pool; however the Agreement restricts the pool from loaning funds to BHC or to any of BHC’s non-utility subsidiaries. The Agreement does not restrict us from paying dividends to BHC. Borrowings under the Agreement bear interest at the weighted average daily cost of our parent company’s external borrowings as defined under the Agreement, or if there are no external funds outstanding on that date, then the rate will be the daily one-month LIBOR plus 1.0%. At September 30, 2017,March 31, 2019, the average cost of borrowing under the Utility Money Pool was 1.66%2.88%.


We had the following balances with the Utility Money Pool (in thousands) as of:
 March 31, 2019December 31, 2018
Money pool notes payable$33,300
$38,690

 September 30, 2017 December 31, 2016
Money pool notes receivable, net$8,881
 $28,409


Our net interest income (expense) relating to balances with the Utility Money Pool was as follows (in thousands):
 Three Months Ended March 31,
 20192018
Net interest income (expense)$(273)$(36)




 Three Months Ended September 30,Nine Months Ended September 30,
 2017201620172016
Net interest income (expense)$53
$277
$269
$845




Other related party activity was as follows (in thousands):
 Three Months Ended
March 31,
 20192018
Revenue:  
Energy sold to Cheyenne Light$574
$703
Rent from electric properties$896
$909
Horizon Point shared facility revenues$3,007
$2,769
   
Fuel and purchased power:
  
Purchases of coal from WRDC$4,657
$4,067
Purchase of excess energy from Cheyenne Light$132
$86
Purchase of renewable wind energy from Cheyenne Light - Happy Jack$535
$641
Purchase of renewable wind energy from Cheyenne Light - Silver Sage$983
$1,093
   
Gas transportation service agreement:  
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation$76
$96
   
Corporate support:  
Corporate support services and fees from Black Hills Service Company$10,191
$7,606

 Three Months Ended September 30,Nine Months Ended September 30,
 2017201620172016
Revenue:    
Energy sold to Cheyenne Light$361
$599
$1,866
$1,908
Rent from electric properties$935
$1,229
$2,805
$3,817
     
Fuel and purchased power:
    
Purchases of coal from WRDC$4,054
$4,122
$11,386
$12,275
Purchase of excess energy from Cheyenne Light$208
$64
$324
$172
Purchase of renewable wind energy from Cheyenne Light - Happy Jack$199
$312
$1,174
$1,329
Purchase of renewable wind energy from Cheyenne Light - Silver Sage$351
$547
$2,007
$2,276
     
Gas transportation service agreement:    
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation$99
$100
$297
$300
     
Corporate support:    
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings$6,626
$6,257
$20,346
$19,155



Horizon Point Agreement

We have a shared facility agreement among South Dakota Electric and Black Hills Service Company where there is a cost allocation for the use of the Horizon Point facility that is owned by South Dakota Electric.  This cost allocation includes the recovery of and return on allocable property and recovery of incurred administrative service expenses for the operation and maintenance of the Horizon Point facility.


(5)
(6)		EMPLOYEE BENEFIT PLANS


The components of net periodic benefit cost for the Defined Benefit Pension Plan were as follows (in thousands):
 Three Months Ended March 31,
 20192018
Service cost$91
$129
Interest cost603
548
Expected return on plan assets(851)(886)
Prior service cost2
11
Net loss (gain)305
516
Net periodic benefit cost$150
$318



 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Service cost$137
 $151
 $409
 $453
Interest cost585
 625
 1,755
 1,875
Expected return on plan assets(898) (908) (2,692) (2,724)
Prior service cost10
 11
 32
 33
Net loss (gain)308
 498
 922
 1,496
Net periodic benefit cost$142
 $377
 $426
 $1,133


Defined Benefit Postretirement Healthcare Plan


The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plan were as follows (in thousands):
 Three Months Ended March 31,
 20192018
Service cost$37
$48
Interest cost47
45
Prior service cost (benefit)(84)(84)
Net periodic benefit cost$—
$9

 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Service cost$52
 $51
 $155
 $153
Interest cost44
 47
 132
 141
Prior service cost (benefit)(84) (84) (252) (252)
Net periodic benefit cost$12
 $14
 $35
 $42




Supplemental Non-qualified Defined Benefit Plans


The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit Plans were as follows (in thousands):
 Three Months Ended March 31,
 20192018
Interest cost$29
$27
Net loss (gain)16
26
Net periodic benefit cost$45
$53

