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~~September 30, 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
7001 Mount Rushmore Road
Rapid City, South Dakota 57702
Registrant’s telephone number (605) 721-1700
Former name, former address, and former fiscal year if changed since last report
NONE

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



Yes x	No o

Indicate by check mark whether the Registrant has submitted electronically 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~~October 31, 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 Comprehensive Income - unaudited	4
	Three and Six Months Ended June 30, 2018 and 2017
	Three and Nine Months Ended September 30, 2018 and 2017
	Condensed Balance Sheets - unaudited	5
	June 30, 2018 and December 31, 2017
	September 30, 2018 and December 31, 2017
	Condensed Statements of Cash Flows - unaudited	7
	Six Months Ended June 30, 2018 and 2017
	Nine Months Ended September 30, 2018 and 2017
	Notes to Condensed Financial Statements - unaudited	8
Item 2.	Managements’ Discussion and Analysis of Financial Condition and Results of Operations	1718
Item 4.	Controls and Procedures	2122
PART II.	OTHER INFORMATION	2223
Item 1.	Legal Proceedings	2223
Item 1A.	Risk Factors	2223
Item 6.	Exhibits	2223
	Signatures	2324

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)
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.
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
Happy Jack	Happy Jack Wind Farms, LLC, a subsidiary of Duke Energy Generation Services
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.
TCJA	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 COMPREHENSIVE INCOME

	Three Months Ended June 30,						Six Months Ended June 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
(unaudited)	2018			2017			2018			2017
	(in thousands)
Revenue	$	7078,~~676~~067		$	6673,~~053~~938		$	~~144~~222,~~491~~558		$	~~139~~213,~~847~~785
Operating expenses:
Fuel and purchased power	2025,~~753~~207			1822,~~612~~843			4368,~~193~~400			4164,~~761~~604
Operations and maintenance	1819,~~428~~851			1816,~~888~~747			3757,~~579~~430			3552,~~842~~589
Depreciation and amortization	9,~~866~~950			89,~~831~~053			1929,~~750~~700			1726,~~525~~578
Taxes - property	21,~~134~~631			21,~~010~~597			45,~~110~~741			35,~~631~~228
Total operating expenses	5156,~~181~~639			4850,~~341~~240			~~104~~161,~~632~~271			98148,~~759~~999
Operating income	1921,~~495~~428			1723,~~712~~698			3961,~~859~~287			4164,~~088~~786
Other income (expense):
Interest expense	(5,654		)	(5,635		)	(11,241		)	(11,390		)
Interest charges -
AFUDC - borrowed	152			392			200			584
Interest expense incurred (including amortization of debt issuance costs, premiums, and discounts)	(5,632		)	(5,483		)	(16,873		)	(16,873		)
Interest income	123			243			238			369
Allowance for funds used during construction - borrowed	199			369			399			953
AFUDC - equity	137			717			171			1,188
Interest income	250			335			488			704
Other income (expense), net	(379		)	(69		)	(530		)	(122		)
Allowance for funds used during construction - equity	68			676			239			1,864
Total other income (expense)	(5,621		)	(4,352		)	(11,162		)	(9,371		)
Other income (expense), net	(315		)	3			(845		)	(119		)
Income before income taxes	13,874			13,360			28,697			31,717
Total other income (expense), net	(5,430		)	(4,100		)	(16,592		)	(13,471		)
Income tax expense	(2,749		)	(4,073		)	(5,812		)	(9,860		)
Income before income taxes	15,998			19,598			44,695			51,315
Net income	11,125			9,287			22,885			21,857
Income tax expense	(2,681		)	(5,772		)	(8,493		)	(15,632		)
Other comprehensive income (loss):
Net income	13,317			13,826			36,202			35,683
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
Other comprehensive income (loss), net of tax:
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
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, 2018 and 2017, and $(17) and $(17) for the nine months ended September 30, 2018 and 2017, respectively)	10			10			31			31
Other comprehensive income	28			25			55			49
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(9) and $(8) for the three months ended September 30, 2018 and 2017, and $(27) and $(23) for the nine months ended September 30, 2018 and 2017, respectively)	17			14			51			42
Comprehensive income	$	11,153		$	9,312		$	22,940		$	21,906
Other comprehensive income (loss), net of tax	27			24			82			73
Comprehensive income	$	13,344		$	13,850		$	36,284		$	35,756

