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 March 31, 20172018
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

As of April 30, 2017,2018, 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
   
PART 1.FINANCIAL INFORMATION 
   
Item 1.Financial Statements 
   
 Condensed Statements of Income and Comprehensive Income - unaudited
 Three Months Ended March 31, 20172018 and 20162017 
   
 Condensed Balance Sheets - unaudited
 March 31, 20172018 and December 31, 20162017 
   
 Condensed Statements of Cash Flows - unaudited
 Three Months Ended March 31, 20172018 and 20162017 
   
 Notes to Condensed Financial Statements - unaudited
   
Item 2.Managements’ Discussion and Analysis of Financial Condition and Results of Operations
   
Item 4.Controls and Procedures
   
PART II.OTHER INFORMATION
   
Item 1.Legal Proceedings
   
Item 1A.Risk Factors
   
Item 6.Exhibits
   
 Signatures
Exhibit Index



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 DayA 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.
ECAEnergy Cost Adjustment - adjustments that allow us to pass the prudently-incurred cost of fuel and purchased energy through to customers.
FASBFinancial Accounting Standards Board
FERCUnited States Federal Energy Regulatory Commission
FitchFitch Ratings
GAAPAccounting principles generally accepted in the United States of America
Happy JackHappy Jack Wind Farms, LLC, a subsidiary of Duke Energy Generation Services
Heating degree dayA 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.
kVKilovolt
LIBORLondon Interbank Offered Rate
Moody’sMoody’s Investors Service, Inc.
MWMegawatts
SDPUCSouth Dakota Public Utilities Commission
SECU. S. Securities and Exchange Commission
Silver SageSilver Sage Windpower, LLC, a subsidiary of Duke Energy Generation Services
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.
TCATransmission 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.
TCJATax Cuts and Jobs Act enacted December 22, 2017
WRDCWyodak Resources Development Corp., an indirect, wholly-owned subsidiary of BHC






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

Three Months Ended March 31,Three Months Ended March 31,
(unaudited)2017 20162018 2017
(in thousands)(in thousands)
Revenue$73,794
 $68,642
$73,815
 $73,794
      
Operating expenses:      
Fuel and purchased power23,149
 20,730
22,440
 23,149
Operations and maintenance16,954
 17,031
19,151
 16,954
Depreciation and amortization8,694
 8,612
9,884
 8,694
Taxes - property1,621
 1,489
1,976
 1,621
Total operating expenses50,418
 47,862
53,451
 50,418
      
Operating income23,376
 20,780
20,364
 23,376
      
Other income (expense):      
Interest expense(6,336) (5,454)(5,587) (6,336)
AFUDC - borrowed192
 223
48
 192
Interest income707
 202
115
 707
AFUDC - equity471
 423
34
 471
Other income (expense), net(53) 74
(151) (53)
Total other income (expense)(5,019) (4,532)(5,541) (5,019)
      
Income from continuing operations before income taxes18,357
 16,248
Income before income taxes14,823
 18,357
Income tax expense(5,787) (5,062)(3,063) (5,787)
Net income12,570
 11,186
11,760
 12,570
      
Other comprehensive income (loss):      
Reclassification adjustments of cash flow hedges settled and included in net income (net of tax (expense) benefit of $(6) and $(6) for the three months ended March 31, 2017 and 2016, respectively)10
 10
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(8) and $(7) for the three months ended March 31, 2017 and 2016, respectively)14
 14
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 March 31, 2018 and 2017, respectively)10
 10
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(9) and $(8) for the three months ended March 31, 2018 and 2017, respectively)17
 14
Other comprehensive income24
 24
27
 24
      
Comprehensive income$12,594
 $11,210
$11,787
 $12,594

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



BLACK HILLS POWER, INC.
CONDENSED BALANCE SHEETS

(unaudited)March 31, 2017December 31, 2016March 31, 2018December 31, 2017
(in thousands)(in thousands)
ASSETS  
Current assets:  
Cash and cash equivalents$1,127
$234
$12
$16
Receivables - customers, net27,457
30,614
29,502
29,050
Receivables - affiliates5,390
9,526
6,925
5,664
Other receivables, net420
351
252
196
Money pool notes receivable, net32,949
28,409
Materials, supplies and fuel23,244
22,389
24,471
23,443
Regulatory assets, current20,536
18,119
20,078
18,993
Other, current assets3,286
3,876
Other current assets4,076
4,528
Total current assets114,409
113,518
85,316
81,890
  
