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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~~March 3031, ~~2018~~2019 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

AsSecurities ofregistered ~~October~~pursuant ~~31,~~to ~~2018,~~Section ~~there~~12(b) ~~were issued and outstanding 23,416,396 shares~~ of the ~~Registrant’s~~Act: ~~common stock, $1.00 par value, all of which were held beneficially and of record by Black Hills Corporation.~~None

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

Reduced Disclosure

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

TABLE OF CONTENTS

		Page
	GLOSSARY OF TERMS AND ABBREVIATIONS	3
PART 1.	FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Statements of Comprehensive Income - unaudited	4
	Three and Nine Months Ended September 30, 2018 and 2017
	Three Months Ended March 31, 2019 and 2018
	Condensed Balance Sheets - unaudited	5
	September 30, 2018 and December 31, 2017
	March 31, 2019 and December 31, 2018
	Condensed Statements of Cash Flows - unaudited	7
	Nine Months Ended September 30, 2018 and 2017
	Three Months Ended March 31, 2019 and 2018
	Notes to Condensed Financial Statements - unaudited	8
Item 2.	Managements’ Discussion and Analysis of Financial Condition and Results of Operations	1816
Item 4.	Controls and Procedures	2220
PART II.	OTHER INFORMATION	2321
Item 1.	Legal Proceedings	2321
Item 1A.	Risk Factors	2321
Item 6.	Exhibits	2321
	Signatures	2422

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.
Cooling degree day (CDD)	A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
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.
Heating degree day (HDD)	A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
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
Parent	Black Hills Corporation
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.
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 September 30,

Nine Months Ended September 30,

Three Months Ended March 31,

(unaudited)

~~2018~~2019

2018

~~2017~~

~~2018~~

~~2017~~

(in thousands)

Revenue

7879,~~067~~041

$73,815

~~73,938~~

~~222,558~~

~~213,785~~

Operating expenses:

Fuel and purchased power

2522,~~207~~733

22,440

~~22,843~~

~~68,400~~

~~64,604~~

Operations and maintenance

19,~~851~~557

19,151

~~16,747~~

~~57,430~~

~~52,589~~

Depreciation and amortization

910,~~950~~077

9,884

~~9,053~~

~~29,700~~

~~26,578~~

Taxes - property

12,~~631~~032

1,976

~~1,597~~

~~5,741~~

~~5,228~~

Total operating expenses

5654,~~639~~399

53,451

~~50,240~~

~~161,271~~

~~148,999~~

Operating income

2124,~~428~~642

20,364

~~23,698~~

~~61,287~~

~~64,786~~

Other income (expense):

Interest charges -

Interest expense incurred (including amortization of debt issuance costs, premiums, and discounts)

(5,~~632~~830

)

(5,587

~~(5,483~~

)

~~(16,873~~

)

~~(16,873~~

)

Allowance for funds used during construction - borrowed

~~199~~283

~~369~~

~~399~~

~~953~~

Interest income

~~250~~115

115

~~335~~

~~488~~

~~704~~

Allowance for funds used during construction - equity

68—

~~676~~

~~239~~

~~1,864~~

Other income (expense), net

(~~315~~375

)

(151

)

~~(845~~

)

~~(119~~

)

Total other income (expense), net

(5,~~430~~807

)

(5,541

~~(4,100~~

)

~~(16,592~~

)

~~(13,471~~

)

Income before income taxes

1518,~~998~~835

14,823

~~19,598~~

~~44,695~~

~~51,315~~

Income tax expense

(23,~~681~~338

)

(3,063

~~(5,772~~

)

~~(8,493~~

)

~~(15,632~~

)

Net income

1315,~~317~~497

11,760

~~13,826~~

~~36,202~~

~~35,683~~

Other comprehensive income (loss), net of tax:

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)

Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $0 and $(6), respectively)

—

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)

Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(4) and $(9), respectively)

Other comprehensive income (loss), net of tax

2712

Comprehensive income

1315,~~344~~509

$11,787

~~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)	~~September~~March 3031, ~~2018~~2019			December 31, ~~2017~~2018
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	13		$	16
Cash	$	5		$	112
Accounts receivable, net	28,~~192~~354			2928,~~050~~431
Accounts receivable from affiliates	69,~~373~~903			58,~~664~~119
Materials, supplies and fuel	2425,~~503~~275			2324,~~443~~853
Regulatory assets, current	1623,~~939~~215			1819,~~993~~052
Other current assets	34,~~211~~692			4,~~724~~538
Total current assets	7991,~~231~~444			8185,~~890~~105
Investments	54,~~006~~973			4,~~926~~889
Property, plant and equipment	1,~~351~~399,~~996~~901			1,~~311~~381,~~819~~045
Less: accumulated depreciation and amortization	(~~370~~383,~~978~~681		)	(~~358~~376,~~946~~160		)
Total property, plant and equipment, net	~~981~~1,~~018~~016,220			~~952~~1,~~873~~004,885
Other assets:
Regulatory assets, non-current	5653,~~728~~141			5956,~~710~~680
Other assets, non-current	924,~~665~~616			39,~~747~~729
Total other assets, non-current	6677,~~393~~757			6366,~~457~~409
TOTAL ASSETS	$	1,~~131~~190,~~648~~394		$	1,~~103~~161,~~146~~288

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

BLACK HILLS POWER, INC.