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~~September 30, 2018			December 31, 2017
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	513		$	16
Receivables - customers, net	29,556			29,050
Accounts receivable, net	28,192			29,050
Receivables - affiliates	5,426			5,664
Accounts receivable from affiliates	6,373			5,664
Other receivables, net	1,536			196
Materials, supplies and fuel	24,503			23,443
Materials, supplies and fuel	24,165			23,443
Regulatory assets, current	16,939			18,993
Regulatory assets, current	18,290			18,993
Other current assets	3,211			4,724
Other current assets	3,462			4,528
Total current assets	79,231			81,890
Total current assets	82,440			81,890
Investments	5,006			4,926
Investments	4,991			4,926
Property, plant and equipment	1,351,996			1,311,819
Property, plant and equipment	1,331,257			1,311,819
Less: accumulated depreciation and amortization	(370,978		)	(358,946		)
Less accumulated depreciation and amortization	(365,103		)	(358,946		)
Total property, plant and equipment, net	981,018			952,873
Total property, plant and equipment, net	966,154			952,873
Other assets:
Regulatory assets, non-current	5556,~~791~~728			59,710
Other non-current assets	8,972			3,747
Other assets, non-current	9,665			3,747
Total other assets	64,763			63,457
Total other assets, non-current	66,393			63,457
TOTAL ASSETS	$	1,~~118~~131,~~348~~648		$	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, 2018			December 31, 2017
	(in thousands, except common stock par value and share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	14,239		$	14,766
Accounts payable - affiliates	25,185			25,653
Accrued liabilities	44,791			38,205
Money pool notes payable	14,949			13,397
Regulatory liabilities, current	5,756			842
Total current liabilities	104,920			92,863
Long-term debt	339,965			339,895
Deferred credits and other liabilities:
Deferred income tax liabilities, net	109,783			110,618
Regulatory liabilities, non-current	154,175			148,013
Benefit plan liabilities	16,785			16,285
Other, non-current liabilities	1,547			1,240
Total deferred credits and other liabilities	282,290			276,156
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
Additional paid-in capital	39,575			39,575
Retained earnings	329,385			332,499
Accumulated other comprehensive loss	(1,203		)	(1,258		)
Total stockholder’s equity	391,173			394,232
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	1,118,348		$	1,103,146

(Continued)



	As of
(unaudited)	September 30, 2018			December 31, 2017
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	20,388		$	14,766
Accounts payable to affiliates	22,939			25,653
Accrued liabilities	43,931			38,205
Money pool notes payable	13,888			13,397
Regulatory liabilities, current	8,216			842
Total current liabilities	109,362			92,863

Long-term debt	340,000			339,895

Deferred credits and other liabilities:
Deferred income tax liabilities, net	113,247			110,618
Regulatory liabilities, non-current	158,063			148,013
Benefit plan liabilities	15,207			16,285
Other deferred credits and other liabilities	1,251			1,240
Total deferred credits and other liabilities	287,768			276,156

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
Additional paid-in capital	39,575			39,575
Retained earnings	332,703			332,499
Accumulated other comprehensive loss	(1,176		)	(1,258		)
Total stockholder’s equity	394,518			394,232

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	1,131,648		$	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~~Nine Months Ended ~~June~~September 30,
	2018			2017
	(in thousands)
Operating activities:
Net income	$	2236,~~885~~202		$	2135,~~857~~683
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization	1929,~~750~~700			1726,~~525~~578
Deferred income tax	(14,~~407~~619		)	16,~~605~~188
Employee benefits	~~760~~1,139			~~408~~613
AFUDC	(~~171~~239		)	(12,~~188~~817		)
Other adjustments, net	12,~~262~~362			~~408~~2,298
Change in operating assets and liabilities -
Accounts receivable and other current assets	~~(1,494~~224		)	76,~~188~~567
Accounts payable and other current liabilities	2,~~170~~337			(3,~~486~~077		)
Regulatory assets - current	2,~~797~~004			~~(315~~1,543		)
Regulatory liabilities - current	58,~~709~~224			~~741~~—
Other operating activities, net	(458		)	380
Contributions to defined benefit pension plan	(1,795		)	(4,000		)
Net cash provided by (used in) operating activities	51,803			45,123
Other operating activities, net	(1,400		)	(1,097		)
Net cash provided by (used in) operating activities	83,377			74,633
Investing activities:
Property, plant and equipment additions	(2747,~~399~~527		)	(4461,~~142~~537		)
Proceeds from sale of assets	4,994			—
Change in money pool notes receivable, net	—			(6212,472		)
Other investing activities	(45,~~961~~338		)	3313
Net cash provided by (used in) investing activities	(2747,~~366~~871		)	(4473,~~201~~696		)
Financing activities:
Change in money pool notes payable, net	(2435,~~448~~509		)	—
Net cash provided by (used in) financing activities	(2435,~~448~~509		)	—
Net change in cash and cash equivalents	(113		)	~~922~~937
Cash and cash equivalents, beginning of period	16			234
Cash and cash equivalents, end of period	$	513		$	1,~~156~~171

See Note 8 for supplemental cash flow information.