Investments4,849
4,841
4,918
4,926
  
Property, plant and equipment1,254,710
1,236,387
1,318,781
1,311,819
Less accumulated depreciation and amortization(342,400)(338,828)(359,344)(358,946)
Total property, plant and equipment, net912,310
897,559
959,437
952,873
  
Other assets:  
Regulatory assets, non-current73,445
74,015
56,134
59,710
Other, non-current assets3,545
3,816
Other non-current assets8,796
3,747
Total other assets76,990
77,831
64,930
63,457
TOTAL ASSETS$1,108,558
$1,093,749
$1,114,601
$1,103,146

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



BLACK HILLS POWER, INC.
CONDENSED BALANCE SHEETS

(unaudited)March 31, 2017December 31, 2016March 31, 2018December 31, 2017
(in thousands, except common stock par value and share amounts)(in thousands, except common stock par value and share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY  
Current liabilities:  
Accounts payable$16,809
$14,158
$15,187
$14,766
Accounts payable - affiliates27,289
31,799
24,767
25,653
Accrued liabilities44,891
37,436
45,512
38,205
Money pool notes payable13,541
13,397
Regulatory liabilities, current
84
3,996
842
Total current liabilities88,989
83,477
103,003
92,863
  
Long-term debt339,791
339,756
339,930
339,895
  
Deferred credits and other liabilities:  
Deferred income tax liability, net, non-current214,657
211,443
Deferred income tax liabilities, net110,081
110,618
Regulatory liabilities, non-current53,896
53,866
153,607
148,013
Benefit plan liabilities19,617
19,544
16,540
16,285
Other, non-current liabilities1,351
1,001
1,420
1,240
Total deferred credits and other liabilities289,521
285,854
281,648
276,156
  
Commitments and contingencies (Notes 4, 5 and 8)
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
23,416
23,416
Additional paid-in capital39,575
39,575
39,575
39,575
Retained earnings328,504
322,933
328,260
332,499
Accumulated other comprehensive loss(1,238)(1,262)(1,231)(1,258)
Total stockholder’s equity390,257
384,662
390,020
394,232
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY$1,108,558
$1,093,749
$1,114,601
$1,103,146

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,Three Months Ended March 31,
2017201620182017
(in thousands)(in thousands)
Operating activities:  
Net income$12,570
$11,186
$11,760
$12,570
Adjustments to reconcile net income to net cash provided by operating activities-  
Depreciation and amortization8,694
8,612
9,884
8,694
Deferred income tax2,704
18,076
(898)2,704
Employee benefits205
443
380
205
AFUDC - equity(471)(423)
AFUDC(34)(471)
Other adjustments, net559
296
1,052
559
Change in operating assets and liabilities -  
Accounts receivable and other current assets7,908
(3,409)(2,478)7,908
Accounts payable and other current liabilities(380)(7,656)3,320
(380)
Regulatory assets - current(2,170)(4,193)1,807
(2,170)
Regulatory liabilities - current(84)
3,171
(84)
Other operating activities, net(152)481
35
(152)
Net cash provided by (used in) operating activities29,383
23,413
27,999
29,383
  
Investing activities:  
Property, plant and equipment additions(16,976)(18,928)(13,533)(16,976)
Proceeds from sale of assets4,994

Change in money pool notes receivable, net(11,540)13,683

(11,540)
Other investing activities26
(27)(3,608)26
Net cash provided by (used in) investing activities(28,490)(5,272)(12,147)(28,490)
  
Financing activities:  
Change in money pool notes payable, net(15,856)
Net cash provided by (used in) financing activities

(15,856)
  
Net change in cash and cash equivalents893
18,141
(4)893
  
Cash and cash equivalents, beginning of period234
297
16
234
Cash and cash equivalents, end of period$1,127
$18,438
$12
$1,127

See Note 78 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 20162017 Annual Report on Form 10-K)

(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 20162017 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 March 31, 20172018, December 31, 20162017 and March 31, 20162017 financial information and are of a normal recurring nature. The results of operations for the three months ended March 31, 20172018 and March 31, 20162017, and our financial condition as of March 31, 20172018 and December 31, 20162017 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

RevisionsRecently Issued Accounting Standards

Certain revisions haveLeases, 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 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 maderevised in regards to prior years’ financial informationwhen an arrangement conveys the right to conformcontrol 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 presentation.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.