CONDENSED BALANCE SHEETS

(Continued)

	As of
(unaudited)	~~September~~March 3031, ~~2018~~2019			December 31, ~~2017~~2018
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	2019,~~388~~434		$	1425,~~766~~122
Accounts payable to affiliates	2226,~~939~~966			25,~~653~~804
Accrued liabilities	4340,~~931~~428			3834,~~205~~193
Money pool notes payable	1333,~~888~~300			1338,~~397~~690
Regulatory liabilities, current	82,~~216~~079			~~842~~2,574
Total current liabilities	~~109~~122,~~362~~207			92126,~~863~~383
Long-term debt	340,~~000~~070			~~339~~340,~~895~~035
Deferred credits and other liabilities:
Deferred income tax liabilities, net	~~113~~116,~~247~~499			~~110~~114,~~618~~009
Regulatory liabilities, non-current	~~158~~161,~~063~~714			~~148~~160,~~013~~642
Benefit plan liabilities	1514,~~207~~631			1614,~~285~~606
Other deferred credits and other liabilities	115,~~251~~525			1,~~240~~368
Total deferred credits and other liabilities	~~287~~308,~~768~~369			~~276~~290,~~156~~625
Commitments and contingencies (Notes 5, 6 and 9)
Stockholder’s equity:
Common stock $1 par value; 50,000,000 shares authorized; 23,416,396 shares issued	23,416			23,416
Additional paid-in capital	39,575			39,575
Retained earnings	~~332~~357,~~703~~636			~~332~~342,~~499~~145
Accumulated other comprehensive loss	(~~1,176~~879		)	(~~1,258~~891		)
Total stockholder’s equity	~~394~~419,~~518~~748			~~394~~404,~~232~~245
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	1,~~131~~190,~~648~~394		$	1,~~103~~161,~~146~~288

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

BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(unaudited)	~~Nine~~Three Months Ended ~~September~~March 3031,
	2018			2017
	2019			2018
	(in thousands)
Operating activities:
Net income	$	3615,~~202~~497		$	3511,~~683~~760
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization	2910,~~700~~077			269,~~578~~884
Deferred income tax	41,~~619~~718			~~6,188~~(898		)
Employee benefits	~~1,139~~195			~~613~~380
AFUDC	(239		)	(2,817		)
Other adjustments, net	1,044			1,018
Other adjustments, net	2,362			2,298
Change in operating assets and liabilities -
Accounts receivable and other current assets	~~224~~(2,437		)	6(2,~~567~~478		)
Accounts payable and other current liabilities	26,~~337~~210			3,~~077~~320
Regulatory assets - current	2(1,~~004~~413		)	1,~~543~~807
Regulatory liabilities - current	~~8,224~~(444		)	—3,171
Contributions to defined benefit pension plan	(1,795		)	(4,000		)
Other operating activities, net	(594		)	35
Other operating activities, net	(1,400		)	(1,097		)
Net cash provided by (used in) operating activities	29,853			27,999
Net cash provided by (used in) operating activities	83,377			74,633
Investing activities:
Property, plant and equipment additions	(4724,~~527~~386		)	(6113,~~537~~533		)
Proceeds from sale of assets	~~4,994~~—			—4,994
Change in money pool notes receivable, net	—			(12,472		)
Other investing activities	(169		)	(3,608		)
Other investing activities	(5,338		)	313
Net cash provided by (used in) investing activities	(24,555		)	(12,147		)
Net cash provided by (used in) investing activities	(47,871		)	(73,696		)
Financing activities:
Change in money pool notes payable, net	(355,~~509~~390		)	—(15,856		)
Net cash provided by (used in) financing activities	(35,509		)	—
Other financing activities	(15		)	—
Net change in cash and cash equivalents	(3		)	937
Net cash provided by (used in) financing activities	(5,405		)	(15,856		)
Cash and cash equivalents, beginning of period	16			234
Net change in cash	(107		)	(4		)
Cash and cash equivalents, end of period	$	13		$	1,171
Cash, beginning of period	112			16
Cash, end of period	$	5		$	12

See Note 8 for supplemental cash flow information.

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

BLACK HILLS POWER, INC.