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

BLACK HILLS POWER, INC.

Notes to Condensed Financial Statements

(unaudited)

(Reference is made to Notes to Financial Statements

included in our 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 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~~September 30, 2018, December 31, 2017 and ~~June~~September 30, 2017 financial information and are of a normal recurring nature. The results of operations for the three months ended ~~June~~September 30, 2018 and ~~June~~September 30, 2017, and our financial condition as of ~~June~~September 30, 2018 and December 31, 2017 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

Recently Issued Accounting Standards

Leases, ASU 2016-02

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

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

Recently Adopted Accounting Standards

Revenue from Contracts with Customers, ASU 2014-09

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

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

Effective January 1, 2018, we adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The standard requires employers to report the service cost component in the same line item(s) as other compensation costs, and ~~require~~requires the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets was applied on a prospective basis for the ~~six~~nine months ended ~~June~~September 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 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 June 30, 2018		Six Months Ended June 30, 2018
	Three Months Ended September 30, 2018		Nine Months Ended September 30, 2018
	(in thousands)
Customer types:
Retail	$	4649,~~525~~874	$	97147,~~166~~040
Wholesale	8,~~191~~255		1725,~~241~~496
Market - off-system sales	37,~~449~~625		513,~~724~~349
Transmission/Other	12,~~372~~183		2436,~~090~~273
Revenue from contracts with customers	7077,~~537~~937		~~144~~222,~~221~~158
Other revenues	~~139~~130		~~270~~400
Total revenues	$	7078,~~676~~067	$	~~144~~222,~~491~~558
Timing of revenue recognition:
Services transferred over time	~~70,537~~$	77,937	~~144,221~~$	222,158
Revenue from contracts with customers	$	7077,~~537~~937	$	~~144~~222,~~221~~158

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 $2.65 million and $58.72 million during the three and ~~six~~nine months ended ~~June~~September 30, 2018.

On ~~June~~September 294, 2018, wethe ~~filed~~SDPUC ~~our~~approved ~~proposed~~a ~~TCJA~~settlement agreement ~~with~~for ~~the~~South ~~SDPUC~~Dakota ~~with~~Electric ~~expected~~allowing ~~final~~the ~~approval~~company byto pass on the ~~end~~benefits of a lower corporate federal income tax rate to our South Dakota retail customers. The aggregate 2018 benefit of approximately $7.7 million will be delivered to customers in October 2018. For 2019, the settlement agreement provides an estimated $8.9 million aggregate reduction in base rates for customers.

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 Business Description 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.


(3)	ACCOUNTS RECEIVABLE

Following is a summary of ~~Receivables~~Accounts ~~- customers~~receivable, net included in the accompanying Condensed Balance Sheets (in thousands) as of:

	June 30, 2018			December 31, 2017
	September 30, 2018			December 31, 2017
Accounts receivable trade	$	17,~~471~~019		$	15,994
Unbilled revenues	1211,~~270~~275			13,280
Allowance for doubtful accounts	(~~185~~102		)	(224		)
Receivables - customers, net	$	29,556		$	29,050
Accounts receivable, net	$	28,192		$	29,050


(4)	REGULATORY ACCOUNTING

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

Our regulatory assets and liabilities were as follows (in thousands) as of:

	Maximum Amortization(in years)	June 30, 2018			December 31, 2017
	September 30, 2018			December 31, 2017
Regulatory assets:
Unamortized loss on reacquired debt (a)	7$	$1,326	~~1,393~~	$	$1,534	~~1,534~~
Deferred taxes on AFUDC (b)	455,010	~~5,038~~		5,095	~~5,095~~
Employee benefit plans(c)	1219,619	~~19,665~~		19,465	~~19,465~~
Deferred energy and fuel cost adjustments (a)	117,697	~~16,923~~		19,602	~~19,602~~
Deferred taxes on flow through accounting	548,302	~~8,137~~		7,579	~~7,579~~
Decommissioning costs, net of amortization	58,710	~~9,224~~		10,252	~~10,252~~
Vegetation management, net of amortization	510,942	~~11,518~~		12,669	~~12,669~~
Other regulatory assets (a)	52,061	~~2,183~~		2,507	~~2,507~~
Total regulatory assets	$	$73,667	~~74,081~~	$	$78,703	~~78,703~~
Less current regulatory assets	(16,939		)	(18,993		)
Regulatory assets, non-current	$	56,728		$	59,710

