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 ~~September 30, 2017~~March 31, 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 ~~October 31, 2017,~~April 30, 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 Nine~~ Months Ended ~~September 30,~~March 31, 2018 and 2017 ~~and 2016~~

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

	Condensed Statements of Cash Flows - unaudited	7
	~~Nine~~Three Months Ended ~~September 30,~~March 31, 2018 and 2017 ~~and 2016~~

	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	2123

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	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	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.
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
~~SourceGas~~	SourceGas Holdings LLC and its subsidiaries, a gas utility owned by funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) that was acquired by BHC on February 12, 2016, and is now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy)
South Dakota 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
~~Wyoming Electric~~	~~Includes Cheyenne Light’s electric utility operations~~

BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF ~~INCOME AND~~ COMPREHENSIVE INCOME


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
(unaudited)	2017			2016			2017			2016			2018			2017
	(in thousands)												(in thousands)
Revenue	$	73,938		$	66,728		$	213,785		$	197,389		$	73,815		$	73,794

Operating expenses:
Fuel and purchased power	22,843			18,421			64,604			55,375			22,440			23,149
Operations and maintenance	16,747			15,601			52,589			49,538			19,151			16,954
Depreciation and amortization	9,053			8,547			26,578			25,363			9,884			8,694
Taxes - property	1,597			1,749			5,228			4,987			1,976			1,621
Total operating expenses	50,240			44,318			148,999			135,263			53,451			50,418

Operating income	23,698			22,410			64,786			62,126			20,364			23,376

Other income (expense):
Interest expense	(5,483		)	(5,454		)	(16,873		)	(16,322		)	(5,587		)	(6,336		)
AFUDC - borrowed	369			319			953			840			48			192
Interest income	335			510			704			1,004			115			707
AFUDC - equity	676			606			1,864			1,595			34			471
Other income (expense), net	3			48			(119		)	75			(151		)	(53		)
Total other income (expense)	(4,100		)	(3,971		)	(13,471		)	(12,808		)	(5,541		)	(5,019		)

Income before income taxes	19,598			18,439			51,315			49,318			14,823			18,357
Income tax expense	(5,772		)	(6,429		)	(15,632		)	(16,316		)	(3,063		)	(5,787		)
Net income	13,826			12,010			35,683			33,002			11,760			12,570

Other comprehensive income (loss):
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax (expense) benefit of $(6) and $(6) for the three months ended September 30, 2017 and 2016, and $(17) and $(17) for the nine months ended September 30, 2017 and 2016, respectively)	10			10			31			31
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(8) and $(8) for the three months ended September 30, 2017 and 2016 and $(23) and $(21) for the nine months ended September 30, 2017 and 2016, respectively)	14			14			42			41
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 income	24			24			73			72			27			24

Comprehensive income	$	13,850		$	12,034		$	35,756		$	33,074		$	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)	September 30, 2017			December 31, 2016			March 31, 2018			December 31, 2017
	(in thousands)						(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	1,171		$	234		$	12		$	16
Receivables - customers, net	27,579			30,614			29,502			29,050
Receivables - affiliates	5,498			9,526			6,925			5,664
Other receivables, net	335			351			252			196
Money pool notes receivable, net	8,881			28,409
Materials, supplies and fuel	23,622			22,389			24,471			23,443
Regulatory assets, current	18,819			18,119			20,078			18,993
Other, current assets	3,432			3,876
Other current assets							4,076			4,528
Total current assets	89,337			113,518			85,316			81,890

Investments	4,902			4,841			4,918			4,926

Property, plant and equipment	1,298,855			1,236,387			1,318,781			1,311,819
Less accumulated depreciation and amortization	(354,788		)	(338,828		)	(359,344		)	(358,946		)
Total property, plant and equipment, net	944,067			897,559			959,437			952,873