Notes to Condensed Financial Statements

(unaudited)

(Reference is made to Notes to Financial Statements

included in our ~~2017~~2018 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~~2018 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~~March 3031, ~~2018~~2019, December 31, ~~2017~~2018 and ~~September~~March 3031, ~~2017~~2018 financial information and are of a normal recurring nature. The results of operations for the three months ended ~~September~~March 3031, ~~2018~~2019 and ~~September~~March 3031, ~~2017~~2018, and our financial condition as of ~~September~~March 3031, ~~2018~~2019 and December 31, ~~2017~~2018 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

Recently ~~Issued~~Adopted Accounting Standards

Leases, ASU 2016-02

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), ~~which~~to ~~supersedes~~increase ~~ASC~~transparency ~~840,~~and ~~Leases. This~~comparability ~~ASU~~among ~~requires~~organizations ~~lessees~~by torequiring ~~recognize~~the arecognition of right-of-use ~~asset~~assets and lease ~~liability~~liabilities on the balance sheet for most leases, whereas ~~today~~previously only financing-type lease liabilities (capital leases) ~~are~~were recognized on the balance sheet. InUnder ~~addition,~~ the ~~definition~~new ofstandard, adisclosures ~~lease~~are ~~has~~required ~~been revised in regards~~ to ~~when~~meet ~~an arrangement conveys~~ the ~~right~~objective toof ~~control~~enabling ~~the~~users ~~use~~ of ~~the~~financial ~~identified~~statements ~~asset under the arrangement which may result in changes~~ to ~~the~~assess ~~classification of an arrangement as a lease. The ASU does not significantly change~~ the ~~lessees’ recognition~~amount, ~~measurement~~timing and ~~presentation~~uncertainty of ~~expenses and~~ cash flows ~~from~~arising ~~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~~adopted tothe ~~adopt this~~ standard oneffective January 1, 2019. ~~For~~We ~~existing~~elected orthe ~~expired~~option ~~land~~to ~~easements that were~~ not ~~previously~~recast ~~accounted~~comparative ~~for~~periods aspresented ~~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~~lease standard ~~also~~and ~~provides~~will areport ~~transition~~these ~~practical~~comparative ~~expedient,~~periods ~~commonly referred to~~ as ~~the~~presented ~~“package~~under ofprevious ~~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~~guidance. WeIn ~~expect~~addition, towe ~~elect~~elected the “package of ~~three”~~ practical ~~expedient. We continue to evaluate the additional transition practical~~ expedients ~~available~~permitted under the transition guidance~~. At~~ ~~this~~with ~~time, we do not believe~~ the ~~implementation~~new ~~of this~~ standard, ~~will~~which ~~have~~among aother ~~material impact on our financial position~~things, ~~results~~allowed ofus ~~operations or cash flows. We continue~~ to ~~finalize~~carry ~~our~~forward ~~process~~the ofhistorical ~~identifying and categorizing our~~ lease ~~contracts and evaluating our current business processes relating to leases~~classification. We ~~have~~also ~~selected,~~elected ~~configured, and tested a new lease software solution and will be entering lease data into~~ the ~~new~~practical ~~system~~expedient inrelated ~~preparation~~to ~~for~~land ~~the January 1~~easements, ~~2019~~allowing ~~standard~~us ~~adoption. We also continue~~ to ~~monitor~~carry ~~utility~~forward ~~industry~~our ~~lease~~accounting ~~implementation~~treatment ~~guidance~~of ~~that may change~~ existing ~~and~~land ~~future~~easement ~~lease classification~~agreements.

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

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 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 nine months ended 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~~As ~~are~~of January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and its related amendments (collectively known as ASC 606). Revenue is recognized in an amount that reflects the consideration we expect to receive in exchange for goods or services, when control of the promised goods or services is transferred to our customers. ~~Our~~The ~~primary~~following ~~types~~table depicts the disaggregation of revenue, from contracts with customers by customer type and timing of revenue recognition for the three months ended March 31, 2019 and 2018. Sales tax and other similar taxes are: excluded from revenues.

• 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.



	Three Months Ended March 31, 2019		Three Months Ended March 31, 2018
	(in thousands)
Customer types:
Retail	$	53,076	$	50,641
Wholesale	8,343		9,050
Market - off-system sales	4,670		2,275
Transmission/Other	12,831		11,718
Revenue from contracts with customers	78,920		73,684
Other revenues	121		131
Total revenues	$	79,041	$	73,815

Timing of revenue recognition:
Services transferred over time	$	78,920	$	73,684
Revenue from contracts with customers	$	78,920	$	73,684

• 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. Sales tax and other similar taxes are excluded from revenues.

	Three Months Ended September 30, 2018		Nine Months Ended September 30, 2018
	(in thousands)
Customer types:
Retail	$	49,874	$	147,040
Wholesale	8,255		25,496
Market - off-system sales	7,625		13,349
Transmission/Other	12,183		36,273
Revenue from contracts with customers	77,937		222,158
Other revenues	130		400
Total revenues	$	78,067	$	222,558
Timing of revenue recognition:
Services transferred over time	$	77,937	$	222,158
Revenue from contracts with customers	$	77,937	$	222,158

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 $2.5 million and $8.2 million during the three and nine months ended September 30, 2018.

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.