Regulatory liabilities:
Cost of removal for utility plant (a)	61$	$51,106	~~50,040~~	$	$44,056	~~44,056~~
Employee benefit plan costs and related deferred taxes (c)	126,808	~~6,808~~		6,808	~~6,808~~
Excess deferred income taxes	4099,774	~~97,061~~		97,101	~~97,101~~
TCJA revenue reserve (d)	subject to approval	5,709			—
TCJA revenue reserve	8,188			—
Other regulatory liabilities	13403	~~313~~		890	~~890~~
Total regulatory liabilities	$	$166,279	~~159,931~~	$	$148,855	~~148,855~~
Less current regulatory liabilities	(8,216		)	(842		)
Regulatory liabilities, non-current	$	158,063		$	148,013

____________________


(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)~~ ~~As of June 30, 2018, the amortization period is yet to be determined and subject to approval by our regulators.~~12

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 Power 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.

We 12estimated and recorded a reserve to revenue of approximately $2.5 million and $8.2 million during the three and nine months ended September 30, 2018.


(5)	RELATED-PARTY TRANSACTIONS

Non-Cash Dividend to Parent

We recorded non-cash dividends to our Parent of $2636 million and $1632 million for ~~six~~nine months ended ~~June~~September 30, 2018 and ~~June~~September 30, 2017, respectively, and changed the utility Money pool note by $2636 million and $1632 million for the ~~six~~nine months ended ~~June~~September 30, 2018 and ~~June~~September 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, 2018		December 31, 2017
	September 30, 2018		December 31, 2017
Receivables - affiliates	$	5,426	$	5,664
Accounts receivables from affiliates	$	6,373	$	5,664
Accounts payable - affiliates	$	25,185	$	25,653
Accounts payable to affiliates	$	22,939	$	25,653

Money Pool Notes Receivable and Notes Payable

We 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 ~~June~~September 30, 2018, the average cost of borrowing under the Utility Money Pool was 2.4960%.

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

	June 30, 2018		December 31, 2017
	September 30, 2018		December 31, 2017
Money pool notes payable	$	1413,~~949~~888	$	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,
	Three Months Ended September 30,					Nine Months Ended September 30,
	2018			2017		2018			2017
Net interest income (expense)	$	(9675	)	$	9053	$	(~~132~~207	)	$	~~216~~269

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

	Three Months Ended June 30,				Six Months Ended June 30,
	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Revenue:
Energy sold to Cheyenne Light	$	~~501~~311	$	~~625~~361	$	1,~~204~~515	$	1,~~505~~866
Rent from electric properties (a)	$	3,691	$	935	$	7,369	$	1,870
Rent from electric properties	$	908	$	935	$	3,025	$	2,805
Horizon Point shared facility revenues	$	2,826	$	—	$	8,078	$	—
Fuel and purchased power:
Purchases of coal from WRDC	$	4,~~249~~161	$	34,~~052~~054	$	812,~~316~~477	$	711,~~332~~386
Purchase of excess energy from Cheyenne Light	$	82193	$	76208	$	~~168~~361	$	~~116~~324
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	~~381~~262	$	~~369~~199	$	1,~~022~~284	$	~~975~~1,174
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	~~696~~582	$	~~637~~351	$	12,~~789~~371	$	12,~~656~~007
Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	96	$	99	$	~~192~~288	$	~~198~~297
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	7,604	$	7,109	$	15,210	$	13,720
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings (a)	$	9,836	$	6,626	$	25,046	$	20,346

____________________

(a) The increase for the three and ~~six~~nine months ended ~~June~~September 30, 2018 is driven by Horizon Point shared facility ~~revenues.~~expenses, ~~See~~higher ~~Horizon~~allocation ~~Point~~of ~~agreement~~employee ~~information~~costs ~~below~~and interest expense.

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.


