UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended June 30, ~~2017~~2018
OR
o	TRANSITION 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 Dakota	IRS Identification Number 46-0111677
~~625 Ninth Street~~7001 Mount Rushmore Road
Rapid City, South Dakota ~~57701~~57702
Registrant’s telephone number (605) 721-1700
Former name, former address, and former fiscal year if changed since last report
NONE

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.



Yes x	No o

Indicate by check mark whether the Registrant has submitted electronically 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 filer	o		Accelerated filer	o

Non-accelerated filer	x	(Do not check if a smaller reporting company)

			Smaller reporting company	o

			Emerging growth company	o

If an emerging growth company, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).



Yes o	No x

As of July 31, ~~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	3

PART 1.	FINANCIAL INFORMATION

Item 1.	Financial Statements

	Condensed Statements of ~~Income and~~ Comprehensive Income - unaudited	4
	Three and Six Months Ended June 30, ~~2017~~2018 and ~~2016~~2017

	Condensed Balance Sheets - unaudited	5
	June 30, ~~2017~~2018 and December 31, ~~2016~~2017

	Condensed Statements of Cash Flows - unaudited	7
	Six Months Ended June 30, ~~2017~~2018 and ~~2016~~2017

	Notes to Condensed Financial Statements - unaudited	8

Item 2.	Managements’ Discussion and Analysis of Financial Condition and Results of Operations	1517

Item 4.	Controls and Procedures	1921

PART II.	OTHER INFORMATION	2022

Item 1.	Legal Proceedings	2022

Item 1A.	Risk Factors	2022

Item 6.	Exhibits	2022

	Signatures	21

	~~Exhibit Index~~	2223

GLOSSARY OF TERMS AND ABBREVIATIONS

The following terms and abbreviations appear in the text of this report and have the definitions described below:



AFUDC	Allowance for Funds Used During Construction
ASC	Accounting Standards Codification
ASU	Accounting Standards Update issued by the FASB
BHC	Black Hills Corporation; the Parent Company
Black Hills Energy	The name used to conduct the business of BHC utility companies
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc. a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills Service Company	Black Hills Service Company, LLC, a direct, wholly-owned subsidiary of BHC
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
~~Cooling Degree Day~~CDD	A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.
~~DSM~~	~~Demand Side Management~~
ECA	Energy Cost Adjustment - adjustments that allow us to pass the prudently-incurred cost of fuel and purchased energy through to customers.
FASB	Financial Accounting Standards Board
FERC	United States Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Accounting 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 Jack	Happy 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.
Horizon Point	BHC Corporate headquarters building in Rapid City, South Dakota, which was completed in 2017.
kV	Kilovolt
LIBOR	London Interbank Offered Rate
Moody’s	Moody’s Investors Service, Inc.
MW	Megawatts
SDPUC	South Dakota Public Utilities Commission
SEC	U. S. Securities and Exchange Commission
Silver Sage	Silver Sage Windpower, LLC, a subsidiary of Duke Energy Generation Services
South Dakota Electric	Includes Black Hills Power operations in South Dakota, Wyoming and Montana
S&P	Standard & Poor’s, a division of The McGraw-Hill Companies, Inc.
TCA	Transmission 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 Atlas~~TCJA	~~An 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
WRDC	Wyodak Resources Development Corp., an indirect, wholly-owned subsidiary of BHC

BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF ~~INCOME AND~~ COMPREHENSIVE INCOME


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
(unaudited)	2017			2016			2017			2016			2018			2017			2018			2017
	(in thousands)												(in thousands)
Revenue	$	66,053		$	62,019		$	139,847		$	130,661		$	70,676		$	66,053		$	144,491		$	139,847

Operating expenses:
Fuel and purchased power	18,612			16,224			41,761			36,954			20,753			18,612			43,193			41,761
Operations and maintenance	18,888			16,906			35,842			33,937			18,428			18,888			37,579			35,842
Depreciation and amortization	8,831			8,204			17,525			16,816			9,866			8,831			19,750			17,525
Taxes - property	2,010			1,749			3,631			3,238			2,134			2,010			4,110			3,631
Total operating expenses	48,341			43,083			98,759			90,945			51,181			48,341			104,632			98,759

Operating income	17,712			18,936			41,088			39,716			19,495			17,712			39,859			41,088

Other income (expense):
Interest expense	(5,635		)	(5,414		)	(11,390		)	(10,868		)	(5,654		)	(5,635		)	(11,241		)	(11,390		)
AFUDC - borrowed	392			298			584			521			152			392			200			584
Interest income	243			292			369			494			123			243			238			369
AFUDC - equity	717			566			1,188			989			137			717			171			1,188
Other income (expense), net	(69		)	(47		)	(122		)	27			(379		)	(69		)	(530		)	(122		)
Total other income (expense)	(4,352		)	(4,305		)	(9,371		)	(8,837		)	(5,621		)	(4,352		)	(11,162		)	(9,371		)

Income before income taxes	13,360			14,631			31,717			30,879			13,874			13,360			28,697			31,717
Income tax expense	(4,073		)	(4,825		)	(9,860		)	(9,887		)	(2,749		)	(4,073		)	(5,812		)	(9,860		)
Net income	9,287			9,806			21,857			20,992			11,125			9,287			22,885			21,857