 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Interest cost$29
 $30
 $87
 $90
Net loss (gain)22
 20
 65
 62
Net periodic benefit cost$51
 $50
 $152
 $152


Contributions


Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. On July 24, 2017, we made contributionsContributions to the Defined Benefit Pension Plan in the amount of approximately $1.8 million. On September 15, 2017, we made an additional contribution of approximately $2.2 million to reduce Pension Benefit Guaranty Corporation premiums and offset the forecasted increase in pension expense due to low bond yields which impact the pension discount rate. Contributions to thePostretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made for 20172019 and anticipated contributions for 20172019 and 20182020 are as follows (in thousands):
 
Contributions
Three Months Ended
March 31, 2019
Remaining Anticipated Contributions for 2019Anticipated Contributions for 2020
Defined Benefit Pension Plan$—
$1,753
$1,841
Defined Benefit Postretirement Healthcare Plan$117
$349
$466
Supplemental Non-qualified Defined Benefit Plans$58
$172
$240
 
Contributions
Nine Months Ended
September 30, 2017
Remaining Anticipated Contributions for 2017Anticipated Contributions for 2018
Defined Benefit Pension Plan$4,000
$—
$1,834
Defined Benefit Postretirement Healthcare Plan$406
$135
$565
Supplemental Non-qualified Defined Benefit Plans$185
$62
$246





(6)(7)FAIR VALUE OF FINANCIAL INSTRUMENTS


Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance on fair value measurements establishes a hierarchy for grouping assets and liabilities, based on significance of inputs. For additional information see Note 1 included in our 20162018 Annual Report on Form 10-K filed with the SEC.


The estimated fair values of our financial instruments were as follows (in thousands) as of:
September 30, 2017 December 31, 2016March 31, 2019December 31, 2018
Carrying AmountFair Value Carrying AmountFair ValueCarrying AmountFair ValueCarrying AmountFair Value
Cash and cash equivalents (a)
$1,171
$1,171
 $234
$234
Cash (a)
$5
$5
$112
$112
Long-term debt, including current maturities (b) (c)
$339,860
$439,973
 $339,756
$410,466
$340,070
$428,498
$340,035
$412,894
_________________
(a)CarryingThe cash fair value approximates faircarrying value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified inas Level 1 in the fair value hierarchy. We believe that the market risk arising from cash in a bank account is minimal.
(b)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.
(c)Carrying amount of long-term debt is net of deferred financing costs.





(7)(8)SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION


 Three Months Ended March 31,
 20192018
 (in thousands)
Non-cash investing and financing activities -  
Property, plant and equipment acquired with accrued liabilities$8,633
$7,556
Non-cash (decrease) to money pool notes receivable, net$—
$(16,000)
Non-cash dividend to Parent$—
$16,000
   
Cash (paid) refunded during the period for -  
Interest (net of amounts capitalized)$(3,345)$(3,088)
Income taxes, net$—
$—

Nine months ended September 30,2017 2016
 (in thousands)
Non-cash investing and financing activities -   
Property, plant and equipment acquired with accrued liabilities$10,242
 $5,565
Non-cash (decrease) to money pool notes receivable, net$(32,000) $(36,500)
Non-cash dividend to Parent$32,000
 $36,500
    
Cash (paid) refunded during the period for -   
Interest (net of amounts capitalized)$(12,838) $(13,486)


(8)(9)COMMITMENTS AND CONTINGENCIES


There have been no significant changes to commitments and contingencies from those previously disclosed in Note 11 of our Notes to the Financial Statements in our 20162018 Annual Report on Form 10-K.


(10)LEASES



We have a ground lease for the Wygen III generating facility with an affiliate and communication tower site and operation center facility leases with third parties. Our leases have remaining terms ranging from less than one year to 31 years.
The components of lease expense were as follows (in thousands):
 Income Statement LocationThree Months Ended March 31, 2019
Operating lease costOperations and maintenance$228
Variable lease costOperations and maintenance43
Total lease cost $271




Supplemental balance sheet information related to leases was as follows (in thousands):
 Balance Sheet LocationAs of March 31, 2019
Assets:  
Operating lease assetsOther assets, non-current$14,316
Total lease assets $14,316
   
Liabilities:  
Current:  
Operating leasesAccrued liabilities$279
   
Noncurrent:  
Operating leasesOther deferred credits and other liabilities14,054
Total lease liabilities $14,333