(6)	EMPLOYEE BENEFIT PLANS

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

	Three Months Ended June 30,						Six Months Ended June 30,
	Three Months Ended September 30,							Nine Months Ended September 30,
	2018			2017			~~2018~~	2018			~~2017~~	2017
Service cost	$	129		$	~~136~~137		$	~~258~~$	387		$	~~272~~$	409
Interest cost	~~549~~548			585			~~1,097~~	1,645			~~1,170~~	1,755
Expected return on plan assets	(887		)	(~~897~~898		)	~~(1,773~~	(2,660	)	)	~~(1,794~~	(2,692	)	)
Prior service cost	11			1110			22	33			22	32
Net loss (gain)	516			~~307~~308			~~1,032~~	1,548			~~614~~	922
Net periodic benefit cost	$	~~318~~317		$	142		$	~~636~~$	953		$	~~284~~$	426

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 September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Service cost	$	4948		$	5152		$	97145		$	~~103~~155
Interest cost	4445			44			89134			88132
Prior service cost (benefit)	(84		)	(84		)	(~~168~~252		)	(~~168~~252		)
Net periodic benefit cost	$	9		$	1112		$	1827		$	2335

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 September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Interest cost	$	27	$	29	$	5481	$	5887
Net loss (gain)	26		2122		5278		4365
Net periodic benefit cost	$	53	$	5051	$	~~106~~159	$	~~101~~152

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

	ContributionsSix Months EndedJune 30, 2018		Remaining Anticipated Contributions for 2018		Anticipated Contributions for 2019
	ContributionsNine Months EndedSeptember 30, 2018		Remaining Anticipated Contributions for 2018		Anticipated Contributions for 2019
Defined Benefit Pension Plan	$	—1,795	$	~~1,795~~—	$	1,~~789~~850
Defined Benefit Postretirement Healthcare Plan	$	~~267~~401	$	~~267~~134	$	~~554~~412
Supplemental Non-qualified Defined Benefit Plans	$	~~123~~184	$	~~123~~61	$	~~241~~242


(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 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, 2018				December 31, 2017
	September 30, 2018				December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	513	$	513	$	16	$	16
Long-term debt, including current maturities (b) (c)	$	~~339~~340,~~965~~000	$	~~418~~411,~~410~~948	$	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.


(8)	SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

	Six Months Ended June 30,
	Nine Months Ended September 30,
	2018			2017
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	710,~~477~~540		$	10,~~495~~242
Non-cash (decrease) to money pool notes receivable, net	$	(2636,000	)	$	(1632,000	)
Non-cash dividend to Parent	$	2636,000		$	1632,000
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(1014,~~930~~104	)	$	(1012,~~786~~838	)


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

~~(10)~~Platte ~~INCOME~~River ~~TAXES~~Power Authority PPA

On ~~December~~August 2216, ~~2017~~2018, ~~the~~we ~~U.S.~~entered ~~government~~into ~~enacted~~a ~~comprehensive~~PPA ~~tax~~with ~~legislation~~Platte ~~commonly~~River ~~referred~~Power toAuthority as(PRPA) ~~the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35%~~ to ~~21%. The~~purchase ~~Company~~up 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~~12 ~~TCJA.~~MW ~~The amount~~ of ~~the~~wind ~~settlements~~energy ~~may~~through ~~change based on decisions and actions by the rate regulators, which could have a material impact on the Company~~PRPA’s ~~future~~agreement ~~results~~with ofSilver ~~operations, cash flows or financial position~~Sage. WeThis ~~revalued~~agreement ~~our deferred tax assets and liabilities as of December 31, 2017, which reflected our estimate of the impact of the TCJA. We~~ will ~~continue~~expire toSeptember ~~evaluate subsequent regulations~~30, ~~clarifications and interpretations with the assumptions made, which could materially change our estimate~~2029.


(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, which reflected our provisional estimate of the impact of the TCJA, under SEC Staff Accounting Bulletin No. 118. 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 state regulatory commissions. In addition to current year revenue reserves disclosed in Note 4, we recorded additional changes in estimates of the provisional amounts recorded at December 31, 2017, primarily related to bonus depreciation and other plan and property items, after filing our 2017 tax returns which decreased tax expense by $0.2 million for the three and nine months ended September 30, 2018. We will continue to evaluate subsequent regulations, clarifications and interpretations of the assumptions made, which could change our estimates to the TCJA, which we expect to finalize in the fourth quarter.

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

On September 4, 2018, the SDPUC approved a settlement agreement for South Dakota Electric allowing the company to pass on the benefits of a lower corporate federal income tax rate to our South Dakota retail customers. The aggregate 2018 benefit of approximately $7.7 million will be delivered to customers in October 2018. For 2019, the settlement agreement provides an estimated $8.9 million aggregate reduction in base rates for customers.

On August 16, 2018, we entered into a PPA with Platte River Power Authority (PRPA) to purchase up to 12 MW of wind energy through PRPA’s agreement with Silver Sage. This agreement will expire September 30, 2029.