Other assets:
Regulatory assets, non-current	73,178			74,015			56,134			59,710
Other, non-current assets	3,545			3,816
Other non-current assets							8,796			3,747
Total other assets	76,723			77,831			64,930			63,457
TOTAL ASSETS	$	1,115,029		$	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)	September 30, 2017			December 31, 2016			March 31, 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	$	14,701		$	14,158		$	15,187		$	14,766
Accounts payable - affiliates	26,828			31,799			24,767			25,653
Accrued liabilities	50,337			37,436			45,512			38,205
Money pool notes payable							13,541			13,397
Regulatory liabilities, current	825			84			3,996			842
Total current liabilities	92,691			83,477			103,003			92,863

Long-term debt	339,860			339,756			339,930			339,895

Deferred credits and other liabilities:
Deferred income tax liability, net, non-current	220,857			211,443
Deferred income tax liabilities, net							110,081			110,618
Regulatory liabilities, non-current	55,822			53,866			153,607			148,013
Benefit plan liabilities	15,721			19,544			16,540			16,285
Other, non-current liabilities	1,393			1,001			1,420			1,240
Total deferred credits and other liabilities	293,793			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 issued	23,416			23,416			23,416			23,416
Additional paid-in capital	39,575			39,575			39,575			39,575
Retained earnings	326,883			322,933			328,260			332,499
Accumulated other comprehensive loss	(1,189		)	(1,262		)	(1,231		)	(1,258		)
Total stockholder’s equity	388,685			384,662			390,020			394,232
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	1,115,029		$	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)	Nine Months Ended September 30,						Three Months Ended March 31,
	2017			2016			2018			2017
	(in thousands)						(in thousands)
Operating activities:
Net income	$	35,683		$	33,002		$	11,760		$	12,570
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization	26,578			25,363			9,884			8,694
Deferred income tax	6,188			22,267			(898		)	2,704
Employee benefits	613			1,327			380			205
AFUDC	(2,817		)	(1,595		)	(34		)	(471		)
Other adjustments, net	2,298			118			1,052			559
Change in operating assets and liabilities -
Accounts receivable and other current assets	6,567			5,499			(2,478		)	7,908
Accounts payable and other current liabilities	3,077			(501		)	3,320			(380		)
Regulatory assets - current	1,543			(4,029		)	1,807			(2,170		)
Contributions to defined benefit pension plan	(4,000		)	(820		)
Regulatory liabilities - current							3,171			(84		)
Other operating activities, net	(1,097		)	(3,994		)	35			(152		)
Net cash provided by (used in) operating activities	74,633			76,637			27,999			29,383

Investing activities:
Property, plant and equipment additions	(61,537		)	(65,062		)	(13,533		)	(16,976		)
Proceeds from sale of assets							4,994			—
Change in money pool notes receivable, net	(12,472		)	(10,966		)	—			(11,540		)
Other investing activities	313			(81		)	(3,608		)	26
Net cash provided by (used in) investing activities	(73,696		)	(76,109		)	(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 equivalents	937			528			(4		)	893

Cash and cash equivalents, beginning of period	234			297			16			234
Cash and cash equivalents, end of period	$	1,171		$	825		$	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 ~~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 ~~September 30, 2017~~March 31, 2018, December 31, ~~2016~~2017 and ~~September 30, 2016~~March 31, 2017 financial information and are of a normal recurring nature. The results of operations for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2018 and ~~September 30, 2016~~March 31, 2017, and our financial condition as of ~~September 30, 2017~~March 31, 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 $9.4 million as of September 30, 2016. It also decreased net cash flows provided by operations by $2.2 million for the nine months ended September 30, 2016. We assessed the materiality of these changes, taking into account quantitative and qualitative factors, and determined them to be immaterial to the balance sheet as of September 30, 2016 and to the Statements of Cash Flows for the nine months ended September 30, 2016. There is no impact to the Statements of Income or Statements of Comprehensive Income (Loss) for any period reported.