Supplemental cash flow information related to leases was as follows (in thousands):
 Three Months Ended March 31, 2019
Cash paid for amounts included in the measurement of lease liabilities: 
Operating cash flows from operating leases$223
Right-of-use assets obtained in exchange for lease obligations: 
Operating leases$—


As of March 31, 2019
Weighted average remaining lease term (years):
Operating leases31 years
Weighted average discount rate:
Operating leases4.4%


Scheduled maturities of operating lease liabilities for future years were as follows (in thousands):
 Total
2019 (a)
$681
2020856
2021855
2022856
2023853
Thereafter21,947
Total lease payments$26,048
Less imputed interest11,715
Present value of lease liabilities$14,333

(a)Includes lease obligations for the remaining nine months of 2019.




(11)EQUITY

A summary of the changes in equity is as follows:


Three Months Ended March 31, 2019Common Stock    
(in thousands except share amounts)SharesValueAdditional Paid in CapitalRetained EarningsAOCITotal
December 31, 201823,416
$23,416
$39,575
$342,145
$(891)$404,245
Net income (loss) available for common stock—
—
—
15,497
—
15,497
Other comprehensive income (loss), net of tax—
—
—
—
12
12
Cumulative effect of ASU 2016-02, Leases implementation
—
—
—
(7)—
(7)
Other adjustments—
—
—
1
—
1
March 31, 201923,416
$23,416
$39,575
$357,636
$(879)$419,748


Three Months Ended March 31, 2018Common Stock    
(in thousands except share amounts)SharesValueAdditional Paid in CapitalRetained EarningsAOCITotal
December 31, 201723,416
$23,416
$39,575
$332,499
$(1,258)$394,232
Net income (loss) available for common stock—
—
—
11,760
—
11,760
Other comprehensive income (loss), net of tax—
—
—
—
27
27
Non-cash dividend to Parent company—
—
—
(16,000)—
(16,000)
Other adjustments—
—
—
1
—
1
March 31, 201823,416
$23,416
$39,575
$328,260
$(1,231)$390,020





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


Amounts are presented on a pre-tax basis unless otherwise indicated.
Minor differences in amounts may result due to rounding.


Significant Events

Regulatory Matters


On June 16, 2017,April 30, 2019, S&P affirmed South Dakota Electric’s credit rating at A.

During the first quarter, South Dakota Electric received approval from the SDPUCcontinued construction on a settlement reached with the SDPUC staff agreeing to a six-year moratorium period effective July 1, 2017. As part of this agreement, South Dakota Electric will not increase base rates, absent an extraordinary event. The moratorium period also includes a suspension of both the Transmission Facility Adjustment and the Environmental Improvement Adjustment, and a $1.0$70 million, increase to the annual power marketing margin guarantee during this period. Additionally, existing regulatory asset balances of approximately $13 million related to decommissioning and Winter Storm Atlas will be amortized over the moratorium period. These balances were previously amortized over a 10-year period ending September 30, 2024. The vegetation management regulatory asset of $14 million, previously unamortized, will also be amortized over the moratorium period. The change in amortization periods for these costs will increase annual amortization expense by approximately $2.7 million.

The June 16, 2017 settlement had no impact to base rates. The following table illustrates information about certain enacted regulatory provisions with respect to South Dakota Electric:
JurisdictionAuthorized Rate of Return on EquityAuthorized Return on Rate BaseAuthorized Capital Structure Debt/EquityEffective DateTariffs and Rate MattersPercentage of Power Marketing Profit Shared with Customers
SDGlobal Settlement7.76%Global Settlement10/2014ECA,TCA, Energy Efficiency Cost Recovery/ DSM70%

Transmission

Construction was completed on the 144 mile-long175-mile electric transmission line connecting the Teckla Substation in northeast Wyomingfrom Stegall, Nebraska to the Lange Substation near Rapid City, South Dakota. The first94-mile final segment of this project connecting Tecklathe transmission line is expected to Osage, WY wasbe completed and placed in service on August 31, 2016. The second segment connecting Osage to Lange was placed in service on May 30, 2017.the fall of 2019.


Tax Matters - Potential Corporate Tax Reform

President Trump and Congressional Republicans have stated that one of their top priorities is enactment of comprehensive tax reform.  On November 2, 2017, the House Ways and Means Committee released its tax reform bill. Significant uncertainty exists as to the ultimate legislation that will be enacted into law.  We are evaluating the proposed legislation; any impact on our future results of operations, financial position and cash flows as a result of the potential changes cannot yet be determined and such changes could be material.




