UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



x☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended	June 30, ~~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~~Accelerated Filer	o		Accelerated ~~filer~~Filer	o

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

			Smaller ~~reporting company~~Reporting Company	o☐

			Emerging ~~growth company~~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).



Yeso	☐	No x



Securities registered pursuant to Section 12(b) of the Act: None

As of July 31, ~~2018,~~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		~~GLOSSARY OF TERMS AND ABBREVIATIONS~~	3

~~PART 1.~~	~~FINANCIAL INFORMATION~~
PART 1. FINANCIAL INFORMATION

Item 1.	Financial Statements - unaudited

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

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

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

	~~Notes to Condensed Financial Statements - unaudited~~	8
	Notes to Condensed Financial Statements		9
	Note 1. Management’s Statement		9
	Note 2. Revenue		10
	Note 3. Accounts Receivable		10
	Note 4. Regulatory Accounting		11
	Note 5. Related-Party Transactions		12
	Note 6. Employee Benefit Plans		13
	Note 7. Fair Value of Financial Instruments		15
	Note 8. Supplemental Disclosure of Cash Flow Information		15
	Note 9. Commitments and Contingencies		15
	Note 10. Leases		15
Item 2.	Managements’ Discussion and Analysis of Financial Condition and Results of Operations		17

Item 4.	Controls and Procedures	21

~~PART II.~~	~~OTHER INFORMATION~~	22

~~Item 1.~~				~~Legal Proceedings~~	22PART II. OTHER INFORMATION

Item ~~1A.~~	~~Risk Factors~~1.	22Legal Proceedings		23
Item 6.	Exhibits		23

~~Item 6.~~	~~Exhibits~~	22Signatures

	~~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)~~Energy and providing electric service)
~~CDD~~Cooling degree day (CDD)	A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected ~~locations over a 30-year average.~~locations.
~~ECA~~CPCN	~~Energy Cost Adjustment - adjustments that allow us to pass the prudently-incurred cost~~Certificate of ~~fuel~~Public Convenience and ~~purchased energy through to customers.~~Necessity
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~~Heating degree day (HDD)	A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected ~~locations over a 30-year average.~~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
MWh	Megawatt-hours
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, which includes 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
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., an indirect, wholly-owned subsidiary of BHC
Wygen III	110 MW mine-mouth coal-fired power plant in which BHP owns a 52% interest, MDU owns a 25% interest and the City of Gillette owns the remaining 23% interest. BHP operates the plant.
Wyodak Plant	Wyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, owned 80% by Pacificorp and 20% by Black Hills Energy South Dakota. Our WRDC mine supplies all of the fuel for the plant.
Wyoming Electric	Includes Cheyenne Light’s electric utility operations

BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
(unaudited)	2018			2017			2018			2017			2019			2018			2019			2018
	(in thousands)												(in thousands)
Revenue	$	70,676		$	66,053		$	144,491		$	139,847		$	69,246		$	70,676		$	148,287		$	144,491

Operating expenses:
Fuel and purchased power	20,753			18,612			43,193			41,761			18,381			20,753			41,114			43,193
Operations and maintenance	18,428			18,888			37,579			35,842			21,128			18,428			40,685			37,579
Depreciation and amortization	9,866			8,831			19,750			17,525			10,357			9,866			20,434			19,750
Taxes - property	2,134			2,010			4,110			3,631			2,070			2,134			4,102			4,110
Total operating expenses	51,181			48,341			104,632			98,759			51,936			51,181			106,335			104,632

Operating income	19,495			17,712			39,859			41,088			17,310			19,495			41,952			39,859

Other income (expense):
Interest expense	(5,654		)	(5,635		)	(11,241		)	(11,390		)
AFUDC - borrowed	152			392			200			584
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums, and discounts)													(5,876		)	(5,654		)	(11,706		)	(11,241		)
Allowance for funds used during construction - borrowed													427			152			710			200
Interest income	123			243			238			369			172			123			287			238
AFUDC - equity	137			717			171			1,188
Other income (expense), net	(379		)	(69		)	(530		)	(122		)	291			(242		)	(84		)	(359		)
Total other income (expense)	(5,621		)	(4,352		)	(11,162		)	(9,371		)
Total other income (expense), net													(4,986		)	(5,621		)	(10,793		)	(11,162		)