Other comprehensive income (loss):
Reclassification adjustments of cash flow hedges settled and included in net income (net of tax (expense) benefit of $(5) and $(5) for the three months ended June 30, 2017 and 2016, and $(11) and $(11) for the six months ended June 30, 2017 and 2016, respectively)	11			11			21			21
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(8) and $(7) for the three months ended June 30, 2017 and 2016 and $(15) and $(14) for the six months ended June 30, 2017 and 2016, respectively)	14			13			28			27
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax (expense) benefit of $(5) and $(5) for the three months ended June 30, 2018 and 2017, and $(11) and $(11) for the six months ended June 30, 2018 and 2017, respectively)													11			11			21			21
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(9) and $(8) for the three months ended June 30, 2018 and 2017, and $(18) and $(15) for the six months ended June 30, 2018 and 2017, respectively)													17			14			34			28
Other comprehensive income	25			24			49			48			28			25			55			49

Comprehensive income	$	9,312		$	9,830		$	21,906		$	21,040		$	11,153		$	9,312		$	22,940		$	21,906

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

BLACK HILLS POWER, INC.

CONDENSED BALANCE SHEETS


							As of
(unaudited)	June 30, 2017			December 31, 2016			June 30, 2018			December 31, 2017
	(in thousands)						(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	1,156		$	234		$	5		$	16
Receivables - customers, net	26,702			30,614			29,556			29,050
Receivables - affiliates	6,596			9,526			5,426			5,664
Other receivables, net	334			351			1,536			196
Money pool notes receivable, net	12,471			28,409
Materials, supplies and fuel	22,989			22,389			24,165			23,443
Regulatory assets, current	21,453			18,119			18,290			18,993
Other, current assets	3,857			3,876
Other current assets							3,462			4,528
Total current assets	95,558			113,518			82,440			81,890

Investments	4,849			4,841			4,991			4,926

Property, plant and equipment	1,280,757			1,236,387			1,331,257			1,311,819
Less accumulated depreciation and amortization	(348,258		)	(338,828		)	(365,103		)	(358,946		)
Total property, plant and equipment, net	932,499			897,559			966,154			952,873

Other assets:
Regulatory assets, non-current	71,449			74,015			55,791			59,710
Other, non-current assets	3,586			3,816
Other non-current assets							8,972			3,747
Total other assets	75,035			77,831			64,763			63,457
TOTAL ASSETS	$	1,107,941		$	1,093,749		$	1,118,348		$	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


							As of
(unaudited)	June 30, 2017			December 31, 2016			June 30, 2018			December 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	$	15,842		$	14,158		$	14,239		$	14,766
Accounts payable - affiliates	23,745			31,799			25,185			25,653
Accrued liabilities	46,744			37,436			44,791			38,205
Money pool notes payable							14,949			13,397
Regulatory liabilities, current	825			84			5,756			842
Total current liabilities	87,156			83,477			104,920			92,863

Long-term debt	339,825			339,756			339,965			339,895

Deferred credits and other liabilities:
Deferred income tax liability, net, non-current	214,539			211,443
Deferred income tax liabilities, net							109,783			110,618
Regulatory liabilities, non-current	54,818			53,866			154,175			148,013
Benefit plan liabilities	19,645			19,544			16,785			16,285
Other, non-current liabilities	1,390			1,001			1,547			1,240
Total deferred credits and other liabilities	290,392			285,854			282,290			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 issued	23,416			23,416			23,416			23,416
Additional paid-in capital	39,575			39,575			39,575			39,575
Retained earnings	328,790			322,933			329,385			332,499
Accumulated other comprehensive loss	(1,213		)	(1,262		)	(1,203		)	(1,258		)
Total stockholder’s equity	390,568			384,662			391,173			394,232
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	1,107,941		$	1,093,749		$	1,118,348		$	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)	Six Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2018			2017
	(in thousands)						(in thousands)
Operating activities:
Net income	$	21,857		$	20,992		$	22,885		$	21,857
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization	17,525			16,816			19,750			17,525
Deferred income tax	1,605			18,009			(1,407		)	1,605
Employee benefits	408			886			760			408
AFUDC - equity	(1,188		)	(989		)
AFUDC							(171		)	(1,188		)
Other adjustments, net	408			(236		)	1,262			408
Change in operating assets and liabilities -
Accounts receivable and other current assets	7,188			3,234			(1,494		)	7,188
Accounts payable and other current liabilities	(3,486		)	(11,538		)	2,170			(3,486		)
Regulatory assets - current	(315		)	(7,026		)	2,797			(315		)
Regulatory liabilities - current	741			—			5,709			741
Contributions to defined benefit pension plan	—			(820		)
Other operating activities, net	380			168			(458		)	380
Net cash provided by (used in) operating activities	45,123			39,496			51,803			45,123

Investing activities:
Property, plant and equipment additions	(44,142		)	(35,153		)	(27,399		)	(44,142		)
Proceeds from sale of assets							4,994			—
Change in money pool notes receivable, net	(62		)	(4,286		)	—			(62		)
Other investing activities	3			(67		)	(4,961		)	3
Net cash provided by (used in) investing activities	(44,201		)	(39,506		)	(27,366		)	(44,201		)