Results of Operations


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 is calculated as operating revenue less cost of fuel and purchased power. Our gross margin is impacted by the fluctuations in power purchases, 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.




The following tables provide certain financial information and operating statistics:


Three Months Ended September 30,Nine Months Ended September 30,Three Months Ended March 31,
20172016Variance20172016Variance20192018Variance
(in thousands)(in thousands)
Revenue$73,938
$66,728
$7,210
$213,785
$197,389
$16,396
$79,041
$73,815
$5,226
Fuel and purchased power22,843
18,421
4,422
64,604
55,375
9,229
22,733
22,440
293
Gross margin51,095
48,307
2,788
149,181
142,014
7,167
Gross margin (non-GAAP)56,308
51,375
4,933
  
Operating expenses27,397
25,897
1,500
84,395
79,888
4,507
31,666
31,011
655
Operating income23,698
22,410
1,288
64,786
62,126
2,660
24,642
20,364
4,278
  
Interest income (expense), net(4,779)(4,625)(154)(15,216)(14,478)(738)(5,432)(5,424)(8)
Other income (expense), net679
654
25
1,745
1,670
75
(375)(117)(258)
Income tax expense(5,772)(6,429)657
(15,632)(16,316)684
(3,338)(3,063)(275)
Net income$13,826
$12,010
$1,816
$35,683
$33,002
$2,681
$15,497
$11,760
$3,737





Three Months Ended September 30, 2017March 31, 2019 Compared to Three Months Ended September 30, 2016.March 31, 2018. Net income was $14$15 million compared to $12 million for the same period in the prior year primarily due to the following:


Gross margin increased overprimarily due to $2.4 million of higher power marketing revenue, customer growth, and favorable weather. A $1.6 million reduction in the prior year reflecting a $2.8 million increase inpurchased power capacity charges and higher rider revenues of $0.9 million, primarily related to transmission investment recovery. Higher cooling degree days were offset by lower usage per customer and lower commercial and industrial demand. Cooling degree days were 11% higher than normal inrecovery, comprised the current year compared to 18% lower than normal forremainder of the same period in the prior year.increase.


Operating expenses increased primarily due to higher outside services expenses and higher employee costs asdriven by labor and benefits partially offset by a result of prior year integration activities and transitiondecrease in expenses chargeddue to our Parent Company related to its prior year acquisition of SourceGas, increased amortization expenses as a result of the SDPUC settlement, and increased maintenance costs from outages.generation outage timing.


Interest expense, net, Other income (expense), net, and other income, netIncome tax expense were all comparable to the same period in the prior year.


Income tax expense: The effective tax rate was lower than the prior year, primarily due to higher flow-through benefits in the current year.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. Net income was $36 million compared to $33 million for the same period in the prior year primarily due to the following:

Gross margin increased over the prior year reflecting a $4.0 million increase in rider revenues primarily related to transmission investment recovery. Higher cooling degree days were slightly offset by lower usage per customer and lower commercial and industrial demand. Cooling degree days were 12% higher than normal in the current year compared to 3% lower than normal for the same period in the prior year.

Operating expenses increased primarily due to higher employee costs as a result of prior year integration activities and transition expenses charged to our Parent Company related to its prior year acquisition of SourceGas, increased amortization expenses as a result of the SDPUC settlement, and increased maintenance costs from higher outages.

Interest expense, net and other income, net were comparable to the same period in the prior year.

Income tax expense: The effective tax rate was lower than the prior year, primarily due to higher flow-through benefits in the current year.