We revisedcurrently expect to adopt this standard on January 1, 2019 and anticipate electing not to assess existing or expired land easements that were not previously accounted for as a lease when transitioning to the new standard. We continue to evaluate the impact of this new standard on our presentationfinancial position, results of operations and cash flows as well as monitor utility industry implementation guidance. We continue the process of identifying and certain cash transactions processed on behalf of affiliates.categorizing our lease contracts and evaluating our current business processes relating to leases. We have banking arrangements at certain financial institutions whereby if required, paymentsselected and initiated implementation 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 $11 million as of March 31, 2016. It also decreased net cash flows provided by operations by $3.3 million for the three months ended March 31, 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 March 31, 2016 and to the Statements of Cash Flows for the three months ended March 31, 2016. There is no impact to the Statements of Income or Statements of Comprehensive Income (Loss) for any period reported.new lease software solution.



Recently Issued and 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, 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

In March 2017, the FASB issuedEffective 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”Cost. The changes to the standard requirerequires 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. ASU 2017-07 will be applied retrospectively for the presentationThe capitalization of only 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 bewas applied on a prospective basis. ASU 2017-07 is effectiveFor 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 annual periods beginning after December 15, 2017, including interim periods within those annual periods. We are currently assessing the changes to the standard.these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs will resultresulted in offsetting changes to Operating income and Other income and areincome. Implementation of the standard did not expected to be material.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

In August 2016, the FASB issuedEffective 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. The ASU will beWe implemented this standard effective for fiscal years beginning after December 15, 2017. We will useJanuary 1, 2018 using the retrospective transition method to adopt thismethod. This standard with fiscal years beginning after December 15, 2017.The adoption of this standard will not have a materialhad no impact on our financial position, results of operations or cash flows.

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 for all leases with terms of more than 12 months. Lessees are permitted to make an accounting policy election to not recognize the asset and liability for leases with a term of 12 months or less. 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 ASC is largely unchanged from the previous accounting standard. In addition, the ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which includes a number of practical expedients. The guidance is effective for us beginning after December 15, 2018. Early adoption is permitted. We are currently assessing the impact that adoption of ASU 2016-02 will have on our financial position, results of operations or cash flows.

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 will adopt this standard for annual and interim reporting periods beginning after December 15, 2017. We continue to actively assess all of our sources of revenue to determine the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. Our evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. A majority of our revenues are from regulated tariff offerings that provide electricity with a defined contractual term. For such arrangements, we expect that the revenue from contracts with the customer will be equivalent to the electricity delivered in that period. Therefore, we do not expect that there will be a significant shift in the timing or pattern of revenue recognition for regulated tariff-based sales. The evaluation of other revenue streams is ongoing, including those tied to longer term contractual commitments. However, a number of industry-specific implementation issues are still unresolved and the final resolution of these issues could impact our current accounting policies and/or patterns for revenue recognition, as well as the transition method selected.



(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 electric utility services tariffs - Our regulated operations, as defined by ASC 980, 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 commodity electricity and 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 regulated utility sales are subject to regulatory-approved tariffs.

Power sales agreements - We 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, we also sell 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.

The following table depicts 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. Sales tax and other similar taxes are excluded from revenues.

 Three Months Ended March 31, 2018
 (in thousands)
Customer types: 
Retail$50,641
Wholesale9,050
Market - off-system sales2,275
Transmission/Other11,718
Revenue from contracts with customers73,684
Other revenues131
Total revenues$73,815
  
Timing of revenue recognition: 
Services transferred at a point in time
Services transferred over time73,684
Revenue from contracts with customers$73,684

The majority of the 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 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.



Revenue Not in Scope of ASC 606

Other revenues included in the table above include revenue accounted for under separate accounting guidance, including lease revenue under ASC 840 and alternative revenue programs revenue under ASC 980.

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 Power’s regulators have directed the utility to calculate the impact of tax reform on existing customer rates and tariffs caused by the income tax rate reduction. Until the regulators have a chance to review and approve these calculations, the utility continues to charge customers existing rates with the embedded 35% tax rate and estimate a reserve to revenue based on current discussions or filed applications with the regulators. We estimated and recorded a revenue reserve of approximately $3.1 million during the three months ended March 31, 2018.

Unbilled Revenue

Revenues attributable to energy 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 may 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 and is further discussed in Note 1 of our Notes to the Financial Statements of our 2017 Annual Report on Form 10-K Business Description. 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.