Financing activities:
Change in money pool notes payable, net							(24,448		)	—
Net cash provided by (used in) financing activities	—			—			(24,448		)	—

Net change in cash and cash equivalents	922			(10		)	(11		)	922

Cash and cash equivalents, beginning of period	234			297			16			234
Cash and cash equivalents, end of period	$	1,156		$	287		$	5		$	1,156

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 ~~2016~~2017 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 ~~2016~~2017 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 June 30, ~~2017~~2018, December 31, ~~2016~~2017 and June 30, ~~2016~~2017 financial information and are of a normal recurring nature. The results of operations for the three ~~and six~~ months ended June 30, ~~2017~~2018 and June 30, ~~2016~~2017, and our financial condition as of June 30, ~~2017~~2018 and December 31, ~~2016~~2017 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 $19 million as of June 30, 2016. It also decreased net cash flows provided by operations by $12 million for the six months ended June 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 June 30, 2016 and to the Statements of Cash Flows for the six months ended June 30, 2016. There is no impact to the Statements of Income or Statements of Comprehensive Income (Loss) for any period reported.

Recently Issued ~~and Adopted~~ Accounting Standards

~~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 periodic 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 monitor utility industry implementation discussions and guidance. 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).~~ T~~his ASU requires changes in the pres~~entation 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~~.Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for ~~all~~most leases, ~~with a term greater than 12 months,~~ whereas today only ~~financing type~~financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. ~~Lessees~~Under the current guidance, lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard. The FASB also issued additional amendments to the new lease standard in July 2018, ASU No. 2018-11, allowing companies to adopt the new standard with a cumulative effect adjustment as of the beginning of the year of adoption with prior year comparative financial information and disclosures remaining as previously reported.

We ~~currently~~ expect to adopt this standard on January 1, 2019. For existing or expired land easements that were not previously accounted for as a lease, we anticipate electing the practical expedient which provides for no assessment of these easements. Further, we anticipate adopting the new standard with a cumulative effect adjustment with prior year comparative financial information remaining as previously reported when transitioning to the new standard. The standard also provides a transition practical expedient, commonly referred to as the “package of three”, that must be taken together and allows entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. We expect to elect the “package of three” practical expedient. We continue to evaluate the additional transition practical expedients available under the guidance and the impact of this new standard on our financial position, results of operations and cash ~~flows as well as monitor emerging guidance on such topics as easements~~flows. We are finalizing the process of identifying and ~~right of ways, pipeline laterals, purchase power agreements, pole attachments~~categorizing our lease contracts and ~~other industry-related areas.~~evaluating our current business processes relating to leases. We have selected and configured a new lease software solution that we are currently testing. We also ~~expect~~continue to ~~implement changes to systems, processes~~monitor utility industry lease implementation guidance that may change existing and ~~procedures in order to recognize and measure leases recorded on the balance sheet that are currently classified as operating leases.~~future lease classification.

Recently Adopted Accounting Standards

Revenue from Contracts with Customers, ASU 2014-09

~~In May 2014, the FASB issued~~Effective January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and its related amendments (collectively known as ASC 606). ~~The~~Under this standard, ~~provides companies with~~revenue is recognized when 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 whencustomer obtains control of ~~the~~promised goods or services ~~transfers~~in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the ~~customer. The new~~standard requires disclosure ~~requirements will provide information about~~of the nature, amount, timing and uncertainty of revenue and cash flows arising from ~~revenue~~ contracts with customers. ~~The guidance is effective for annual~~We applied the five-step method outlined in the ASU to all in-scope revenue streams and ~~interim reporting periods beginning after December 15, 2017 with early adoption on January 1, 2017 permitted. Entities will have~~elected 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~~implementation method. Implementation 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 ondid not have a ~~modified retrospective basis effective January 1, 2018. We continue to actively assess all of our sources of revenue to determine the~~material impact ~~that adoption of the new standard will have~~ on our financial position, results of operations ~~and~~or cash flows. ~~Our evaluation includes identifying revenue streams by like contracts to allow for ease~~Implementation of ~~implementation. A majority~~the standard did not have a significant impact on the measurement or recognition of our revenues are from regulated tariff offerings that provide natural gas or electricity with a defined contractual term. For such arrangements, we expect that revenue from contracts with the customer will be equivalentrevenue; therefore, no cumulative adoption adjustment to the ~~electricity or gas delivered~~opening balance of Retained earnings at the date of initial application was necessary. The additional disclosures required by the ASU are included in ~~that period. Therefore,~~Note 2.

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

Effective January 1, 2018, we ~~do not expect there will be a significant shift~~adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The standard requires employers to report the service cost component in the ~~timing~~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. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets was applied on a prospective basis for the six months ended June 30, 2018. Retrospective impact was not material and therefore not adjusted. For our rate-regulated entities, we capitalize the other components of net periodic benefit costs into regulatory assets or ~~pattern~~regulatory liabilities and maintain a FERC-to-GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs resulted in offsetting changes to Operating income and Other income. Implementation of ~~revenue recognition for regulated tariff based sales. The evaluation~~the standard did not have a material impact on our financial position, results of ~~other revenue streams is ongoing,~~operations or cash flows.