Income before income taxes	13,874			13,360			28,697			31,717			12,324			13,874			31,159			28,697
Income tax expense	(2,749		)	(4,073		)	(5,812		)	(9,860		)	(2,176		)	(2,749		)	(5,514		)	(5,812		)
Net income	11,125			9,287			22,885			21,857			10,148			11,125			25,645			22,885

Other comprehensive income (loss):
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax (expense) benefit of $(5) and $(5) for the three months ended June 30, 2018 and 2017, and $(11) and $(11) for the six months ended June 30, 2018 and 2017, respectively)	11			11			21			21
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(9) and $(8) for the three months ended June 30, 2018 and 2017, and $(18) and $(15) for the six months ended June 30, 2018 and 2017, respectively)	17			14			34			28
Other comprehensive income	28			25			55			49
Other comprehensive income (loss), net of tax:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(7), $(5), $(7) and $(11), respectively)													25			11			25			21
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(2), $(9), $(6) and $(18), respectively)													14			17			26			34
Other comprehensive income (loss), net of tax													39			28			51			55

Comprehensive income	$	11,153		$	9,312		$	22,940		$	21,906		$	10,187		$	11,153		$	25,696		$	22,940

~~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)
ASSETS
Current assets:
Cash and cash equivalents $ 5
$ 16
Receivables - customers, net 29,556
29,050
Receivables - affiliates 5,426
5,664
Other receivables, net 1,536
196
Materials, supplies and fuel 24,165
23,443
Regulatory assets, current 18,290
18,993
Other current assets 3,462
4,528
Total current assets 82,440
81,890

Investments 4,991
4,926

Property, plant and equipment 1,331,257
1,311,819
Less accumulated depreciation and amortization (365,103 ) (358,946 )
Total property, plant and equipment, net 966,154
952,873

Other assets:
Regulatory assets, non-current 55,791
59,710
Other non-current assets 8,972
3,747
Total other assets 64,763
63,457
TOTAL ASSETS $ 1,118,348
$ 1,103,146

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

BLACK HILLS POWER, INC.

CONDENSED BALANCE SHEETS

As of
(unaudited) June 30, 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



	As of
(unaudited)	June 30, 2019			December 31, 2018
	(in thousands)
ASSETS
Current assets:
Cash	$	5		$	112
Accounts receivable, net	25,882			28,431
Accounts receivable from affiliates	5,102			8,119
Materials, supplies and fuel	25,313			24,853
Regulatory assets, current	22,339			19,052
Other current assets	4,460			4,538
Total current assets	83,101			85,105

Investments	4,846			4,889

Property, plant and equipment	1,428,721			1,381,045
Less: accumulated depreciation and amortization	(390,570		)	(376,160		)
Total property, plant and equipment, net	1,038,151			1,004,885

Other assets:
Regulatory assets, non-current	53,364			56,680
Other assets, non-current	26,284			9,729
Total other assets, non-current	79,648			66,409

TOTAL ASSETS	$	1,205,746		$	1,161,288

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~~BALANCE SHEETS

(Continued)

(unaudited) Six Months Ended June 30,
2018 2017
(in thousands)
Operating activities:
Net income $ 22,885
$ 21,857
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization 19,750
17,525
Deferred income tax (1,407 ) 1,605
Employee benefits 760
408
AFUDC (171 ) (1,188 )
Other adjustments, net 1,262
408
Change in operating assets and liabilities -
Accounts receivable and other current assets (1,494 ) 7,188
Accounts payable and other current liabilities 2,170
(3,486 )
Regulatory assets - current 2,797
(315 )
Regulatory liabilities - current 5,709
741
Other operating activities, net (458 ) 380
Net cash provided by (used in) operating activities 51,803
45,123

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

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

Net change in cash and cash equivalents (11 ) 922

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



	As of
(unaudited)	June 30, 2019			December 31, 2018
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	22,730		$	25,122
Accounts payable to affiliates	24,737			25,804
Accrued liabilities	38,159			34,193
Money pool notes payable	13,071			38,690
Notes payable to Parent	25,000			—
Regulatory liabilities, current	2,392			2,574
Total current liabilities	126,089			126,383

Long-term debt	340,105			340,035

Deferred credits and other liabilities:
Deferred income tax liabilities, net	117,272			114,009
Regulatory liabilities, non-current	162,104			160,642
Benefit plan liabilities	14,568			14,606
Other deferred credits and other liabilities	15,672			1,368
Total deferred credits and other liabilities	309,616			290,625

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	367,785			342,145
Accumulated other comprehensive loss	(840		)	(891		)
Total stockholder’s equity	429,936			404,245

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	1,205,746		$	1,161,288

~~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.