(23)
ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

Following is a summary of Receivables - customers, net included in the accompanying Condensed Balance Sheets (in thousands) as of:
March 31, 2017December 31, 2016March 31, 2018December 31, 2017
Accounts receivable trade$16,197
$16,972
$16,992
$15,994
Unbilled revenues11,524
13,799
12,772
13,280
Allowance for doubtful accounts(264)(157)(262)(224)
Receivables - customers, net$27,457
$30,614
$29,502
$29,050



(34)
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:
Recovery/Amortization Period
(in years)
March 31, 2017 December 31, 2016
Maximum Amortization
(in years)
March 31, 2018 December 31, 2017
Regulatory assets:        
Unamortized loss on reacquired debt (a)
8$1,745
 $1,815
7$1,464
 $1,534
Deferred taxes on AFUDC (b)
459,607
 9,367
455,050
 5,095
Employee benefit plans (c)
1220,100
 20,100
1219,723
 19,465
Deferred energy and fuel cost adjustments - current (a)
Less than 1 year23,075
 23,016
117,912
 19,602
Deferred taxes on flow through accounting (a)
3512,802
 12,545
547,929
 7,579
Decommissioning costs, net of amortization(b)
812,025
 12,456
69,738
 10,252
Other regulatory assets (a) (d)
214,627
 12,835
Vegetation management, net of amortization612,093
 12,669
Other regulatory assets (a)
62,303
 2,507
Total regulatory assets $93,981
 $92,134
 $76,212
 $78,703

Regulatory liabilities:        
Cost of removal for utility plant (a)
61$41,592
 $41,541
61$49,580
 $44,056
Employee benefit plan costs and related deferred taxes (c)
1212,304
 12,304
126,808
 6,808
Excess deferred income taxes4097,061
 97,101
TCJA revenue reserve (d)
subject to approval3,121
 
Other regulatory liabilities13
 105
131,033
 890
Total regulatory liabilities $53,896
 $53,950
 $157,603
 $148,855
____________________
(a)RecoveryWe 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, respectively.base.
(d)Includes approximately $14 million and $12 millionAs of vegetation management expenses at March 31, 20172018, the amortization period is yet to be determined and December 31, 2016, respectively, for which we are allowed a rate of return.subject to approval by our regulators.

Regulatory Matters
Except as discussed below, 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 2017 Annual Report on Form 10-K.

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 Power’s regulators have issued orders directing the utility to calculate the impacts of tax reform on existing rates/tariffs caused by the income tax rate reduction. Until each regulator has a chance to review and approve the calculations, the utility continues to charge customers existing rates with the embedded 35% federal tax rate, resulting in a reserve to revenue until new rates reflecting the 21% federal tax rate are effective. We estimated and recorded a reserve to revenue of approximately $3.1 million during the three months ended March 31, 2018.

We are working with our respective regulators to address the impact of tax reform and the appropriate benefit to customers.




(4)(5)RELATED-PARTY TRANSACTIONS

Non-Cash Dividend to Parent

We recorded non-cash dividends to our Parent of $16 million and $7.0 million for three months ended March 31, 2018 and March 31, 2017, respectively, and decreased the utility Money pool note receivable by $16 million and $7.0 million for the three months ended March 31, 2018 and March 31, 2017, respectively.

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, 2017 December 31, 2016March 31, 2018 December 31, 2017
Receivables - affiliates$5,390
 $9,526
$6,925
 $5,664
Accounts payable - affiliates$27,289
 $31,799
$24,767
 $25,653

Money Pool Notes Receivable and Notes Payable

We have entered into aparticipate in the Utility Money Pool Agreement (the “Agreement”) with BHC, Black Hills Service Company and the utility companies conducting business as Black Hills Energy. We are the administrator of the Money Pool.Agreement). Under the Agreement, we may borrow from BHC;the pool; however the Agreement restricts usthe 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 and advances 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 March 31, 20172018, the average cost of borrowing under the Utility Money Pool was 1.47%2.54%.