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

Effective January 1, 2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. We implemented this standard effective January 1, 2018 using the retrospective transition method. This standard had no impact on our non-regulated revenues and those tied to longer term contractual commitments. We also continue to monitor outstanding industry implementation issues and assess the impacts to our current accounting policies and/financial position, results of operations or ~~patterns of revenue recognition.~~cash flows.

(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 June 30, 2018		Six Months Ended June 30, 2018
	(in thousands)
Customer types:
Retail	$	46,525	$	97,166
Wholesale	8,191		17,241
Market - off-system sales	3,449		5,724
Transmission/Other	12,372		24,090
Revenue from contracts with customers	70,537		144,221
Other revenues	139		270
Total revenues	$	70,676	$	144,491

Timing of revenue recognition:
Services transferred over time	70,537		144,221
Revenue from contracts with customers	$	70,537	$	144,221

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. We have been collaborating with our regulators in the states in which we provide utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We estimated and recorded a revenue reserve of approximately $2.6 million and $5.7 million during the three and six months ended June 30, 2018.

On June 29, 2018, we filed our proposed TCJA agreement with the SDPUC with expected final approval by the end of 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:


	June 30, 2017			December 31, 2016			June 30, 2018			December 31, 2017
Accounts receivable trade	$	15,731		$	16,972		$	17,471		$	15,994
Unbilled revenues	11,137			13,799			12,270			13,280
Allowance for doubtful accounts	(166		)	(157		)	(185		)	(224		)
Receivables - customers, net	$	26,702		$	30,614		$	29,556		$	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)	June 30, 2017		December 31, 2016		Maximum Amortization (in years)	June 30, 2018		December 31, 2017
Regulatory assets:
Unamortized loss on reacquired debt ^(a)	8	$	1,674	$	1,815	7	$	1,393	$	1,534
Deferred taxes on AFUDC ^(b)	45	9,913		9,367		45	5,038		5,095
Employee benefit plans^(c)	12	20,100		20,100		12	19,665		19,465
Deferred energy and fuel cost adjustments - current^(a)	Less than 1 year	20,397		23,016
Deferred energy and fuel cost adjustments^(a)						1	16,923		19,602
Deferred taxes on flow through accounting ^(a)	35	13,464		12,545		54	8,137		7,579
Decommissioning costs, net of amortization^(d)	6	11,201		12,456		5	9,224		10,252
Other regulatory assets ^(a) ^(d)	6	16,153		12,835
Vegetation management, net of amortization						5	11,518		12,669
Other regulatory assets ^(a)						5	2,183		2,507
Total regulatory assets		$	92,902	$	92,134		$	74,081	$	78,703


Regulatory liabilities:
Cost of removal for utility plant ^(a)	61	$	42,514	$	41,541	61	$	50,040	$	44,056
Employee benefit plan costs and related deferred taxes ^(c)	12	12,304		12,304		12	6,808		6,808
Excess deferred income taxes						40	97,061		97,101
TCJA revenue reserve ^(d)						subject to approval	5,709		—
Other regulatory liabilities	13	825		105		13	313		890
Total regulatory liabilities		$	55,643	$	53,950		$	159,931	$	148,855

____________________


(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, respectively.~~base.

(d)

~~In accordance with a settlement agreement approved by the SDPUC on~~As of June ~~16, 2017,~~30, 2018, the amortization ~~of South Dakota Electric’s decommissioning costs of approximately $11 million, vegetation management costs of approximately $14 million,~~period is yet to be determined and Winter Storm Atlas costs of approximately $2.0 million will be 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 expensesubject to approval by ~~approximately $2.7 million.~~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.

On April 30, 2018 Black Hills and the SDPUC staff signed an amendment to the stipulation executed in June 2017. The amendment provides clarifying language to certain provisions from the stipulation specific to the TCJA and performance based rates. The amendment was approved by the SDPUC on May 15, 2018.

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. We have been collaborating with our regulators in the states in which we provide utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We estimated and recorded a reserve to revenue of approximately $2.6 million and $5.7 million during the three and six months ended June 30, 2018.

On June 29, 2018, we filed our proposed TCJA agreement with the SDPUC with expected final approval by the end of 2018.


~~(4)~~(5)	RELATED-PARTY TRANSACTIONS

Non-Cash Dividend to Parent

We recorded non-cash dividends to our Parent of $26 million and $16 million for six months ended June 30, 2018 and June 30, 2017, respectively, and changed the utility Money pool note by $26 million and $16 million for the six months ended June 30, 2018 and June 30, 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:


	June 30, 2017		December 31, 2016		June 30, 2018		December 31, 2017
Receivables - affiliates	$	6,596	$	9,526	$	5,426	$	5,664
Accounts payable - affiliates	$	23,745	$	31,799	$	25,185	$	25,653

Money Pool Notes Receivable and Notes Payable

We ~~have entered into a~~participate 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 June 30, ~~2017~~2018, the average cost of borrowing under the Utility Money Pool was ~~1.61%~~2.49%.