On August 9, 2018, S&P upgraded South Dakota Electric’s credit rating to A.

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 July 19. 2018, Fitch affirmed South Dakota 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 and amortization from the measure. The presentation of gross margin is intended to supplement investors’ understanding of our operating performance.

Gross margin is calculated as operating revenue less cost of fuel and purchased power. Our gross margin is impacted by the fluctuations in power purchases, natural gas and other fuel supply costs. However, while these fluctuating costs impact gross margin as a percentage of revenue, they only impact total gross margin if the costs cannot be passed through to our customers.

Our gross margin measure may not be comparable to other companies’ gross margin measure. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

The following tables provide certain financial information and operating statistics:

Three Months Ended June 30,

Six Months Ended June 30,

Three Months Ended September 30,

Nine Months Ended September 30,

2018

2017

Variance

2018

2017

Variance

(in thousands)

Revenue

7078,~~676~~067

6673,~~053~~938

4,~~623~~129

~~144~~222,~~491~~558

~~139~~213,~~847~~785

48,~~644~~773

Fuel and purchased power

2025,~~753~~207

1822,~~612~~843

2,~~141~~364

4368,~~193~~400

4164,~~761~~604

13,~~432~~796

Gross margin (a)

4952,~~923~~860

4751,~~441~~095

21,~~482~~765

~~101~~154,~~298~~158

98149,~~086~~181

34,~~212~~977

Operating expenses

3031,~~428~~432

2927,~~729~~397

~~699~~4,035

6192,~~439~~871

5684,~~998~~395

48,~~441~~476

Operating income

1921,~~495~~428

1723,~~712~~698

1(2,~~783~~270

)

3961,~~859~~287

4164,~~088~~786

(13,~~229~~499

)

Interest income (expense), net

(5,~~379~~183

)

(54,~~000~~779

)

(~~379~~404

)

(1015,~~803~~986

)

(1015,~~437~~216

)

(~~366~~770

)

Other income (expense), net

(~~242~~247

)

~~648~~679

(~~890~~926

)

(~~359~~606

)

1,~~066~~745

(12,~~425~~351

)

Income tax expense

(2,~~749~~681

)

(45,~~073~~772

)

13,~~324~~091

(58,~~812~~493

)

(915,~~860~~632

)

47,~~048~~139

Net income

1113,~~125~~317

913,~~287~~826

~~1,838~~(509

)

2236,~~885~~202

2135,~~857~~683

~~1,028~~519

________________


(a)	Non-GAAP measure

Nine 17Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017. Net income was $36 million compared to $36 million for the same period in the prior year primarily due to the following:

~~Three~~Gross ~~Months~~margin ~~Ended~~increased ~~June~~primarily 30due to $8.1 million Horizon Point shared facility revenue, ~~2018~~higher ~~Compared~~power tomarketing ~~Three~~and ~~Months~~wholesale ~~Ended~~revenue ~~June~~of 30$1.9 million, ~~2017~~a $1. ~~Net~~4 ~~income~~million ~~was~~increase in residential margins primarily from higher volume usage per customer, and higher rider revenues of $112.0 million ~~compared~~primarily related to transmission investment recovery. These increases were partially offset by an $98.32 million ~~for~~reserve ~~the~~to ~~same~~revenue ~~period~~to inreflect the ~~prior~~reduction ~~year~~of ~~primarily~~the ~~due~~lower tofederal income tax rate from the ~~following:~~TCJA on our existing rate tariffs and lower commercial and industrial volume of $0.6 million.

~~Gross~~Operating ~~margin~~expenses increased ~~primarily~~ due to ~~higher~~depreciation ~~non-energy revenue of $2.4 million primarily related to Horizon Point shared facility revenue, higher commercial~~ and ~~industrial~~property ~~demand~~taxes increases of $03.96 million, afrom ~~$0.8~~higher ~~million~~asset ~~increase~~base indriven ~~residential~~by ~~margins primarily from warmer weather in~~ the ~~current~~prior year, ~~and~~additions ~~higher rider revenues~~ of ~~$1.0~~Horizon ~~million~~Point ~~primarily~~and ~~related~~the toTeckla-Lange transmission ~~investment recovery~~line. ~~These~~ ~~increases~~Higher ~~were~~vegetation ~~partially~~management ~~offset~~expenses, byhigher aemployee ~~$2.6~~costs, ~~million~~and ~~reserve~~higher tofacility ~~revenue~~costs tocomprise ~~reflect~~ the ~~reduction~~remainder of the ~~lower~~increase ~~federal~~compared ~~income~~to ~~tax rate from~~ the ~~TCJA~~same onperiod ~~our~~in ~~existing~~the ~~rate~~prior ~~tariffs~~year.