CONDENSED STATEMENTS OF CASH FLOWS



(unaudited)	Six Months Ended June 30,
	2019			2018
	(in thousands)
Operating activities:
Net income	$	25,645		$	22,885
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	20,434			19,750
Deferred income tax	2,004			(1,407		)
Employee benefits	389			760
Other adjustments, net	1,767			1,091
Change in operating assets and liabilities:
Accounts receivable and other current assets	4,841			(1,494		)
Accounts payable and other current liabilities	47			2,170
Regulatory assets - current	(2,037		)	2,797
Regulatory liabilities - current	(131		)	5,709
Other operating activities, net	(2,372		)	(458		)
Net cash provided by (used in) operating activities	50,587			51,803

Investing activities:
Property, plant and equipment additions	(49,387		)	(27,399		)
Proceeds from sale of assets	—			4,994
Other investing activities	(688		)	(4,961		)
Net cash provided by (used in) investing activities	(50,075		)	(27,366		)

Financing activities:
Change in money pool notes payable, net	(619		)	(24,448		)
Net cash provided by (used in) financing activities	(619		)	(24,448		)

Net change in cash	(107		)	(11		)

Cash, beginning of period	112			16
Cash, end of period	$	5		$	5

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.

CONDENSED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY



	Common Stock
(in thousands, except share amounts)	Shares	Value		Additional Paid in Capital		Retained Earnings			AOCI			Total
December 31, 2018	23,416,396	$	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 ASC 842 implementation	—	—		—		(7		)	—			(7		)
Other adjustments	—	—		—		1			—			1
March 31, 2019	23,416,396	$	23,416	$	39,575	$	357,636		$	(879	)	$	419,748
Net income (loss) available for common stock	—	—		—		10,148			—			10,148
Other comprehensive income (loss), net of tax	—	—		—		—			39			39
Other adjustments	—	—		—		1			—			1
June 30, 2019	23,416,396	$	23,416	$	39,575	$	367,785		$	(840	)	$	429,936



	Common Stock
(in thousands except share amounts)	Shares	Value		Additional Paid in Capital		Retained Earnings			AOCI			Total
December 31, 2017	23,416,396	$	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
Dividend to Parent company	—	—		—		(16,000		)	—			(16,000		)
Other adjustments	—	—		—		1			—			1
March 31, 2018	23,416,396	$	23,416	$	39,575	$	328,260		$	(1,231	)	$	390,020
Net income (loss) available for common stock	—	—		—		11,125			—			11,125
Other comprehensive income (loss), net of tax	—	—		—		—			28			28
Dividend to Parent company	—	—		—		(10,000		)	—			(10,000		)
June 30, 2018	23,416,396	$	23,416	$	39,575	$	329,385		$	(1,203	)	$	391,173

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)(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 June 30, 2019, December 31, 2018 and June 30, 2018, ~~December 31, 2017~~ ~~and~~ ~~June 30, 2017~~ financial information and are of a normal recurring nature. The results of operations for the three and six months ended June 30, 2019 and June 30, 2018, ~~and~~ ~~June 30, 2017~~, and our financial condition as of June 30, ~~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 Accounting Standards

Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, ASU 2018-19

In June 2016, the FASB issued ASU 2016-13, Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, which was subsequently amended by ASU 2018-19 in November 2018. The standard introduces new accounting guidance for credit losses on financial instruments within its scope, including trade receivables. This new guidance adds an impairment model that is based on expected losses rather than incurred losses. It is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. We are currently assessing the impacts of adopting this standard.

Recently Adopted 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~~increase transparency and comparability among organizations by requiring the recognition 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. ~~In addition,~~Under the ~~definition~~new standard, disclosures are required to meet the objective of ~~a lease has been revised in regards~~enabling users of financial statements to ~~when an arrangement conveys~~assess the ~~right to control the use~~amount, timing and uncertainty 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 arising from leases.