Electric Revenue by Customer TypeElectric Revenue by Customer Type
Three Months Ended September 30, Nine Months Ended September 30,Three Months Ended March 31,
(in thousands)(in thousands)
2017 Percentage Change 2016 2017 Percentage Change 20162019 Percentage Change 2018
Residential$18,020
 3% $17,501
 $53,724
 1% $53,057
$21,190
 1% $21,061
Commercial25,459
 (1)% 25,714
 72,608
 (1)% 73,026
23,144
 (2)% 23,544
Industrial8,149
 (2)% 8,275
 24,774
 1% 24,540
8,357
 1% 8,276
Municipal1,071
 2% 1,053
 2,849
 —% 2,844
781
 (4)% 811
Total retail revenue52,699
 —% 52,543
 153,955
 —% 153,467
53,472
 —% 53,692
Contract wholesale (a)
8,048
 75% 4,596
 22,593
 78% 12,717
Wholesale off-system (b)
4,787
 20% 3,984
 11,044
 (2)% 11,304
Wholesale8,343
 (8)% 9,050
Market - off-system sales (a)
4,670
 105% 2,275
Other revenue (c)(b)
8,404
 50% 5,605
 26,193
 32% 19,901
12,556
 43% 8,798
Total revenue$73,938
 11% $66,728
 $213,785
 8% $197,389
$79,041
 7% $73,815
____________________
(a)Increase for the three and nine months ended September 30, 2017March 31, 2019 was primarily due to a new 50 MW power sales agreement effective January 1, 2017.higher trading volume opportunities driven by weather and energy prices.
(b)Increase for the three months ended September 30, 2017March 31, 2019 was driven by higher commodity prices on similar MWh quantities sold. For the nine months ended September 30, 2017 higher commodity prices primarily offset lower MWh quantities sold.
(c)Increase fromdue to the prior year is primarily duereserve to higher transmission revenues.revenue to reflect the reduction of the lower federal income tax rate from the TCJA on our existing rate tariffs.




Megawatt Hours Sold by Customer TypeMegawatt Hours Sold by Customer Type
Three Months Ended September 30, Nine Months Ended September 30,Three Months Ended March 31,
2017 Percentage Change 2016 2017 Percentage Change 20162019 Percentage Change 2018
Residential129,616
 5% 124,012
 386,709
 1% 381,616
169,936
 4% 163,113
Commercial212,773
 —% 213,276
 582,899
 (2)% 592,371
194,794
 —% 194,931
Industrial109,745
 —% 110,220
 323,038
 1% 320,861
108,196
 4% 104,302
Municipal10,156
 2% 9,927
 25,865
 —% 25,855
7,573
 1% 7,503
Total retail quantity sold462,290
 1% 457,435
 1,318,511
 —% 1,320,703
480,499
 2% 469,849
Contract wholesale (a)
185,723
 197% 62,547
 537,720
 195% 182,087
Wholesale off-system (b)
130,825
 2% 128,415
 388,287
 (12)% 438,852
Wholesale223,020
 (6)% 237,704
Market - off-system sales99,572
 8% 92,102
Total quantity sold778,838
 20% 648,397
 2,244,518
 16% 1,941,642
803,091
 —% 799,655
Losses and company use (c)
56,447
 36% 41,585
 155,477
 40% 111,437
Losses and Company use (a)
41,910
 47% 28,522
Total energy835,285
 21% 689,982
 2,399,995
 17% 2,053,079
845,001
 2% 828,177
____________________
(a)Increase for the three and nine months ended September 30, 2017 was primarily due to a new 50 MW power sales agreement effective January 1, 2017.
(b)Decrease in 2017 was primarily driven by commodity prices that impacted power marketing sales.
(c)Includes company uses, line losses, and excess exchange production.







Megawatt Hours Generated and PurchasedMegawatt Hours Generated and Purchased
Three Months Ended September 30, Nine Months Ended September 30,Three Months Ended March 31,
Generated -2017 Percentage Change 2016 2017 Percentage Change 20162019 Percentage Change 2018
Coal-fired423,766
 6% 401,231
 1,101,291
 4% 1,054,264
409,666
 3% 399,087
Natural Gas and Oil (a)
54,466
 31% 41,654
 75,840
 (22)% 96,649
47,703
 264% 13,107
Total generated478,232
 8% 442,885
 1,177,131
 2% 1,150,913
457,369
 11% 412,194
          
Total purchased (b)
357,053
 44% 247,097
 1,222,864
 36% 902,166
387,632
 (7)% 415,983
Total generated and purchased (b)
835,285
 21% 689,982
 2,399,995
 17% 2,053,079
845,001
 2% 828,177
____________________
(a) Increase is primarily due to low natural gas prices and the ability to generate at a lower cost than to purchase generation on the open market for the three months ended March 31, 2019.

 Power Plant Availability
 Three Months Ended March 31,
 20192018
Coal-fired plants (a)
98.2%92.9%
Other plants (b)
87.3%99.4%
Total availability92.4%96.3%
____________________
(a)Variances for the three and nine months ended September 30, 2017 compared to the same periods in the prior year are driven primarily by the ability to purchase excess generation in the open market at a lower or higher cost than to generate.
(b)Increase in 2017 is primarily driven by resource needs from a new 50 MW power sales agreement effective January 1, 2017.