~~Operating~~Interest ~~expenses~~expense, net increased ~~primarily~~ due to ~~increased depreciation from~~ higher ~~asset base driven by the~~ prior year ~~additions~~AFUDC ofassociated ~~Horizon~~with ~~Point~~higher ~~and~~prior ~~the~~year ~~Teckla-Lange~~capital ~~transmission line~~spend.

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

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

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

~~Six~~ ~~Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017. Net income was $23 million compared to $22 million for the same period in the prior year primarily due to the following:~~19

Gross margin increased 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 $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.



	Electric Revenue by Customer Type
	Three Months Ended September 30,					Nine Months Ended September 30,
	(in thousands)
	2018		Percentage Change	2017		2018		Percentage Change	2017
Residential	$	17,971	—%	$	18,020	$	55,458	3%	$	53,724
Commercial	25,601		1%	25,459		72,683		—%	72,608
Industrial	7,685		(6)%	8,149		24,131		(3)%	24,774
Municipal	1,005		(6)%	1,071		2,692		(6)%	2,849
Total retail revenue	52,262		(1)%	52,699		154,964		1%	153,955
Wholesale ^(a)	8,255		3%	8,048		25,496		13%	22,593
Market - off-system sales ^(b)	7,625		59%	4,787		13,349		21%	11,044
Other revenue ^(c)	9,925		18%	8,404		28,749		10%	26,193
Total revenue	$	78,067	6%	$	73,938	$	222,558	4%	$	213,785

Operating expenses increased 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, and facility costs comprise the remainder of the increase compared to the same period in the prior year.

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

	Electric Revenue by Customer Type
	Three Months Ended June 30,					Six Months Ended June 30,
	(in thousands)
	2018		Percentage Change	2017		2018		Percentage Change	2017
Residential	$	16,426	5%	$	15,633	$	37,487	5%	$	35,704
Commercial	23,538		3%	22,858		47,082		—%	47,149
Industrial	8,170		—%	8,171		16,446		(1)%	16,625
Municipal	876		(7)%	942		1,687		(5)%	1,778
Total retail revenue	49,010		3%	47,604		102,702		1%	101,256
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	10,026		8%	9,323		18,824		6%	17,789
Total revenue	$	70,676	7%	$	66,053	$	144,491	3%	$	139,847

____________________

(a) Increase for the ~~three~~nine ~~and six~~ months ended ~~June~~September 30, 2018 was primarily driven by increased volumes on long -term wholesale contracts.

(b) Increase for the three and nine months ended ~~June~~September 30, 2018 was due to higher trading volume opportunities.

(c) 18Increase for the three and nine months ended September 30, 2018 was primarily driven by Horizon Point shared facility revenues.

	Megawatt Hours Sold by Customer Type
	Three Months Ended June 30,			Six Months Ended June 30,
	Three Months Ended September 30,			Nine Months Ended September 30,
	2018	Percentage Change	2017	2018	Percentage Change	2017
Residential	~~115~~125,~~905~~159	8(3)%	~~107~~129,~~521~~616	~~279~~404,~~018~~177	95%	~~257~~386,~~093~~709
Commercial	~~186~~204,~~784~~621	8(4)%	~~173~~212,~~720~~773	~~381~~586,~~715~~336	31%	~~370~~582,~~126~~899
Industrial	106,100	3%	103,497	210,402	(1)%	213,293
Industrial (a)	95,473	(13)%	109,745	305,875	(5)%	323,038
Municipal	7,479	(8)%	8,104	14,982	(5)%	15,709
Municipal (b)	9,070	(11)%	10,156	24,052	(7)%	25,865
Total retail quantity sold	~~416~~434,~~268~~323	(6)%	~~392~~462,~~842~~290	~~886~~1,~~117~~320,440	3—%	~~856~~1,~~221~~318,511
Wholesale (a)	218,132	31%	165,881	455,836	29%	351,997
Wholesale (c)	221,327	19%	185,723	677,163	26%	537,720
Market - off-system sales (b)	141,866	38%	102,966	233,968	(9)%	257,462
Market - off-system sales (d)	172,141	32%	130,825	406,109	5%	388,287
Total quantity sold	~~776~~827,~~266~~791	176%	~~661~~778,~~689~~838	12,~~575~~403,~~921~~712	87%	12,~~465~~244,~~680~~518
Losses and company use (c)	61,677	8%	57,189	90,199	(9)%	99,030
Losses and company use (e)	47,171	(16)%	56,447	137,370	(12)%	155,477
Total energy	~~837~~874,~~943~~962	175%	~~718~~835,~~878~~285	12,~~666~~541,~~120~~082	6%	12,~~564~~399,~~710~~995

____________________

(a) Increase for the three ~~and six~~ months ended ~~June~~September 30, 2018 was primarily driven by ~~increased~~lower ~~volumes~~demand onand ~~long-term~~milder ~~wholesale~~summer ~~contracts~~weather.