We adopted the ~~previous accounting standard. Lessors’ accounting under~~standard effective January 1, 2019. We elected 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 earliestoption to not recast comparative ~~period~~periods 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~~transitioning 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~~and will report these comparative periods as presented under previous lease guidance. In addition, we elected the ~~new lease standard. The FASB also issued additional amendments to~~package of practical expedients permitted under the ~~new lease standard in July 2018, ASU No. 2018-11, allowing companies to adopt~~transition guidance with the new standard, ~~with a cumulative effect adjustment~~which among other things, allowed us to carry forward the historical lease classification. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment of existing land easement 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 ~~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~~The lease standard did not ~~previously accounted for as a lease, we anticipate electing the practical expedient which provides for~~materially impact our net earnings and had no assessment of these easements. Further, we anticipate adopting the new standard with a cumulative effect adjustment with prior year comparative financial information remaining as previously reported when transitioning to the new standard. The standard also provides a transition practical expedient, commonly referred to as the “package of three”, that must be taken together and allows entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. We expect to elect the “package of three” practical expedient. We continue to evaluate the additional transition practical expedients available under the guidance and the impact ~~of this new standard~~ on ~~our financial position, results of operations and~~ cash flows. We are finalizing the process of identifying and categorizing our lease contracts and evaluating our current business processes relating to leases. We have selected and configured a new lease software solution that we are currently testing. We also continue to monitor utility industry lease implementation guidance that may change existing and future lease classification.

(2) REVENUE

~~Recently Adopted Accounting Standards~~

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

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

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

~~Effective January 1, 2018, we adopted ASU 2017-07,~~ ~~Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost~~. The standard requires employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets was applied on a prospective basis for the six months ended June 30, 2018. Retrospective impact was not material and therefore not adjusted. For our rate-regulated entities, we capitalize the other components of net periodic benefit costs into regulatory assets or 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.~~three and six months ended June 30, 2019 and 2018. Sales tax and other similar taxes are excluded from revenues.



	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		Six Months Ended June 30, 2018
	(in thousands)
Customer types:
Retail	$	46,809	$	46,525	$	99,885	$	97,166
Wholesale	6,780		8,191		15,123		17,241
Market - off-system sales	2,393		3,449		7,063		5,724
Transmission/Other	13,083		12,372		25,914		24,090
Revenue from contracts with customers	69,065		70,537		147,985		144,221
Other revenues	181		139		302		270
Total revenues	$	69,246	$	70,676	$	148,287	$	144,491

Timing of revenue recognition:
Services transferred over time	$	69,065	$	70,537	$	147,985	$	144,221
Revenue from contracts with customers	$	69,065	$	70,537	$	147,985	$	144,221

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

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

The majority of the our revenue contracts are based on variable quantities delivered; any fixed consideration contracts with an expected duration of one year or more are immaterial to our revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer.

~~Revenue Not in Scope of ASC 606~~

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

~~Significant Judgments and Estimates~~

~~TCJA revenue reserve~~

The TCJA or “tax reform”, signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21% effective for tax years beginning after December 31, 2017. We have been collaborating with our regulators in the states in which we provide utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We estimated and recorded a revenue reserve of approximately $2.6 million and $5.7 million during the three and six months ended June 30, 2018.

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

~~Unbilled Revenue~~

Revenues attributable to energy delivered to customers but not yet billed are estimated and accrued, and the related costs are charged to expense. Factors influencing the determination of unbilled revenues may include estimates of delivered sales volumes based on weather information and customer consumption trends.