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~~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~~3. We do not typically incur costs that would be capitalized, to obtain or fulfill a revenue 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 Accounts receivable, net included in the accompanying Condensed Balance Sheets (in thousands) as of:

	September 30, 2018			December 31, 2017
	March 31, 2019			December 31, 2018
Accounts receivable trade	$	1718,~~019~~196		$	1516,~~994~~236
Unbilled revenues	1110,~~275~~356			1312,~~280~~333
Allowance for doubtful accounts	(~~102~~198		)	(~~224~~138		)
Accounts receivable, net	$	28,~~192~~354		$	2928,~~050~~431

119


(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:

	September 30, 2018			December 31, 2017
	March 31, 2019			December 31, 2018
Regulatory assets:
Unamortized loss on reacquired debt (a)	$	1,326		$	1,534
Loss on reacquired debt (a)	$	1,191		$	1,259
Deferred taxes on AFUDC (b)	5,~~010~~048			5,~~095~~020
Employee benefit plans(c)	19,619			19,465
Employee benefit plans and related deferred taxes (c)	20,085			19,868
Deferred energy and fuel cost adjustments (a)	17,697			19,602
Deferred energy and fuel cost adjustments (b)	21,649			20,334
Deferred taxes on flow through accounting	8,302			7,579
Deferred taxes on flow through accounting (c)	9,045			8,749
Decommissioning costs, net of amortization	8,710			10,252
Decommissioning costs (a)	7,682			8,196
Vegetation management, net of amortization	10,942			12,669
Vegetation management (a)	9,790			10,366
Other regulatory assets (a)	21,~~061~~866			21,~~507~~940
Total regulatory assets	$	7376,~~667~~356		$	7875,~~703~~732
Less current regulatory assets	(1623,~~939~~215		)	(1819,~~993~~052		)
Regulatory assets, non-current	$	5653,~~728~~141		$	5956,~~710~~680

Regulatory liabilities:
Cost of removal for utility plant (a)	$	5153,~~106~~758		$	4452,~~056~~366
Employee benefit plan costs and related deferred taxes (c)	67,~~808~~518			67,~~808~~518
Excess deferred income taxes	99,774			97,101
Excess deferred income taxes (c)	99,846			100,276
TCJA revenue reserve	82,~~188~~079			—2,523
Other regulatory liabilities	403			890
Other regulatory liabilities (c)	592			533
Total regulatory liabilities	$	~~166~~163,~~279~~793		$	~~148~~163,~~855~~216
Less current regulatory liabilities	(82,~~216~~079		)	(~~842~~2,574		)
Regulatory liabilities, non-current	$	~~158~~161,~~063~~714		$	~~148~~160,~~013~~642

____________________


(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.

Regulatory Matters

~~Except~~There ~~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~~2018 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, 2018.10

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 estimated 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 $3616 million and ~~$32~~decreased ~~million~~the ~~for~~utility ~~nine~~Money ~~months~~pool ~~ended~~note ~~September~~receivable ~~30,~~by ~~2018~~$16 ~~and~~million ~~September 30,~~for ~~2017, respectively, and changed~~ the ~~utility~~three ~~Money~~months ~~pool~~ended ~~note~~March 31, by2018. We ~~$36~~did ~~million~~not ~~and~~record ~~$32~~any ~~million~~dividends for the ~~nine~~three months ended ~~September~~March 3031, ~~2018 and September 30, 2017, respectively~~2019.

Receivables and Payables

We have accounts receivable and accounts payable balances related to transactions with other BHC subsidiaries. The balances were as follows (in thousands) as of:

	September 30, 2018			December 31, 2017
	March 31, 2019		December 31, 2018
Accounts receivables from affiliates	$	6,373		$	5,664
Accounts receivable from affiliates	$	9,903	$	8,119
Accounts payable to affiliates	$	2226,~~939~~966	$	$25,804	~~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 ~~September~~March 3031, ~~2018~~2019, the average cost of borrowing under the Utility Money Pool was 2.6088%.

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

	September 30, 2018			December 31, 2017
	March 31, 2019		December 31, 2018
Money pool notes payable	$	1333,~~888~~300	$	$38,690	~~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,
	Three Months Ended March 31,
	2018			2017			2018			2017
	2019			2018
Net interest income (expense)	$	(75273	)	$	53(36	)	$	~~(207~~	)	$	~~269~~

1311

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	Three Months EndedMarch 31,
	2018		2017		2018		2017
	2019		2018
Revenue:
Energy sold to Cheyenne Light	$	~~311~~574	$	~~361~~703	$	~~1,515~~	$	~~1,866~~
Rent from electric properties	$	~~908~~896	$	~~935~~909	$	~~3,025~~	$	~~2,805~~
Horizon Point shared facility revenues	$	23,~~826~~007	$	—2,769	$	~~8,078~~	$	—
Fuel and purchased power:
Purchases of coal from WRDC	$	4,~~161~~657	$	4,~~054~~067	$	~~12,477~~	$	~~11,386~~
Purchase of excess energy from Cheyenne Light	$	~~193~~132	$	~~208~~86	$	~~361~~	$	~~324~~
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	~~262~~535	$	~~199~~641	$	~~1,284~~	$	~~1,174~~
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	~~582~~983	$	~~351~~1,093	$	~~2,371~~	$	~~2,007~~
Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	9676	$	9996	$	~~288~~	$	~~297~~
Corporate support:
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
Corporate support services and fees from Black Hills Service Company	$	10,191	$	7,606