(b) Increase for three months ended ~~June~~September 30, 2018 was due to ~~improved~~milder ~~pricing~~summer ~~in markets compared to same period in prior year~~weather.

(c) ~~Includes~~Increase ~~company~~for ~~uses,~~the ~~line~~three ~~losses~~and nine months ended September 30, ~~and~~2018 ~~excess~~was ~~exchange~~primarily ~~production~~driven by increased volumes on long-term wholesale contracts.

(d) 19Increase for three months ended September 30, 2018 was due to improved pricing in markets compared to same period in prior year.

	Megawatt Hours Generated and Purchased
	Three Months Ended June 30,			Six Months Ended June 30,
Generated -	2018	Percentage Change	2017	2018	Percentage Change	2017
Coal-fired (a)	388,081	34%	289,540	787,168	16%	677,525
Natural Gas and Oil (b)	23,758	116%	11,024	36,865	72%	21,374
Total generated	411,839	37%	300,564	824,033	18%	698,899
Total purchased	426,104	2%	418,314	842,087	(3)%	865,811
Total generated and purchased	837,943	17%	718,878	1,666,120	6%	1,564,710


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



	Megawatt Hours Generated and Purchased
	Three Months Ended September 30,			Nine Months Ended September 30,
Generated -	2018	Percentage Change	2017	2018	Percentage Change	2017
Coal-fired	407,936	(4)%	423,766	1,195,104	9%	1,101,291
Natural Gas and Oil ^(a)	61,744	13%	54,466	98,609	30%	75,840
Total generated	469,680	(2)%	478,232	1,293,713	10%	1,177,131

Total purchased	405,282	14%	357,053	1,247,369	2%	1,222,864
Total generated and purchased	874,962	5%	835,285	2,541,082	6%	2,399,995

____________________

(a) Increase ~~for~~is ~~the~~primarily ~~three~~due ~~and~~to ~~six~~low ~~months~~natural ~~ended~~gas ~~June~~prices ~~30,~~and ~~2018~~the ~~compared~~ability to ~~same~~generate ~~periods~~at ina ~~prior~~lower ~~year~~cost isthan ~~driven~~to ~~primarily~~purchase byexcess ~~planned~~generation ~~outages~~on atthe ~~Neil~~open ~~Simpson~~market ~~II,~~for ~~Wyodak,~~the three and ~~Wygen~~nine IImonths inended ~~2017~~September 30, 2018.

(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 September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Coal-fired plants ^(a)	93.8	%	97.5	%	92.7	%	84.8	%
Other plants	96.0	%	93.7	%	97.6	%	97.0	%
Total availability	95.0	%	95.5	%	95.3	%	91.3	%

	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)	2017 included planned outages at Neil Simpson II, Wyodak and Wygen II.

	Degree Days						Degree Days
	Three Months Ended June 30,						Six Months Ended June 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
	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
Heating degree days	~~1,037~~236	15	%	~~910~~202	(1110	)%	4,~~736~~972	1211	%	4,~~040~~242	(5	)%
Cooling degree days	~~132~~356	(33	)%	~~114~~595	1511	%	~~132~~488	33(23	)%	~~114~~709	1512	%

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~~September 30, 2018:

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

__________

(a) On ~~July~~August 199, 2018, ~~Fitch~~S&P ~~affirmed~~upgraded to A rating.

(b) 20On 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 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, 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~~September 30, 2018. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective as of ~~June~~September 30, 2018.

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

Changes in Internal Control over Financial Reporting

During the quarter ended ~~June~~September 30, 2018, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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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 2017 Annual Report on Form 10-K and Note 9 of our Notes to Condensed Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 9 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, 2017.


Item 6.	Exhibits


Exhibit 3.1*	Restated Articles of Incorporation of the Registrant dated January 30, 2018 (filed as Exhibit 3 to Registrant’s Form 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).


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

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~~November 76, 2018

2324

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