We had the following balances with the Utility Money Pool (in thousands) as of:
 March 31, 2017 December 31, 2016
Money pool notes receivable, net$32,949
 $28,409
 March 31, 2018 December 31, 2017
Money pool notes payable$13,541
 $13,397

Our net interest income (expense) relating to balances with the Utility Money Pool was as follows (in thousands):
 Three Months Ended March 31,
 20172016
Net interest income (expense)$126
$278
 Three Months Ended March 31,
 20182017
Net interest income (expense)$(36)$126



Other related party activity was as follows (in thousands):
Three Months Ended March 31,Three Months Ended March 31,
2017201620182017
Revenue:  
Energy sold to Cheyenne Light$878
$661
$703
$878
Rent from electric properties$1,272
$1,213
$3,678
$1,272
  
Fuel and purchased power:
  
Purchases of coal from WRDC$4,280
$4,796
$4,067
$4,280
Purchase of excess energy from Cheyenne Light$40
$55
$86
$40
Purchase of renewable wind energy from Cheyenne Light - Happy Jack$606
$664
$641
$606
Purchase of renewable wind energy from Cheyenne Light - Silver Sage$1,019
$1,127
$1,093
$1,019
  
Gas transportation service agreement:  
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation$99
$136
$96
$99
  
Corporate support:  
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings$6,611
$6,721
$7,606
$6,611

Horizon Point Agreement

We have a shared facility agreement among South Dakota Electric, Black Hills Service Company, and Black Hills Utility Holdings 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.

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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,Three Months Ended March 31,
2017 20162018
2017
Service cost$136
 $151
$129
 $136
Interest cost585
 625
548
 585
Expected return on plan assets(897) (908)(886) (897)
Prior service cost11
 11
11
 11
Net loss (gain)307
 499
516
 307
Net periodic benefit cost$142
 $378
$318
 $142



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,Three Months Ended March 31,
2017 20162018 2017
Service cost$52
 $51
$48
 $52
Interest cost44
 47
45
 44
Prior service cost (benefit)(84) (84)(84) (84)
Net periodic benefit cost$12
 $14
$9
 $12

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,Three Months Ended March 31,
2017 20162018 2017
Interest cost$29
 $30
$27
 $29
Net loss (gain)22
 21
26
 22
Net periodic benefit cost$51
 $51
$53
 $51

For the three months ended March 31, 2018, service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other income (expense), net on the Condensed Statements of Comprehensive Income. For the three months ended March 31, 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 Statements of Comprehensive Income. See Note 1 for additional information.

Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust.Trust account. Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made for 20172018 and anticipated contributions for 20172018 and 20182019 are as follows (in thousands):
Contributions
Three Months Ended March 31, 2017
Remaining Anticipated Contributions for 2017Anticipated Contributions for 2018
Contributions
Three Months Ended
March 31, 2018
Remaining Anticipated Contributions for 2018Anticipated Contributions for 2019
Defined Benefit Pension Plan$
$1,305
$660
$
$1,795
$1,789
Defined Benefit Postretirement Healthcare Plan$135
$406
$565
$134
$401
$554
Supplemental Non-qualified Defined Benefit Plans$62
$185
$246
$61
$184
$241




(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 20162017 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:
March 31, 2017 December 31, 2016March 31, 2018 December 31, 2017
Carrying AmountFair Value Carrying AmountFair ValueCarrying AmountFair Value Carrying AmountFair Value
Cash and cash equivalents (a)
$1,127
$1,127
 $234
$234
$12
$12
 $16
$16
Long-term debt, including current maturities (b)
$339,791
$424,453
 $339,756
$410,466
Long-term debt, including current maturities (b) (c)
$339,930
$429,001
 $339,895
$446,978
_________________
(a)Carrying value approximates fair value due to either 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)Long-term debt is valued using the market approach based on observable inputs of quoted market prices and yields available for debt instruments either directly or indirectly for similar maturities and debt ratingsliabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy. The carrying
(c)Carrying amount of our variable ratelong-term debt approximates fair value due to the variable interest rates with short reset periods.is net of deferred financing costs.

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

Three months ended March 31,2017 20162018 2017
(in thousands)(in thousands)
Non-cash investing and financing activities -      
Property, plant and equipment acquired with accrued liabilities$10,998
 $5,087
$7,556
 $10,998
Non-cash (decrease) to money pool notes receivable, net$(7,000) $(12,500)$(16,000) $(7,000)
Non-cash dividend to Parent$7,000
 $12,500
$16,000
 $7,000
      
Cash (paid) refunded during the period for -      
Interest (net of amounts capitalized)$(3,014) $(2,989)$(3,088) $(3,014)

(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 20162017 Annual Report on Form 10-K.