We had the following balances with the Utility Money Pool (in thousands) as of:

June 30, 2017 December 31, 2016
Money pool notes receivable, net $ 12,471
$ 28,409



	June 30, 2018		December 31, 2017
Money pool notes payable	$	14,949	$	13,397

Our net interest income (expense) relating to balances with the Utility Money Pool was as follows (in thousands):

Three Months Ended June 30, Six Months Ended June 30,
2017 2016 2017 2016
Net interest income (expense) $ 90
$ 290
$ 216
$ 568



	Three Months Ended June 30,					Six Months Ended June 30,
	2018			2017		2018			2017
Net interest income (expense)	$	(96	)	$	90	$	(132	)	$	216

Other related party activity was as follows (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016		2018		2017		2018		2017
Revenue:
Energy sold to Cheyenne Light	$	625	$	648	$	1,505	$	1,309	$	501	$	625	$	1,204	$	1,505
Rent from electric properties(a)	$	935	$	1,375	$	1,870	$	2,588	$	3,691	$	935	$	7,369	$	1,870

Fuel and purchased power:
Purchases of coal from WRDC	$	3,052	$	3,357	$	7,332	$	8,153	$	4,249	$	3,052	$	8,316	$	7,332
Purchase of excess energy from Cheyenne Light	$	76	$	53	$	116	$	108	$	82	$	76	$	168	$	116
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	369	$	353	$	975	$	1,017	$	381	$	369	$	1,022	$	975
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	637	$	602	$	1,656	$	1,729	$	696	$	637	$	1,789	$	1,656

Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	99	$	100	$	198	$	200	$	96	$	99	$	192	$	198

Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	7,109	$	6,177	$	13,720	$	12,898	$	7,604	$	7,109	$	15,210	$	13,720

____________________


(a)	The increase for the three and six months ended June 30, 2018 is driven by Horizon Point shared facility revenues. See Horizon Point agreement information below.

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.


(56)	EMPLOYEE BENEFIT PLANS

The components of net periodic benefit cost for the Defined Benefit Pension Plan were as follows (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Service cost	$	136		$	151		$	272		$	302		$	129		$	136		$	258		$	272
Interest cost	585			625			1,170			1,250			549			585			1,097			1,170
Expected return on plan assets	(897		)	(908		)	(1,794		)	(1,816		)	(887		)	(897		)	(1,773		)	(1,794		)
Prior service cost	11			11			22			22			11			11			22			22
Net loss (gain)	307			499			614			998			516			307			1,032			614
Net periodic benefit cost	$	142		$	378		$	284		$	756		$	318		$	142		$	636		$	284

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 June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Service cost	$	51		$	51		$	103		$	102		$	49		$	51		$	97		$	103
Interest cost	44			47			88			94			44			44			89			88
Prior service cost (benefit)	(84		)	(84		)	(168		)	(168		)	(84		)	(84		)	(168		)	(168		)
Net periodic benefit cost	$	11		$	14		$	23		$	28		$	9		$	11		$	18		$	23

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 June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016		2018		2017		2018		2017
Interest cost	$	29	$	30	$	58	$	60	$	27	$	29	$	54	$	58
Net loss (gain)	21		21		43		42		26		21		52		43
Net periodic benefit cost	$	50	$	51	$	101	$	102	$	53	$	50	$	106	$	101

For the three and six months ended June 30, 2018, service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other income (expense), net on the Condensed Statements of Comprehensive Income. For the three and six months ended June 30, 2017, service costs and non-service costs were recorded in Operations and maintenance expense. Because prior years’ costs were not considered material, they were not reclassified on the Condensed 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 ~~accounts.~~account. On July ~~24, 2017,~~25, 2018, we made ~~contributions~~a contribution of approximately $1.8 million (included in the table below) to the Defined Benefit Pension ~~Plan in the amount of approximately $1.8 million.~~Plan. Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made for ~~2017~~2018 and anticipated contributions for ~~2017~~2018 and ~~2018~~2019 are as follows (in thousands):


	Contributions Six Ended June 30, 2017		Remaining Anticipated Contributions for 2017		Anticipated Contributions for 2018		Contributions Six Months Ended June 30, 2018		Remaining Anticipated Contributions for 2018		Anticipated Contributions for 2019
Defined Benefit Pension Plan	$	—	$	1,834	$	1,834	$	—	$	1,795	$	1,789
Defined Benefit Postretirement Healthcare Plan	$	271	$	271	$	565	$	267	$	267	$	554
Supplemental Non-qualified Defined Benefit Plans	$	124	$	124	$	246	$	123	$	123	$	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 ~~2016~~2017 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:


	June 30, 2017				December 31, 2016				June 30, 2018				December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents ^(a)	$	1,156	$	1,156	$	234	$	234	$	5	$	5	$	16	$	16
Long-term debt, net of deferred financing costs ^(b)	$	339,825	$	434,228	$	339,756	$	410,466
Long-term debt, including current maturities ^{(b) (c)}									$	339,965	$	418,410	$	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 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


Six months ended June 30,	2017			2016
							Six Months Ended June 30,
							2018			2017
	(in thousands)						(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	10,495		$	5,355		$	7,477		$	10,495
Non-cash (decrease) to money pool notes receivable, net	$	(16,000	)	$	(24,500	)	$	(26,000	)	$	(16,000	)
Non-cash dividend to Parent	$	16,000		$	24,500		$	26,000		$	16,000

Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(10,786	)	$	(10,547	)	$	(10,930	)	$	(10,786	)


~~(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 ~~2016~~2017 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~~On July 25, 2018, we placed in service the first 48-mile segment of a $70 million, 175-mile, 230-kilovolt transmission line from Rapid City, South Dakota, to Stegall, Nebraska. The remaining segment is expected to be in service by the end of 2019.