Recently Issued Accounting Standards

~~Revenue from Contracts with Customers, ASU 2014-09~~

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

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

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

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

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

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

~~In August 2016, the FASB issued ASU 2016-15,~~ ~~Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force).~~ 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. 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.

We currently expect to adopt this standard on January 1, ~~2019.~~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 financial position, results of operations and cash flows as well as monitor ~~emerging guidance on such topics as easements and right of ways, pipeline laterals, purchase power agreements, and other industry-related areas.~~utility industry implementation guidance. We ~~have begun~~continue the process of identifying and categorizing our lease contracts and evaluating our current business ~~processes.~~processes relating to leases. We have selected and initiated implementation of a new lease software solution.

Recently Adopted Accounting Standards

Revenue from Contracts with Customers, ASU 2014-09

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

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

Effective January 1, 2018, we adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The standard requires employers to report the service cost component in the same line item(s) as other compensation costs, and 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 our rate-regulated entities, we capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC-to-GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs resulted in offsetting changes to Operating income and Other income. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows.

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

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

(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
Wholesale	9,050
Market - off-system sales	2,275
Transmission/Other	11,718
Revenue from contracts with customers	73,684
Other revenues	131
Total revenues	$	73,815

Timing of revenue recognition:
Services transferred at a point in time	—
Services transferred over time	73,684
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:


	September 30, 2017			December 31, 2016			March 31, 2018			December 31, 2017
Accounts receivable trade	$	17,356		$	16,972		$	16,992		$	15,994
Unbilled revenues	10,348			13,799			12,772			13,280
Allowance for doubtful accounts	(125		)	(157		)	(262		)	(224		)
Receivables - customers, net	$	27,579		$	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:


	Maximum Amortization (in years)	September 30, 2017		December 31, 2016		Maximum Amortization (in years)	March 31, 2018		December 31, 2017
Regulatory assets:
Unamortized loss on reacquired debt ^(a)	8	$	1,604	$	1,815	7	$	1,464	$	1,534
Deferred taxes on AFUDC ^(b)	45	10,192		9,367		45	5,050		5,095
Employee benefit plans^(c)	12	20,180		20,100		12	19,723		19,465
Deferred energy and fuel cost adjustments - current^(a)	1	13,754		18,119		1	17,912		19,602
Deferred gas cost adjustments ^{(a) (e)}	1	5,324		4,897
Deferred taxes on flow through accounting ^(a)	35	14,906		12,545
Decommissioning costs, net of amortization^(d)	6	10,766		12,456
Other regulatory assets ^(a) ^(d)	6	15,271		12,835
Deferred taxes on flow through accounting						54	7,929		7,579
Decommissioning costs, net of amortization						6	9,738		10,252
Vegetation management, net of amortization						6	12,093		12,669
Other regulatory assets ^(a)						6	2,303		2,507
Total regulatory assets		$	91,997	$	92,134		$	76,212	$	78,703


Regulatory liabilities:
Cost of removal for utility plant ^(a)	61	$	43,518	$	41,541	61	$	49,580	$	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	3,121		—
Other regulatory liabilities	13	825		105		13	1,033		890
Total regulatory liabilities		$	56,647	$	53,950		$	157,603	$	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.

(d)

~~In accordance with a settlement agreement approved by the SDPUC on June 16, 2017,~~As of March 31, 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 are being amortized over 6 years, effective July 1, 2017. Decommissioning costs and Winter Storm Atlas costs were previously amortized over a 10 year period ending September 30, 2024. The vegetation management costs were previously unamortized. The change in amortization periods for these costs will increase annual amortization expensesubject to approval by ~~approximately $2.7 million.~~our regulators.

~~(e)~~

Our deferred energy, fuel cost, and gas cost adjustments represent the cost of electricity and gas delivered to our electric utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. We file periodic quarterly, semi-annual, and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions.