(10)INCOME 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. We have made our 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 rate regulators, which could have a material impact on the Company’s future results of operations, cash flows or financial position. We revalued our deferred tax assets and liabilities as of December 31, 2017, which reflected our estimate of the impact of the TCJA. We will continue to evaluate subsequent regulations, clarifications and interpretations with the assumptions made, which could materially change our estimate.



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

During the first quarter of 2016,2018, we commenced construction of the $54a $70 million, 230-kV, 144175 mile-long transmission line that will connect the Teckla Substation in northeast Wyoming, to the Lange Substation nearconnects Rapid City, South Dakota.Dakota to Stegall, Nebraska. The project will be constructed in two segments, with the first segment of this project connecting Teckla to Osage, WY was energized on August 31, 2016. The second segment of the project is expected to be placed in service in 2018 and the first half of 2017.second segment expected to be serving customers in 2019.

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 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 March 31,Three Months Ended March 31,
20172016Variance20182017Variance
(in thousands)(in thousands)
Revenue$73,794
$68,642
$5,152
$73,815
$73,794
$21
Fuel and purchased power23,149
20,730
2,419
22,440
23,149
(709)
Gross margin50,645
47,912
2,733
51,375
50,645
730
  
Operating expenses27,269
27,132
137
31,011
27,269
3,742
Operating income23,376
20,780
2,596
20,364
23,376
(3,012)
  
Interest income (expense), net(5,437)(5,029)(408)(5,424)(5,437)13
Other income (expense), net418
497
(79)(117)418
(535)
Income tax expense(5,787)(5,062)(725)(3,063)(5,787)2,724
Net income$12,570
$11,186
$1,384
$11,760
$12,570
$(810)



Three Months Ended March 31, 20172018 Compared to Three Months Ended March 31, 2016.2017. Net income was $13$12 million compared to $11$13 million for the same period in the prior year primarily due to the following:

Gross margin increased over the prior year reflecting higher non-energy revenue of $2.2 million primarily duerelated to higher transmission revenue andHorizon Point rent income, a $1.1 million increase in residential margins primarily from colder weather as compared to the same period in the prior year.current year, and higher rider revenues of $0.8 million primarily related to transmission investment recovery. These increases were partially offset by a $3.1 million reserve to revenue to reflect the reduction of the lower federal income tax rate from the TCJA on our existing rate tariffs and $0.3 million lower commercial and industrial demand.

Operating expenses were comparableincreased primarily due to $2.8 million of higher vegetation management expenses. Higher employee costs, property taxes and outage related expenses comprise the remainder of the increase compared to the same period in the prior year.

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

Other income (expense), net was comparabledecreased due to the same period in thehigher prior year.year AFUDC associated with higher prior year capital spend.

Income tax expense: The effective tax rate was comparabledecreased from the prior year due to the same periodreduction in the prior year.federal corporate income tax rate from 35 percent to 21 percent from the TCJA, effective January 1, 2018.




Electric Revenue by Customer TypeElectric Revenue by Customer Type
Three Months Ended March 31,Three Months Ended March 31,
(in thousands)(in thousands)
2017 Percentage Change 20162018 Percentage Change 2017
Residential$20,071
 4% $19,315
$21,061
 5% $20,071
Commercial24,291
 3% 23,589
23,544
 (3)% 24,291
Industrial8,454
 (1)% 8,501
8,276
 (2)% 8,454
Municipal836
 1% 831
811
 (3)% 836
Total retail revenue53,652
 3% 52,236
53,692
 —% 53,652
Contract wholesale (a)
7,843
 88% 4,174
Wholesale off-system (b)
3,833
 (16)% 4,586
Wholesale (a)
9,050
 15% 7,843
Market - off-system sales (b)
2,275
 (41)% 3,833
Other revenue8,466
 11% 7,646
8,798
 4% 8,466
Total revenue$73,794
 8% $68,642
$73,815
 —% $73,794
____________________
(a)Increase fromfor the prior year isthree months ended March 31, 2018 was primarily due to a new power-sales agreement which was effective January 1, 2017.driven by colder weather.
(b)Decrease in 2017 revenuefor three months ended March 31, 2018 was primarilydue to softer market conditions driven by commoditynatural gas prices that impacted power marketing sales.and excess energy in the market.