On ~~June 16, 2017,~~July 19. 2018, Fitch affirmed South Dakota Electric received approval from the SDPUC 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 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:~~

Jurisdiction Authorized Rate of Return on Equity Authorized Return on Rate Base Authorized Capital Structure Debt/Equity Effective Date Tariffs and Rate Matters Percentage of Power Marketing Profit Shared with Customers
SD Global Settlement 7.76% Global Settlement 10/2014 ECA,TCA, Energy Efficiency Cost Recovery/ DSM 70%

~~Transmission~~

Construction was completed on the 144 mile-long transmission line connecting the Teckla Substation in northeast Wyoming to the Lange Substation near Rapid City, South Dakota. The first segment of this project connecting Teckla to Osage, WY was placed in service on August 31, 2016. The second segment connecting Osage to Lange was placed in service on May 30, 2017.

Electric’s credit rating at A.

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 June 30,									Six Months Ended June 30,									Three Months Ended June 30,									Six Months Ended June 30,
	2017			2016			Variance			2017			2016			Variance			2018			2017			Variance			2018			2017			Variance
	(in thousands)																		(in thousands)
Revenue	$	66,053		$	62,019		$	4,034		$	139,847		$	130,661		$	9,186		$	70,676		$	66,053		$	4,623		$	144,491		$	139,847		$	4,644
Fuel and purchased power	18,612			16,224			2,388			41,761			36,954			4,807			20,753			18,612			2,141			43,193			41,761			1,432
Gross margin(a)	47,441			45,795			1,646			98,086			93,707			4,379			49,923			47,441			2,482			101,298			98,086			3,212

Operating expenses	29,729			26,859			2,870			56,998			53,991			3,007			30,428			29,729			699			61,439			56,998			4,441
Operating income	17,712			18,936			(1,224		)	41,088			39,716			1,372			19,495			17,712			1,783			39,859			41,088			(1,229		)

Interest income (expense), net	(5,000		)	(4,824		)	(176		)	(10,437		)	(9,853		)	(584		)	(5,379		)	(5,000		)	(379		)	(10,803		)	(10,437		)	(366		)
Other income (expense), net	648			519			129			1,066			1,016			50			(242		)	648			(890		)	(359		)	1,066			(1,425		)
Income tax expense	(4,073		)	(4,825		)	752			(9,860		)	(9,887		)	27			(2,749		)	(4,073		)	1,324			(5,812		)	(9,860		)	4,048
Net income	$	9,287		$	9,806		$	(519	)	$	21,857		$	20,992		$	865		$	11,125		$	9,287		$	1,838		$	22,885		$	21,857		$	1,028

________________


(a)	Non-GAAP measure

Three Months Ended June 30, ~~2017~~2018 Compared to Three Months Ended June 30, ~~2016.~~2017. Net income was ~~$9.3~~$11 million compared to ~~$9.8~~$9.3 million for the same period in the prior year primarily due to the following:

Gross margin increased ~~over the prior year reflecting~~primarily due to higher non-energy revenue of $2.4 million primarily related to Horizon Point shared facility revenue, higher commercial and industrial demand of $0.9 million, a ~~$2.5~~$0.8 million increase in residential margins primarily from warmer weather in the current year, and higher rider revenues of $1.0 million primarily related to transmission investment recovery. ~~Partially offsetting these~~These increases ~~was $0.4~~were partially offset by a $2.6 million inreserve to revenue to reflect the reduction of the lower ~~residential margins driven primarily by lower cooling degree days. Compared to normal, cooling degree days were 15% higher than normal in~~federal income tax rate from the ~~current year compared to 74% higher than normal for the same period in the prior year.~~TCJA on our existing rate tariffs.

Operating expenses increased primarily due to increased depreciation from higher ~~employee costs as a result of~~asset base driven by the prior year ~~integration activities~~additions of Horizon Point and transition expenses charged to our Parent Company related to its prior year acquisition of SourceGas, higher property taxes with increased asset base, and increased maintenance costs from higher outages.the Teckla-Lange transmission line.

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

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

Income tax expense: The effective tax rate ~~was lower than~~decreased from the prior year ~~primarily~~ due to ~~higher flow-through benefits~~the reduction in the ~~current year.~~federal corporate income tax rate from 35 percent to 21 percent from the TCJA, effective January 1, 2018.