____________________

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

Horizon Point Agreement

We have a shared facility agreement among South Dakota Electric, and 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 September 30,							Nine Months Ended September 30,
	Three Months Ended March 31,
	2018				2017			2018			2017
	2019			2018
Service cost	$	~~129~~91		$	$129	~~137~~		$	~~387~~		$	~~409~~
Interest cost	~~548~~603			548	~~585~~			~~1,645~~			~~1,755~~
Expected return on plan assets	(~~887~~851		)	(886	~~(898~~	)	)	~~(2,660~~		)	~~(2,692~~		)
Prior service cost	112			11	10			33			32
Net loss (gain)	~~516~~305			516	~~308~~			~~1,548~~			~~922~~
Net periodic benefit cost	$	~~317~~150		$	$318	~~142~~		$	~~953~~		$	~~426~~

1412

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,
	2018				2017			2018			2017
	2019			2018
Service cost	$	4837		$	$48	52		$	~~145~~		$	~~155~~
Interest cost	4547			45	44			~~134~~			~~132~~
Prior service cost (benefit)	(84		)	(84	~~(84~~	)	)	~~(252~~		)	~~(252~~		)
Net periodic benefit cost	$	9—		$	$9	12		$	27		$	35

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,
	2018			2017		2018		2017
	2019		2018
Interest cost	$	2729	$	$27	29	$	81	$	87
Net loss (gain)	2616		26	22		78		65
Net periodic benefit cost	$	5345	$	$53	51	$	~~159~~	$	~~152~~

For the three and nine months ended 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 nine months ended 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~~2019 and anticipated contributions for ~~2018~~2019 and ~~2019~~2020 are as follows (in thousands):

	ContributionsNine Months EndedSeptember 30, 2018		Remaining Anticipated Contributions for 2018		Anticipated Contributions for 2019
	ContributionsThree Months EndedMarch 31, 2019		Remaining Anticipated Contributions for 2019		Anticipated Contributions for 2020
Defined Benefit Pension Plan	$	~~1,795~~—	$	—1,753	$	1,~~850~~841
Defined Benefit Postretirement Healthcare Plan	$	~~401~~117	$	~~134~~349	$	~~412~~466
Supplemental Non-qualified Defined Benefit Plans	$	~~184~~58	$	61172	$	~~242~~240

1513


(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~~2018 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, 2018					December 31, 2017
	March 31, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount	~~Carrying Amount~~		Fair Value	~~Fair Value~~
Cash and cash equivalents (a)	$	13	$	13		$	16		$	16
Cash (a)	$	5	$	5	$	112		$	112
Long-term debt, including current maturities (b) (c)	$	340,~~000~~070	$	~~411~~428,~~948~~498	$	$340,035	~~339,895~~	$	$412,894	~~446,978~~

_________________

(a) ~~Carrying~~The ~~value~~cash ~~approximates~~ fair value ~~due~~approximates tocarrying ~~either~~value ~~short-term~~and ~~length~~therefore ofis ~~maturity~~classified oras ~~variable~~Level ~~interest~~1 ~~rates~~in ~~that~~the ~~approximate~~fair ~~prevailing~~value ~~market~~hierarchy. ~~rates~~We ~~and~~believe ~~therefore~~that isthe ~~classified~~market inrisk ~~Level~~arising 1from cash in ~~the~~a ~~fair~~bank ~~value~~account ~~hierarchy~~is minimal.


(b)	Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.


(c)	Carrying amount of long-term debt is net of deferred financing costs.


(8)	SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

	Nine Months Ended September 30,
	Three Months Ended March 31,
	2018				2017
	2019			2018
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	108,~~540~~633		$	$7,556	~~10,242~~
Non-cash (decrease) to money pool notes receivable, net	$	~~(36,000~~—	)	$	$(16,000	~~(32,000~~)	)
Non-cash dividend to Parent	$	~~36,000~~—		$	$16,000	~~32,000~~
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(143,~~104~~345	)	$	$(3,088	~~(12,838~~)	)
Income taxes, net	$	—		$	—


(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~~2018 Annual Report on Form 10-K ~~except for those described below~~.