 Power Plant Availability
 Three Months Ended September 30,Nine Months Ended September 30,
 201720162017 2016
Coal-fired plants (a)
97.5% 92.8% 84.8% 83.2%
Other plants93.7% 97.7% 97.0% 98.4%
Total availability95.5% 95.6% 91.3% 91.8%
____________________
(a)Both years included outages. 20172018 included planned outages at Neil Simpson II, Wyodak and Wygen II, and 2016 includedII.
(b)2019 includes a planned outage at Wygen III and an extended planned outage at Wyodak.Lange CT.



 Degree Days Degree Days
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 ActualVariance from 30-year Average ActualVariance from 30-year Average ActualVariance from 30-year Average ActualVariance from 30-year Average
            
Heating degree days202
(10)% 161
(23)% 4,242
(5)% 3,844
(13)%
Cooling degree days595
11 % 460
(18)% 709
12 % 646
(3)%
 Degree Days
 Three Months Ended March 31,
 2019 2018
 ActualVariance from Normal ActualVariance from Normal
      
Heating degree days3,916
22% 3,699
15%


Credit Ratings


Credit ratings impact our ability to obtain short and long-term financing, the cost of such financing, and vendor payment terms, including collateral requirements. The following table represents our secured credit rating from each agency’s review which was in effect at September 30, 2017:March 31, 2019:


Rating AgencySenior Secured Rating
S&P(a)
A-A
Moody’s(b)
A1
Fitch(c)
A

__________
(a)On April 30, 2019, S&P affirmed A rating.
(b)On December 12, 2018, Moody’s affirmed A1 rating.
(c)On October 11, 2018, Fitch affirmed A rating.






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 on which the statement is made, and 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 is 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 Item 1A of our 20162018 Annual Report on Form 10-K, including statements contained within Item 1A - Risk Factors and Part II, Item 1A of this Quarterly Report on Form 10-Q.


ITEM 4.CONTROLS AND PROCEDURES


This section should be read in conjunction with Item 9A, “Controls and Procedures” included in our Annual Report on Form 10-K for the year ended December 31, 2016.2018.


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, 2017.March 31, 2019. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective as of September 30, 2017.March 31, 2019.


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


Changes in Internal Control over Financial Reporting


During the quarter ended September 30, 2017,March 31, 2019, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.






BLACK HILLS POWER, INC.


Part II - Other Information


Item 1.Legal Proceedings


For information regarding legal proceedings, see Note 11 of Notes to Financial Statements in Item 8 of our 20162018 Annual Report on Form 10-K and Note 89 of our Notes to Condensed Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 89 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 Annual Report on Form 10-K for the year ended December 31, 2016.2018.




Item 6.Exhibits


Exhibit 3.1*
Restated Articles of Incorporation of the Registrant dated MarchJanuary 30, 20152018 (filed as Exhibit 3.13 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2015)8-K filed on February 5, 2018).


Exhibit 3.2*
Amended and Restated Bylaws of the Registrant dated March 30, 2015 (filed as Exhibit 3.2 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2015).


Exhibit 4.1*
Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to J.P. Morgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registration Statement on Form S-3 (No. 333-150669-01)). Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014).

First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to J.P. Morgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)).
Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registration Statement on Form S-3 (No. 333-150669-01)).
Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014).

Exhibit 31.1
Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.


Exhibit 31.2
Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.


Exhibit 32.1
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.


Exhibit 32.2
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.


Exhibit 101101.INSFinancial Statements for XBRL FormatInstance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCHXBRL Taxonomy Extension Schema Document
101.CALXBRL Taxonomy Extension Calculation Linkbase Document
101.DEFXBRL Taxonomy Extension Definition Linkbase Document
101.LABXBRL Taxonomy Extension Label Linkbase Document
101.PREXBRL Taxonomy Extension Presentation Linkbase Document
_________________________
*Previously filed as part of the filing indicated and incorporated by reference herein.






BLACK HILLS POWER, INC.


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 POWER, INC.




/S/ DAVIDLINDEN R. EMERYEVANS
DavidLinden R. Emery,Evans, Chairman, President
and Chief Executive Officer




/S/ RICHARD W. KINZLEY
Richard W. Kinzley, Senior Vice President
and Chief Financial Officer


Dated: NovemberMay 3, 20172019




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