Six Months Ended June 30, ~~2017~~2018 Compared to Six Months Ended June 30, ~~2016.~~2017. Net income was ~~$22~~$23 million compared to ~~$21~~$22 million for the same period in the prior year primarily due to the following:

Gross margin increased ~~over the prior year reflecting~~primarily due to higher non-energy revenue of $4.6 million primarily related to Horizon Point shared facility revenue, higher commercial and industrial demand of $0.5 million, a ~~$3.0~~$1.9 million increase in residential margins primarily from warmer weather in the current year, and higher rider revenues of $1.8 million primarily related to transmission investment recovery. These increases were partially offset by a $5.7 million reserve to revenue to reflect the reduction of the lower federal income tax rate from the TCJA on our existing rate tariffs.

Operating expenses increased ~~primarily~~ due to increased depreciation and property taxes of $2.7 million from higher asset base driven by the prior year additions of Horizon Point and the Teckla-Lange transmission line. $1.8 million of higher vegetation management expenses, employee costs, ~~as a result~~and facility costs comprise the remainder of the increase compared to the same period in the prior year integration activities and transition expenses charged to our Parent Company related to its prior year acquisition of SourceGas, higher property taxes with increased asset base, and increased maintenance costs from higher outages.year.

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

Income tax expense: The effective tax rate ~~was comparable~~decreased from the prior year due to the ~~same period~~reduction 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 Type										Electric Revenue by Customer Type
	Three Months Ended June 30,					Six Months Ended June 30,					Three Months Ended June 30,					Six Months Ended June 30,
	(in thousands)										(in thousands)
	2017		Percentage Change	2016		2017		Percentage Change	2016		2018		Percentage Change	2017		2018		Percentage Change	2017
Residential	$	15,633	(4)%	$	16,241	$	35,704	—%	$	35,556	$	16,426	5%	$	15,633	$	37,487	5%	$	35,704
Commercial	22,858		(4)%	23,723		47,149		—%	47,312		23,538		3%	22,858		47,082		—%	47,149
Industrial	8,171		5%	7,764		16,625		2%	16,265		8,170		—%	8,171		16,446		(1)%	16,625
Municipal	942		(2)%	960		1,778		(1)%	1,791		876		(7)%	942		1,687		(5)%	1,778
Total retail revenue	47,604		(2)%	48,688		101,256		—%	100,924		49,010		3%	47,604		102,702		1%	101,256
Contract wholesale ^(a)	6,702		70%	3,947		14,545		79%	8,121
Wholesale off-system ^(b)	2,424		(11)%	2,734		6,257		(15)%	7,320
Wholesale ^(a)											8,191		22%	6,702		17,241		19%	14,545
Market - off-system sales ^(b)											3,449		42%	2,424		5,724		(9)%	6,257
Other revenue ^(c)	9,323		40%	6,650		17,789		24%	14,296		10,026		8%	9,323		18,824		6%	17,789
Total revenue	$	66,053	7%	$	62,019	$	139,847	7%	$	130,661	$	70,676	7%	$	66,053	$	144,491	3%	$	139,847

____________________


(a)	Increase for the three and six months ended June 30, ~~2017~~2018 was primarily ~~due to a new 50 MW power sales agreement with Cargill effective January 1, 2017.~~driven by increased volumes on long term wholesale contracts.


(b)	~~Decrease in 2017 revenue~~Increase for three months ended June 30, 2018 was ~~primarily driven by commodity prices that impacted power marketing sales.~~


~~(c)~~	~~Increase from the prior year is primarily~~ due to higher ~~transmission revenues.~~trading volume opportunities.


	Megawatt Hours Sold by Customer Type						Megawatt Hours Sold by Customer Type
	Three Months Ended June 30,			Six Months Ended June 30,			Three Months Ended June 30,			Six Months Ended June 30,
	2017	Percentage Change	2016	2017	Percentage Change	2016	2018	Percentage Change	2017	2018	Percentage Change	2017
Residential	107,521	(6)%	114,851	257,093	—%	257,604	115,905	8%	107,521	279,018	9%	257,093
Commercial	173,720	(9)%	190,207	370,126	(2)%	379,095	186,784	8%	173,720	381,715	3%	370,126
Industrial	103,497	1%	102,620	213,293	1%	210,641	106,100	3%	103,497	210,402	(1)%	213,293
Municipal	8,104	(5)%	8,487	15,709	(1)%	15,928	7,479	(8)%	8,104	14,982	(5)%	15,709
Total retail quantity sold	392,842	(6)%	416,165	856,221	(1)%	863,268	416,268	6%	392,842	886,117	3%	856,221
Contract wholesale ^(a)	165,881	196%	56,087	351,997	194%	119,540
Wholesale off-system ^(b)	102,966	(12)%	117,064	257,462	(17)%	310,437
Wholesale ^(a)							218,132	31%	165,881	455,836	29%	351,997
Market - off-system sales ^(b)							141,866	38%	102,966	233,968	(9)%	257,462
Total quantity sold	661,689	12%	589,316	1,465,680	13%	1,293,245	776,266	17%	661,689	1,575,921	8%	1,465,680
Losses and company use ^(c)	57,189	87%	30,528	99,030	42%	69,852	61,677	8%	57,189	90,199	(9)%	99,030
Total energy	718,878	16%	619,844	1,564,710	15%	1,363,097	837,943	17%	718,878	1,666,120	6%	1,564,710

____________________


(a)	Increase for the three and six months ended June 30, ~~2017~~2018 was primarily ~~due to a new 50 MW power sales agreement with Cargill effective January 1, 2017.~~driven by increased volumes on long-term wholesale contracts.