Contract Balances

The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts ~~Receivable~~receivable and is further discussed in Note ~~1 of our Notes to the Financial Statements of our~~ ~~2017~~ ~~Annual Report on Form 10-K Business Description.~~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) (3)	ACCOUNTS RECEIVABLE

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



	June 30, 2019			December 31, 2018
Accounts receivable trade	$	15,972		$	16,236
Unbilled revenues	10,110			12,333
Allowance for doubtful accounts	(200		)	(138		)
Accounts receivable, net	$	25,882		$	28,431

June 30, 2018 December 31, 2017
Accounts receivable trade $ 17,471
$ 15,994
Unbilled revenues 12,270
13,280
Allowance for doubtful accounts (185 ) (224 )
Receivables - customers, net $ 29,556
$ 29,050


(4) (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:



	June 30, 2019			December 31, 2018
Regulatory assets:
Loss on reacquired debt ^(a)	$	1,124		$	1,259
Deferred taxes on AFUDC ^(b)	4,955			5,020
Employee benefit plans and related deferred taxes ^(c)	20,022			19,868
Deferred energy and fuel cost adjustments^(b)	22,195			20,334
Deferred taxes on flow through accounting^(c)	9,201			8,749
Decommissioning costs ^(a)	7,168			8,196
Vegetation management ^(a)	9,214			10,366
Other regulatory assets ^(a)	1,824			1,940
Total regulatory assets	$	75,703		$	75,732
Less current regulatory assets	(22,339		)	(19,052		)
Regulatory assets, non-current	$	53,364		$	56,680

Maximum Amortization
(in years)
June 30, 2018 December 31, 2017
Regulatory assets:
Unamortized loss on reacquired debt ^(a)
7 $ 1,393
$ 1,534
Deferred taxes on AFUDC ^(b)
45 5,038
5,095
Employee benefit plans^(c)

12 19,665
19,465
Deferred energy and fuel cost adjustments^(a)
1 16,923
19,602
Deferred taxes on flow through accounting 54 8,137
7,579
Decommissioning costs, net of amortization 5 9,224
10,252
Vegetation management, net of amortization 5 11,518
12,669
Other regulatory assets ^(a)
5 2,183
2,507
Total regulatory assets $ 74,081
$ 78,703



Regulatory liabilities:
Cost of removal for utility plant ^(a)	$	54,947		$	52,366
Employee benefit plan costs and related deferred taxes ^(c)	7,518			7,518
Excess deferred income taxes ^(c)	99,417			100,276
TCJA revenue reserve	2,392			2,523
Other regulatory liabilities^(c)	222			533
Total regulatory liabilities	$	164,496		$	163,216
Less current regulatory liabilities	(2,392		)	(2,574		)
Regulatory liabilities, non-current	$	162,104		$	160,642

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

____________________


(a)	We are allowed a recovery of costs, but we are not allowed a rate of return.


(b)	In addition to recovery of costs, we are allowed a rate of return.


(c)	In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base.


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

Regulatory Matters

~~Except as discussed below, there~~

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.~~10-K except as reported below.

~~On April 30, 2018 Black Hills~~Renewable Ready Service Tariffs and Corriedale Wind Energy Project

South Dakota Electric and Wyoming Electric received approvals for the ~~SDPUC staff signed an amendment~~Renewable Ready Service Tariffs and related jointly-filed CPCN to construct the ~~stipulation executed in June 2017.~~$57 million, 40 MW Corriedale Wind Energy Project. The ~~amendment provides clarifying language to certain provisions from the stipulation specific to the TCJA and performance based rates. The amendment was approved~~wind project will be jointly owned 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 servicetwo electric utilities to deliver renewable energy for large commercial and industrial customers and governmental agencies. The project is expected to ~~customers the benefits of a lower corporate federal income tax rate beginning~~be 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.~~service in 2020.

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


(5)	RELATED-PARTY TRANSACTIONS

~~Non-Cash~~ Dividend to Parent

We did not record any dividends for the six months ended June 30, 2019. We recorded non-cash dividends to our Parent of $26 million and ~~$16 million for six months ended June 30, 2018 and June 30, 2017, respectively, and changed~~decreased the utility Money pool note receivable by $26 ~~million and $16~~ million for the six months ended June 30, ~~2018 and June 30, 2017, respectively.~~2018.

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, 2019		December 31, 2018
Accounts receivable from affiliates	$	5,102	$	8,119
Accounts payable to affiliates	$	24,737	$	25,804

June 30, 2018 December 31, 2017
Receivables - affiliates $ 5,426
$ 5,664
Accounts payable - affiliates $ 25,185
$ 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 30, ~~2018~~,2019, the average cost of borrowing under the Utility Money Pool was ~~2.49%~~2.78%.