Regulatory Matters

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:


	September 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017
Receivables - affiliates	$	5,498	$	9,526	$	6,925	$	5,664
Accounts payable - affiliates	$	26,828	$	31,799	$	24,767	$	25,653

Money Pool Notes Receivable and Notes Payable

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

We ~~will continue to~~ participate in the Utility Money Pool Agreement (the Agreement). Under the Agreement, we may borrow from the pool; however the Agreement restricts the pool from loaning funds to BHC or to any of BHC’s non-utility subsidiaries. The Agreement does not restrict us from paying dividends to BHC. Borrowings under the Agreement bear interest at the weighted average daily cost of our parent company’s external borrowings as defined under the Agreement, or if there are no external funds outstanding on that date, then the rate will be the daily one-month LIBOR plus 1.0%. At ~~September 30, 2017~~March 31, 2018, the average cost of borrowing under the Utility Money Pool was ~~1.66%~~2.54%.

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

September 30, 2017 December 31, 2016
Money pool notes receivable, net $ 8,881
$ 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 September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Net interest income (expense) $ 53
$ 277
$ 269
$ 845

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


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2017		2016		2017		2016		2018		2017
Revenue:
Energy sold to Cheyenne Light	$	361	$	599	$	1,866	$	1,908	$	703	$	878
Rent from electric properties	$	935	$	1,229	$	2,805	$	3,817	$	3,678	$	1,272

Fuel and purchased power:
Purchases of coal from WRDC	$	4,054	$	4,122	$	11,386	$	12,275	$	4,067	$	4,280
Purchase of excess energy from Cheyenne Light	$	208	$	64	$	324	$	172	$	86	$	40
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	199	$	312	$	1,174	$	1,329	$	641	$	606
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	351	$	547	$	2,007	$	2,276	$	1,093	$	1,019

Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	99	$	100	$	297	$	300	$	96	$	99

Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	6,626	$	6,257	$	20,346	$	19,155	$	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.


(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 September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2017			2016			2017			2016			2018			2017
Service cost	$	137		$	151		$	409		$	453		$	129		$	136
Interest cost	585			625			1,755			1,875			548			585
Expected return on plan assets	(898		)	(908		)	(2,692		)	(2,724		)	(886		)	(897		)
Prior service cost	10			11			32			33			11			11
Net loss (gain)	308			498			922			1,496			516			307
Net periodic benefit cost	$	142		$	377		$	426		$	1,133		$	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 September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2017			2016			2017			2016			2018			2017
Service cost	$	52		$	51		$	155		$	153		$	48		$	52
Interest cost	44			47			132			141			45			44
Prior service cost (benefit)	(84		)	(84		)	(252		)	(252		)	(84		)	(84		)
Net periodic benefit cost	$	12		$	14		$	35		$	42		$	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 September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2017		2016		2017		2016		2018		2017
Interest cost	$	29	$	30	$	87	$	90	$	27	$	29
Net loss (gain)	22		20		65		62		26		22
Net periodic benefit cost	$	51	$	50	$	152	$	152	$	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 account. ~~On July 24, 2017, we made contributions~~Contributions to the Defined Benefit Pension Plan in the amount of approximately $1.8 million. On September 15, 2017, we made an additional contribution of approximately $2.2 million to reduce Pension Benefit Guaranty Corporation premiums and offset the forecasted increase in pension expense due to low bond yields which impact the pension discount rate. Contributions to thePostretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made for ~~2017~~2018 and anticipated contributions for ~~2017~~2018 and ~~2018~~2019 are as follows (in thousands):


	Contributions Nine Months Ended September 30, 2017		Remaining Anticipated Contributions for 2017		Anticipated Contributions for 2018		Contributions Three Months Ended March 31, 2018		Remaining Anticipated Contributions for 2018		Anticipated Contributions for 2019
Defined Benefit Pension Plan	$	4,000	$	—	$	1,834	$	—	$	1,795	$	1,789
Defined Benefit Postretirement Healthcare Plan	$	406	$	135	$	565	$	134	$	401	$	554
Supplemental Non-qualified Defined Benefit Plans	$	185	$	62	$	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 ~~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:


	September 30, 2017				December 31, 2016				March 31, 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)	$	1,171	$	1,171	$	234	$	234	$	12	$	12	$	16	$	16
Long-term debt, including current maturities ^{(b) (c)}	$	339,860	$	439,973	$	339,756	$	410,466	$	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 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


Nine months ended September 30,	2017			2016
Three months ended March 31,							2018			2017
	(in thousands)						(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	10,242		$	5,565		$	7,556		$	10,998
Non-cash (decrease) to money pool notes receivable, net	$	(32,000	)	$	(36,500	)	$	(16,000	)	$	(7,000	)
Non-cash dividend to Parent	$	32,000		$	36,500		$	16,000		$	7,000

Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(12,838	)	$	(13,486	)	$	(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 ~~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 June 16, 2017, South Dakota Electric received approval from~~During the ~~SDPUC on~~first quarter of 2018, we commenced construction of a settlement reached with the SDPUC staff agreeing to a six-year moratorium period effective July 1, 2017. As part of this agreement, South Dakota Electric will not increase base rates, absent an extraordinary event. The moratorium period also includes a suspension of both the Transmission Facility Adjustment and the Environmental Improvement Adjustment, and a $1.0$70 million, increase to the annual power marketing margin guarantee during this period. Additionally, existing regulatory asset balances of approximately $13 million related to decommissioning and Winter Storm Atlas will be amortized over the moratorium period. These balances were previously amortized over a 10-year period ending September 30, 2024. The vegetation management regulatory asset of $14 million, previously unamortized, will also be amortized over the moratorium period. The change in amortization periods for these costs will increase annual amortization expense by approximately $2.7 million.

~~The June 16, 2017 settlement had no impact to base rates. The following table illustrates information about certain enacted regulatory provisions with respect to South Dakota Electric:~~

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~~230-kV, 175 mile-long transmission line ~~connecting the Teckla Substation in northeast Wyoming to the Lange Substation near~~that connects 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~~expected to ~~Osage, WY was~~be placed in service ~~on August 31, 2016. The~~in 2018 and the second segment ~~connecting Osage~~expected to ~~Lange was placed~~be serving customers in ~~service on May 30, 2017.~~

~~Tax Matters - Potential Corporate Tax Reform~~

President Trump and Congressional Republicans have stated that one of their top priorities is enactment of comprehensive tax reform. On November 2, 2017, the House Ways and Means Committee released its tax reform bill. Significant uncertainty exists as to the ultimate legislation that will be enacted into law. We are evaluating the proposed legislation; any impact on our future results of operations, financial position and cash flows as a result of the potential changes cannot yet be determined and such changes could be material.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 September 30,									Nine Months Ended September 30,									Three Months Ended March 31,
	2017			2016			Variance			2017			2016			Variance			2018			2017			Variance
	(in thousands)																		(in thousands)
Revenue	$	73,938		$	66,728		$	7,210		$	213,785		$	197,389		$	16,396		$	73,815		$	73,794		$	21
Fuel and purchased power	22,843			18,421			4,422			64,604			55,375			9,229			22,440			23,149			(709		)
Gross margin	51,095			48,307			2,788			149,181			142,014			7,167			51,375			50,645			730

Operating expenses	27,397			25,897			1,500			84,395			79,888			4,507			31,011			27,269			3,742
Operating income	23,698			22,410			1,288			64,786			62,126			2,660			20,364			23,376			(3,012		)

Interest income (expense), net	(4,779		)	(4,625		)	(154		)	(15,216		)	(14,478		)	(738		)	(5,424		)	(5,437		)	13
Other income (expense), net	679			654			25			1,745			1,670			75			(117		)	418			(535		)
Income tax expense	(5,772		)	(6,429		)	657			(15,632		)	(16,316		)	684			(3,063		)	(5,787		)	2,724
Net income	$	13,826		$	12,010		$	1,816		$	35,683		$	33,002		$	2,681		$	11,760		$	12,570		$	(810	)