(b)	~~Decrease~~Increase for three months ended June 30, 2018 was due to improved pricing in ~~2017 sales was primarily driven by commodity prices that impacted power marketing sales.~~markets compared to same period in prior year.


(c)	Includes company uses, line losses, and excess exchange production.


	Megawatt Hours Generated and Purchased						Megawatt Hours Generated and Purchased
	Three Months Ended June 30,			Six Months Ended June 30,			Three Months Ended June 30,			Six Months Ended June 30,
Generated -	2017	Percentage Change	2016	2017	Percentage Change	2016	2018	Percentage Change	2017	2018	Percentage Change	2017
Coal-fired(a)	289,540	9%	265,032	677,525	4%	653,033	388,081	34%	289,540	787,168	16%	677,525
Gas-fired ^(a)	11,024	(72)%	39,433	21,374	(61)%	54,995
Natural Gas and Oil ^(b)							23,758	116%	11,024	36,865	72%	21,374
Total generated	300,564	(1)%	304,465	698,899	(1)%	708,028	411,839	37%	300,564	824,033	18%	698,899

Total purchased ^(b)	418,314	33%	315,379	865,811	32%	655,069	426,104	2%	418,314	842,087	(3)%	865,811
Total generated and purchased ^(b)	718,878	16%	619,844	1,564,710	15%	1,363,097	837,943	17%	718,878	1,666,120	6%	1,564,710

____________________

(a) Increase for the three and six months ended June 30, 2018 compared to same periods in prior year is driven primarily by planned outages at Neil Simpson II, Wyodak, and Wygen II in 2017.

(b) Increase is primarily due to low natural gas prices and the ability to generate at a lower cost than to purchase excess generation on the open market for the three and six months ended June 30, 2018.



	Power Plant Availability
	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Coal-fired plants ^(a)	91.3	%	67.6	%	92.1	%	78.4	%
Other plants	97.5	%	98.0	%	98.4	%	98.7	%
Total availability	94.6	%	83.7	%	95.5	%	89.2	%

____________________


(a)	~~Decrease is primarily due to the ability to purchase excess generation in the open market at a lower cost than to generate for the three and six months ended June 30, 2017.~~


~~(b)~~	~~Increase in 2017 is primarily driven by resource needs from a new 50 MW power sales agreement with Cargill, effective January 1, 2017.~~

Power Plant Availability
Three Months Ended June 30, Six Months Ended June 30,
2017 2016 2017 2016
Coal-fired plants ^(a)
67.6 % 64.5 % 78.4 % 78.4 %
Other plants 98.0 % 99.2 % 98.7 % 98.7 %
Total availability 83.7 % 84.2 % 89.2 % 90.0 %

~~____________________~~


~~(a)~~	~~Both years included outages.~~ 2017 included planned outages at Neil Simpson II, Wyodak and Wygen ~~II, and 2016 included a planned outage at Wygen III and an extended planned outage at Wyodak.~~II.


	Degree Days						Degree Days						Degree Days						Degree Days
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016			2018			2017			2018			2017
	Actual	Variance from 30-year Average		Actual	Variance from 30-year Average		Actual	Variance from 30-year Average		Actual	Variance from 30-year Average		Actual	Variance from 30-year Average		Actual	Variance from 30-year Average		Actual	Variance from 30-year Average		Actual	Variance from 30-year Average

Heating degree days	910	(11	)%	877	(13	)%	4,040	(5	)%	3,683	(13	)%	1,037	1	%	910	(11	)%	4,736	12	%	4,040	(5	)%
Cooling degree days	114	15	%	186	74	%	114	15	%	186	74	%	132	33	%	114	15	%	132	33	%	114	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 June 30, ~~2017:~~2018:



Rating Agency	Secured Rating
S&P	A-
Moody’s	A1
Fitch^(a)	A

__________


(a)	On July 19, 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 ~~2016~~2017 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 June 30, ~~2017.~~2018. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective as of June 30, ~~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~~Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the quarter ended June 30, ~~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 ~~2016~~2017 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*	Restated Articles of Incorporation of the Registrant dated ~~March~~January 30, ~~2015~~2018 (filed as Exhibit ~~3.1~~3 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 101	Financial 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: August ~~8, 2017~~7, 2018

~~EXHIBIT INDEX~~


~~Exhibit Number~~	~~Description~~


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*


~~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 101~~	~~Financial Statements for XBRL Format~~

~~_________________________~~


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

2223



Jurisdiction	Authorized Rate of Return on Equity	Authorized Return on Rate Base	Authorized Capital Structure Debt/Equity	Effective Date	Tariffs and Rate Matters	Percentage of Power Marketing Profit Shared with Customers
SD	Global Settlement	7.76%	Global Settlement	10/2014	ECA,TCA, Energy Efficiency Cost Recovery/ DSM	70%