~~Platte~~(10) ~~River Power Authority PPA~~LEASES

OnWe ~~August~~have ~~16,~~a ~~2018,~~ground welease ~~entered~~for ~~into~~the aWygen ~~PPA~~III generating facility with ~~Platte~~an ~~River~~affiliate ~~Power~~and ~~Authority~~communication ~~(PRPA)~~tower tosite ~~purchase~~and upoperation tocenter 12facility MWleases ofwith ~~wind~~third ~~energy~~parties. Our ~~through~~leases ~~PRPA’s~~have ~~agreement~~remaining ~~with~~terms ~~Silver~~ranging ~~Sage. This~~from ~~agreement~~less ~~will~~than ~~expire~~one ~~September~~year ~~30,~~to ~~2029.~~31 years.

The 16components of lease expense were as follows (in thousands):

(10) INCOME TAXES



	Income Statement Location	Three Months Ended March 31, 2019
Operating lease cost	Operations and maintenance	$	228
Variable lease cost	Operations and maintenance	43
Total lease cost		$	271

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.14

Supplemental 17balance sheet information related to leases was as follows (in thousands):



	Balance Sheet Location	As of March 31, 2019
Assets:
Operating lease assets	Other assets, non-current	$	14,316
Total lease assets		$	14,316

Liabilities:
Current:
Operating leases	Accrued liabilities	$	279

Noncurrent:
Operating leases	Other deferred credits and other liabilities	14,054
Total lease liabilities		$	14,333

Supplemental cash flow information related to leases was as follows (in thousands):



	Three Months Ended March 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	223
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	—



	As of March 31, 2019
Weighted average remaining lease term (years):
Operating leases	31 years

Weighted average discount rate:
Operating leases	4.4	%

Scheduled maturities of operating lease liabilities for future years were as follows (in thousands):



	Total
2019 ^(a)	$	681
2020	856
2021	855
2022	856
2023	853
Thereafter	21,947
Total lease payments	$	26,048
Less imputed interest	11,715
Present value of lease liabilities	$	14,333


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


(11)	EQUITY

A summary of the changes in equity is as follows:



Three Months Ended March 31, 2019	Common Stock
(in thousands except share amounts)	Shares	Value		Additional Paid in Capital		Retained Earnings			AOCI			Total
December 31, 2018	23,416	$	23,416	$	39,575	$	342,145		$	(891	)	$	404,245
Net income (loss) available for common stock	—	—		—		15,497			—			15,497
Other comprehensive income (loss), net of tax	—	—		—		—			12			12
Cumulative effect of ASU 2016-02, Leases implementation	—	—		—		(7		)	—			(7		)
Other adjustments	—	—		—		1			—			1
March 31, 2019	23,416	$	23,416	$	39,575	$	357,636		$	(879	)	$	419,748



Three Months Ended March 31, 2018	Common Stock
(in thousands except share amounts)	Shares	Value		Additional Paid in Capital		Retained Earnings			AOCI			Total
December 31, 2017	23,416	$	23,416	$	39,575	$	332,499		$	(1,258	)	$	394,232
Net income (loss) available for common stock	—	—		—		11,760			—			11,760
Other comprehensive income (loss), net of tax	—	—		—		—			27			27
Non-cash dividend to Parent company	—	—		—		(16,000		)	—			(16,000		)
Other adjustments	—	—		—		1			—			1
March 31, 2018	23,416	$	23,416	$	39,575	$	328,260		$	(1,231	)	$	390,020

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

RESULTS OF OPERATIONS

Amounts are presented on a pre-tax basis unless otherwise indicated.

Minor differences in amounts may result due to rounding.

Significant Events

On ~~September~~April 430, ~~2018~~2019, ~~the~~S&P ~~SDPUC~~affirmed ~~approved a settlement agreement for~~ South Dakota Electric’s ~~allowing~~credit ~~the~~rating ~~company~~at ~~to pass on the benefits of a lower corporate federal income tax rate to our South Dakota retail customers~~A. 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.

OnDuring ~~August~~the ~~16,~~first ~~2018~~quarter, weSouth ~~entered~~Dakota ~~into~~Electric continued construction on a ~~PPA~~$70 ~~with~~million, ~~Platte~~175-mile ~~River~~electric ~~Power~~transmission ~~Authority~~line ~~(PRPA)~~from Stegall, Nebraska to ~~purchase~~Rapid upCity, toSouth 12Dakota. MWThe 94-mile final segment of ~~wind~~the ~~energy~~transmission ~~through~~line ~~PRPA’s~~is ~~agreement~~expected ~~with~~to ~~Silver~~be ~~Sage. This~~completed ~~agreement~~and ~~will~~placed ~~expire~~in ~~September~~service ~~30,~~in ~~2029.~~the fall of 2019.