Megawatt Hours Sold by Customer TypeMegawatt Hours Sold by Customer Type
Three Months Ended March 31,Three Months Ended March 31,
2017 Percentage Change 20162018 Percentage Change 2017
Residential149,572
 5% 142,753
163,113
 9% 149,572
Commercial196,406
 4% 188,888
194,931
 (1)% 196,406
Industrial109,796
 2% 108,021
104,302
 (5)% 109,796
Municipal7,605
 2% 7,441
7,503
 (1)% 7,605
Total retail quantity sold463,379
 4% 447,103
469,849
 1% 463,379
Contract wholesale (a)
186,116
 193% 63,453
Wholesale off-system (b)
154,496
 (20)% 193,373
Wholesale (a)
237,704
 28% 186,116
Market - off-system sales (b)
92,102
 (40)% 154,496
Total quantity sold803,991
 14% 703,929
799,655
 (1)% 803,991
Losses and company use(c)41,841
 6% 39,324
28,522
 (32)% 41,841
Total energy845,832
 14% 743,253
828,177
 (2)% 845,832
____________________
(a)Effective January 1, 2017, we have an energy sales agreement with Cargill through DecemberIncrease for the three months ended March 31, 2021 to supply 50 MW of energy during heavy and light load timing intervals.2018 was primarily driven by colder weather.
(b)Decrease in 2017 salesfor three months ended March 31, 2018 was primarilydue to softer market conditions driven by commoditylower natural gas prices that impacted power marketing sales.and excess energy in the market.
(c)Includes company uses, line losses, and excess exchange production.



Megawatt Hours Generated and PurchasedMegawatt Hours Generated and Purchased
Three Months Ended March 31,Three Months Ended March 31,
Generated -2017 Percentage Change 20162018 Percentage Change 2017
Coal-fired387,985
 —% 388,001
399,087
 3% 387,985
Gas-fired (a)
10,350
 (33)% 15,562
Natural Gas and Oil (a)
13,107
 27% 10,350
Total generated398,335
 (1)% 403,563
412,194
 3% 398,335
   
 
Total purchased (b)
447,497
 32% 339,690
415,983
 (7)% 447,497
Total generated and purchased (b)
845,832
 14% 743,253
828,177
 (2)% 845,832
____________________
(a)Decrease is primarily due to the ability to purchase excess generation in the open market at a lower cost than to generateIncrease for the three months ended March 31, 2017.
(b)Increase2018 compared to the same periods in 2017 isthe prior year are driven primarily driven by resource needs from a new 50 MW power sales agreement with Cargill, effective January 1, 2017.lower natural gas prices compared to purchased power.

Power Plant AvailabilityPower Plant Availability
Three Months Ended March 31,Three Months Ended March 31,
2017201620182017
Coal-fired plants (a)
89.2% 92.4% 92.9% 89.2% 
Other plants99.4% 98.3% 99.4% 99.4% 
Total availability94.6% 95.8% 96.3% 94.6% 
____________________
(a)Decrease is primarily due toBoth years included outages. 2018 included planned outages at Neil Simpson II, Wyodak and Wygen II, and 2017 included a planned outage at Neil Simpson II during the three months ended March 31, 2017.Wygen III and an extended planned outage at Wyodak.


 Degree Days
 Three Months Ended March 31,
 2017 2016
 ActualVariance from 30-year Average ActualVariance from 30-year Average
      
Heating degree days3,130
(3)% 2,806
(13)%
 Degree Days
 Three Months Ended March 31,
 2018 2017
 ActualVariance from 30-year Average ActualVariance from 30-year Average
      
Heating degree days3,699
15% 3,130
(3)%
Cooling degree days
% 
 %

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 March 31, 2017:2018:

Rating AgencySecured Rating
S&PA-
Moody’sA1
FitchA



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 20162017 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, 2016.2017.

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 March 31, 2017.2018. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective as of March 31, 2017.2018.

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 March 31, 2017,2018, 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 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 20162017 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, 2016.2017.


Item 6.Exhibits

Exhibit 3.1*

Exhibit 3.2*

Exhibit 4.1*
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

Exhibit 31.2

Exhibit 32.1

Exhibit 32.2

Exhibit 101Financial Statements for XBRL Format
_________________________
*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/ 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: May 8, 20174, 2018




EXHIBIT INDEX


Exhibit NumberDescription

Exhibit 3.1*Restated Articles of Incorporation of the Registrant dated March 30, 2015 (filed as Exhibit 3.1 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2015).

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).

Exhibit 31.1Certification 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 31.2Certification 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 32.1Certification 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 32.2Certification 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 101Financial Statements for XBRL Format
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*Previously filed as part of the filing indicated and incorporated by reference herein.


2023