Three Months Ended ~~September 30, 2017~~March 31, 2018 Compared to Three Months Ended ~~September 30, 2016.~~March 31, 2017. Net income was ~~$14~~$12 million compared to ~~$12~~$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 related to Horizon Point rent income, a ~~$2.8~~$1.1 million increase in residential margins primarily from colder weather in the current year, and higher rider revenues of $0.8 million primarily related to transmission investment recovery. ~~Higher cooling degree days~~These increases were partially offset by a $3.1 million reserve to revenue to reflect the reduction of the lower ~~usage per customer~~federal income tax rate from the TCJA on our existing rate tariffs and $0.3 million lower commercial and industrial demand. ~~Cooling degree days were 11%~~

Operating expenses increased primarily due to $2.8 million of higher ~~than normal in~~vegetation management expenses. Higher employee costs, property taxes and outage related expenses comprise the ~~current year~~remainder of the increase compared to ~~18% lower than normal for~~ the same period in the prior year.

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

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

~~Income tax expense:~~Other income (expense), net ~~The effective tax rate was lower than the prior year, primarily~~decreased due to higher ~~flow-through benefits in the current year.~~

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

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

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


	Electric Revenue by Customer Type										Electric Revenue by Customer Type
	Three Months Ended September 30,					Nine Months Ended September 30,					Three Months Ended March 31,
	(in thousands)										(in thousands)
	2017		Percentage Change	2016		2017		Percentage Change	2016		2018		Percentage Change	2017
Residential	$	18,020	3%	$	17,501	$	53,724	1%	$	53,057	$	21,061	5%	$	20,071
Commercial	25,459		(1)%	25,714		72,608		(1)%	73,026		23,544		(3)%	24,291
Industrial	8,149		(2)%	8,275		24,774		1%	24,540		8,276		(2)%	8,454
Municipal	1,071		2%	1,053		2,849		—%	2,844		811		(3)%	836
Total retail revenue	52,699		—%	52,543		153,955		—%	153,467		53,692		—%	53,652
Contract wholesale ^(a)	8,048		75%	4,596		22,593		78%	12,717
Wholesale off-system ^(b)	4,787		20%	3,984		11,044		(2)%	11,304
Wholesale ^(a)											9,050		15%	7,843
Market - off-system sales ^(b)											2,275		(41)%	3,833
Other revenue ^(c)	8,404		50%	5,605		26,193		32%	19,901		8,798		4%	8,466
Total revenue	$	73,938	11%	$	66,728	$	213,785	8%	$	197,389	$	73,815	—%	$	73,794

____________________


(a)	Increase for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2018 was primarily ~~due to a new 50 MW power sales agreement effective January 1, 2017.~~driven by colder weather.


(b)	~~Increase~~Decrease for three months ended ~~September 30, 2017~~March 31, 2018 was due to softer market conditions driven by ~~higher commodity~~natural gas prices ~~on similar MWh quantities sold. For~~and excess energy in the ~~nine months ended September 30, 2017 higher commodity prices primarily offset lower MWh quantities sold.~~market.