On ~~August 9, 2018, S&P upgraded South Dakota Electric’s credit rating to A.~~16

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 September 30,									Nine Months Ended September 30,
	Three Months Ended March 31,
	2018			2017			Variance			2018			2017			Variance
	2019			2018			Variance
	(in thousands)
Revenue	$	7879,~~067~~041		$	73,~~938~~815		$	45,~~129~~226		$	~~222,558~~		$	~~213,785~~		$	~~8,773~~
Fuel and purchased power	2522,~~207~~733			22,~~843~~440			~~2,364~~293			~~68,400~~			~~64,604~~			~~3,796~~
Gross margin (a)	52,860			51,095			1,765			154,158			149,181			4,977
Gross margin (non-GAAP)	56,308			51,375			4,933
Operating expenses	31,~~432~~666			2731,~~397~~011			~~4,035~~655			~~92,871~~			~~84,395~~			~~8,476~~
Operating income	2124,~~428~~642			2320,~~698~~364			(24,~~270~~278		)	~~61,287~~			~~64,786~~			~~(3,499~~		)
Interest income (expense), net	(5,~~183~~432		)	(45,~~779~~424		)	(~~404~~8		)	~~(15,986~~		)	~~(15,216~~		)	~~(770~~		)
Other income (expense), net	(~~247~~375		)	~~679~~(117		)	(~~926~~258		)	~~(606~~		)	~~1,745~~			~~(2,351~~		)
Income tax expense	(23,~~681~~338		)	(53,~~772~~063		)	~~3,091~~(275		)	~~(8,493~~		)	~~(15,632~~		)	~~7,139~~
Net income	$	1315,~~317~~497		$	1311,~~826~~760		$	~~(509~~3,737	)	$	~~36,202~~		$	~~35,683~~		$	~~519~~

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

~~(a)~~Gross ~~Non-GAAP~~margin ~~measure~~increased primarily due to $2.4 million of higher power marketing revenue, customer growth, and favorable weather. A $1.6 million reduction in the purchased power capacity charges and higher rider revenues of $0.9 million, primarily related to transmission investment recovery, comprised the remainder of the increase.

~~Nine~~Operating ~~Months~~expenses ~~Ended~~increased ~~September~~primarily ~~30,~~due ~~2018 Compared~~ to ~~Nine~~higher ~~Months~~outside ~~Ended~~services ~~September~~expenses ~~30,~~and ~~2017. Net~~higher ~~income~~employee ~~was~~costs ~~$36~~driven ~~million~~by ~~compared~~labor toand ~~$36~~benefits ~~million~~partially ~~for~~offset ~~the~~by ~~same~~a ~~period~~decrease in ~~the~~expenses ~~prior year primarily~~ due to ~~the~~generation ~~following:~~outage timing.

~~Gross~~Interest ~~margin~~expense, ~~increased primarily due to $8.1 million Horizon Point shared facility revenue~~net, ~~higher~~Other ~~power~~income ~~marketing and wholesale revenue of $1.9 million~~(expense), ~~a $1.4 million increase in residential margins primarily from higher volume usage per customer~~net, and ~~higher~~Income ~~rider~~tax ~~revenues~~expense ~~of $2.0 million primarily related to transmission investment recovery. These increases~~ were ~~partially~~all ~~offset~~comparable ~~by an $8.2 million reserve~~ to ~~revenue~~prior ~~to reflect the reduction of the lower federal income tax rate from the TCJA on our existing rate tariffs and lower commercial and industrial volume of $0~~year.~~6 million.~~

~~Operating~~ expenses increased due to depreciation and property taxes increases of $3.6 million from higher asset base driven by the prior year additions of Horizon Point and the Teckla-Lange transmission line. Higher vegetation management expenses, higher employee costs, and higher facility costs comprise the remainder of the increase compared to the same period in the prior year. 17

Interest expense, net increased due to higher prior year AFUDC associated with higher prior year capital spend.



	Electric Revenue by Customer Type
	Three Months Ended March 31,
	(in thousands)
	2019		Percentage Change	2018
Residential	$	21,190	1%	$	21,061
Commercial	23,144		(2)%	23,544
Industrial	8,357		1%	8,276
Municipal	781		(4)%	811
Total retail revenue	53,472		—%	53,692
Wholesale	8,343		(8)%	9,050
Market - off-system sales ^(a)	4,670		105%	2,275
Other revenue ^(b)	12,556		43%	8,798
Total revenue	$	79,041	7%	$	73,815

Other income (expense), net decreased due to the presentation 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.

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.

	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

____________________

(a) Increase for the ~~nine~~three months ended ~~September~~March 3031, ~~2018~~2019 was ~~primarily~~due ~~driven~~to byhigher ~~increased~~trading ~~volumes~~volume onopportunities ~~long-term~~driven ~~wholesale~~by ~~contracts~~weather and energy prices.

(b) Increase for the three ~~and nine~~ months ended ~~September~~March 3031, ~~2018~~2019 was primarily due to ~~higher~~the ~~trading~~prior ~~volume~~year ~~opportunities~~reserve to revenue to reflect the reduction of the lower federal income tax rate from the TCJA on our existing rate tariffs.

(c) Increase 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 March 31,
	2019	Percentage Change	2018
Residential	169,936	4%	163,113
Commercial	194,794	—%	194,931
Industrial	108,196	4%	104,302
Municipal	7,573	1%	7,503
Total retail quantity sold	480,499	2%	469,849
Wholesale	223,020	(6)%	237,704
Market - off-system sales	99,572	8%	92,102
Total quantity sold	803,091	—%	799,655
Losses and Company use ^(a)	41,910	47%	28,522
Total energy	845,001	2%	828,177

	Megawatt Hours Sold by Customer Type
	Three Months Ended September 30,			Nine Months Ended September 30,
	2018	Percentage Change	2017	2018	Percentage Change	2017
Residential	125,159	(3)%	129,616	404,177	5%	386,709
Commercial	204,621	(4)%	212,773	586,336	1%	582,899
Industrial (a)	95,473	(13)%	109,745	305,875	(5)%	323,038
Municipal (b)	9,070	(11)%	10,156	24,052	(7)%	25,865
Total retail quantity sold	434,323	(6)%	462,290	1,320,440	—%	1,318,511
Wholesale (c)	221,327	19%	185,723	677,163	26%	537,720
Market - off-system sales (d)	172,141	32%	130,825	406,109	5%	388,287
Total quantity sold	827,791	6%	778,838	2,403,712	7%	2,244,518
Losses and company use (e)	47,171	(16)%	56,447	137,370	(12)%	155,477
Total energy	874,962	5%	835,285	2,541,082	6%	2,399,995

____________________

(a) ~~Increase~~Includes ~~for~~company ~~the~~uses, ~~three~~line ~~months ended September 30~~losses, ~~2018 was primarily driven by lower demand~~ and ~~milder~~excess ~~summer~~exchange ~~weather~~production.

~~(b)~~ ~~Increase for three months ended September 30, 2018 was due to milder summer weather.~~18

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



	Megawatt Hours Generated and Purchased
	Three Months Ended March 31,
Generated -	2019	Percentage Change	2018
Coal-fired	409,666	3%	399,087
Natural Gas and Oil ^(a)	47,703	264%	13,107
Total generated	457,369	11%	412,194

Total purchased	387,632	(7)%	415,983
Total generated and purchased	845,001	2%	828,177

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

(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 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 nine~~ months ended ~~September~~March 3031, ~~2018~~2019.

	Power Plant Availability
	Three Months Ended September 30,					Nine Months Ended September 30,
	Three Months Ended March 31,
	2018			2017		2018		2017
	2019		2018
Coal-fired plants (a)	9398.82	%	92.9	~~97.5~~%	%	~~92.7~~	%	~~84.8~~	%
Other plants	96.0	%		93.7	%	97.6	%	97.0	%
Other plants (b)	87.3	%	99.4	%
Total availability	9592.04	%	96.3	~~95.5~~%	%	~~95.3~~	%	~~91.3~~	%

____________________

(a) ~~2017~~2018 included planned outages at Neil Simpson II, Wyodak and Wygen II.

	Degree Days						Degree Days
	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	236	5	%	202	(10	)%	4,972	11	%	4,242	(5	)%
Cooling degree days	356	(33	)%	595	11	%	488	(23	)%	709	12	%


(b)	2019 includes a planned outage at Lange CT.



	Degree Days
	Three Months Ended March 31,
	2019			2018
	Actual	Variance from Normal		Actual	Variance from Normal

Heating degree days	3,916	22	%	3,699	15	%

Credit Ratings

Credit ratings impact our ability to obtain short and long-term financing, the cost of such financing, and vendor payment terms, including collateral requirements. The following table represents our secured credit rating from each agency’s review which was in effect at ~~September~~March 3031, ~~2018~~2019:

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

__________

(a) On ~~August~~April 930, ~~2018~~2019, S&P ~~upgraded~~affirmed to A rating.

(b) On ~~July~~December 1912, 2018, ~~Fitch~~Moody’s affirmed AA1 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~~2018 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~~2018.

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) as of ~~September~~March 3031, ~~2018~~2019. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective as of ~~September~~March 3031, ~~2018~~2019.

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

Changes in Internal Control over Financial Reporting

During the quarter ended ~~September~~March 3031, ~~2018~~2019, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

2220

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~~2018 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~~2018.


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.INS ~~Financial~~XBRL ~~Statements~~Instance ~~for~~Document - the instance document does not appear in the Interactive Data File because its XBRL ~~Format~~tags are embedded within the Inline XBRL document


101.SCH	XBRL Taxonomy Extension Schema Document


101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document


101.DEF	XBRL Taxonomy Extension Definition Linkbase Document


101.LAB	XBRL Taxonomy Extension Label Linkbase Document


101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

_________________________


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

2321

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~~LINDEN R. ~~EMERY~~EVANS

~~David~~Linden R. ~~Emery~~Evans, Chairman, President

and Chief Executive Officer

/S/ RICHARD W. KINZLEY

Richard W. Kinzley, Senior Vice President

and Chief Financial Officer

Dated: ~~November~~May 63, ~~2018~~2019

2422

Filing Compare · BLACK HILLS POWER INC