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


	Megawatt Hours Sold by Customer Type						Megawatt Hours Sold by Customer Type
	Three Months Ended September 30,			Nine Months Ended September 30,			Three Months Ended March 31,
	2017	Percentage Change	2016	2017	Percentage Change	2016	2018	Percentage Change	2017
Residential	129,616	5%	124,012	386,709	1%	381,616	163,113	9%	149,572
Commercial	212,773	—%	213,276	582,899	(2)%	592,371	194,931	(1)%	196,406
Industrial	109,745	—%	110,220	323,038	1%	320,861	104,302	(5)%	109,796
Municipal	10,156	2%	9,927	25,865	—%	25,855	7,503	(1)%	7,605
Total retail quantity sold	462,290	1%	457,435	1,318,511	—%	1,320,703	469,849	1%	463,379
Contract wholesale ^(a)	185,723	197%	62,547	537,720	195%	182,087
Wholesale off-system ^(b)	130,825	2%	128,415	388,287	(12)%	438,852
Wholesale ^(a)							237,704	28%	186,116
Market - off-system sales ^(b)							92,102	(40)%	154,496
Total quantity sold	778,838	20%	648,397	2,244,518	16%	1,941,642	799,655	(1)%	803,991
Losses and company use ^(c)	56,447	36%	41,585	155,477	40%	111,437	28,522	(32)%	41,841
Total energy	835,285	21%	689,982	2,399,995	17%	2,053,079	828,177	(2)%	845,832

____________________


(a)	Increase for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2018 was primarily ~~due to a new 50 MW power sales agreement effective January 1, 2017.~~driven by colder weather.


(b)	Decrease ~~in 2017~~for three months ended March 31, 2018 was ~~primarily~~due to softer market conditions driven by ~~commodity~~lower 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 Purchased						Megawatt Hours Generated and Purchased
	Three Months Ended September 30,			Nine Months Ended September 30,			Three Months Ended March 31,
Generated -	2017	Percentage Change	2016	2017	Percentage Change	2016	2018	Percentage Change	2017
Coal-fired	423,766	6%	401,231	1,101,291	4%	1,054,264	399,087	3%	387,985
Natural Gas and Oil ^(a)	54,466	31%	41,654	75,840	(22)%	96,649	13,107	27%	10,350
Total generated	478,232	8%	442,885	1,177,131	2%	1,150,913	412,194	3%	398,335

Total purchased ^(b)	357,053	44%	247,097	1,222,864	36%	902,166	415,983	(7)%	447,497
Total generated and purchased ^(b)	835,285	21%	689,982	2,399,995	17%	2,053,079	828,177	(2)%	845,832

____________________


(a)	~~Variances~~Increase for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2018 compared to the same periods in the prior year are driven primarily by ~~the ability~~lower natural gas prices compared to ~~purchase excess generation in the open market at a lower or higher cost than to generate.~~


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


	Power Plant Availability								Power Plant Availability
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2017		2016		2017		2016		2018		2017
Coal-fired plants ^(a)	97.5	%	92.8	%	84.8	%	83.2	%	92.9	%	89.2	%
Other plants	93.7	%	97.7	%	97.0	%	98.4	%	99.4	%	99.4	%
Total availability	95.5	%	95.6	%	91.3	%	91.8	%	96.3	%	94.6	%

____________________


(a)	Both years included outages. ~~2017~~2018 included planned outages at Neil Simpson II, Wyodak and Wygen II, and ~~2016~~2017 included a planned outage at Wygen III and an extended planned outage at Wyodak.


	Degree Days						Degree Days						Degree Days
	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2017			2016			2017			2016			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

Heating degree days	202	(10	)%	161	(23	)%	4,242	(5	)%	3,844	(13	)%	3,699	15	%	3,130	(3	)%
Cooling degree days	595	11	%	460	(18	)%	709	12	%	646	(3	)%	—	—	%	—	—	%

Credit Ratings

Credit ratings impact our ability to obtain short and long-term financing, the cost of such financing, and vendor payment terms, including collateral requirements. The following table represents our secured credit rating from each agency’s review which was in effect at ~~September 30, 2017:~~March 31, 2018:



Rating Agency	Secured Rating
S&P	A-
Moody’s	A1
Fitch	A

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 ~~September 30, 2017.~~March 31, 2018. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective as of ~~September 30, 2017.~~March 31, 2018.

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

Changes in Internal Control over Financial Reporting

During the quarter ended ~~September 30, 2017,~~March 31, 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)).

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: ~~November 3, 2017~~May 4, 2018

2123



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%

Three Months Ended March 31,

Net interest income (expense)