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

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

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Net interest income (expense)	$	(198	)	$	(96	)	$	(471	)	$	(132	)

Notes payable to Parent

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

(a) Note bears interest at 4.51%, expires December 31, 2019, and is eligible for annual renewal. Interest payable related to this note was $0.2 million as of June 30, 2019.

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Revenue:
Energy sold to Cheyenne Light	$	340	$	501	$	914	$	1,204
Rent from electric properties	$	895	$	908	$	1,791	$	1,817
Horizon Point shared facility revenues	$	3,006	$	2,783	$	6,013	$	5,552

Fuel and purchased power:
Purchases of coal from WRDC	$	3,216	$	4,249	$	7,873	$	8,316
Purchase of excess energy from Cheyenne Light	$	41	$	82	$	173	$	168
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	342	$	381	$	877	$	1,022
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	611	$	696	$	1,594	$	1,789
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	75	$	96	$	151	$	192

Operations and maintenance:
Corporate support services and fees from Black Hills Service Company ^(a)	$	9,451	$	7,604	$	19,642	$	15,210
Wygen III ground lease with WRDC	$	247	$	241	$	493	$	481

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

Fuel and purchased power:

Purchases of coal from WRDC $ 4,249
$ 3,052
$ 8,316
$ 7,332
Purchase of excess energy from Cheyenne Light $ 82
$ 76
$ 168
$ 116
Purchase of renewable wind energy from Cheyenne Light - Happy Jack $ 381
$ 369
$ 1,022
$ 975
Purchase of renewable wind energy from Cheyenne Light - Silver Sage $ 696
$ 637
$ 1,789
$ 1,656

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

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

~~____________________~~


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

~~Horizon Point Agreement~~

~~We have a shared facility agreement~~ among South Dakota Electric, Black Hills Service Company, and Black Hills Utility Holdings where there is a cost allocation for the use of the Horizon Point facility that is owned by South Dakota Electric. This cost allocation includes the recovery of and return on allocable property and recovery of incurred administrative(a) Increase in 2019 was primarily due to higher outside service expenses ~~for the operation~~ and ~~maintenance of the Horizon Point facility.~~higher employee costs driven by labor and benefits.


(6) (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,
	2019			2018			2019			2018
Service cost	$	92		$	129		$	183		$	258
Interest cost	602			549			1,205			1,097
Expected return on plan assets	(852		)	(887		)	(1,703		)	(1,773		)
Prior service cost	3			11			5			22
Net loss (gain)	305			516			610			1,032
Net periodic benefit cost	$	150		$	318		$	300		$	636

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

Defined Benefit Postretirement Healthcare Plan

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Service cost	$	37		$	49		$	74		$	97
Interest cost	46			44			93			89
Prior service cost (benefit)	(84		)	(84		)	(168		)	(168		)
Net periodic benefit cost	$	(1	)	$	9		$	(1	)	$	18

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

Supplemental Non-qualified Defined Benefit Plans

The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit Plans were as follows (in thousands):



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Interest cost	$	28	$	27	$	57	$	54
Net loss (gain)	17		26		33		52
Net periodic benefit cost	$	45	$	53	$	90	$	106

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

For the three and six months ended June 30, 2018, service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other income (expense), net on the Condensed Statements of Comprehensive Income. For the three and six months ended June 30, 2017, service costs and non-service costs were recorded in Operations and maintenance expense. Because prior years’ costs were not considered material, they were not reclassified on the Condensed Statements of Comprehensive Income. See Note 1 for additional information.

Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust 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):



	Contributions Six Months Ended June 30, 2019		Remaining Anticipated Contributions for 2019		Anticipated Contributions for 2020
Defined Benefit Pension Plan	$	—	$	1,753	$	1,841
Defined Benefit Postretirement Healthcare Plan	$	233	$	233	$	466
Supplemental Non-qualified Defined Benefit Plans	$	115	$	115	$	240

Contributions
Six Months Ended
June 30, 2018
Remaining Anticipated Contributions for 2018 Anticipated Contributions for 2019
Defined Benefit Pension Plan $ —
$ 1,795
$ 1,789
Defined Benefit Postretirement Healthcare Plan $ 267
$ 267
$ 554
Supplemental Non-qualified Defined Benefit Plans $ 123
$ 123
$ 241


(7)	FAIR VALUE OF FINANCIAL INSTRUMENTS

~~Fair value is defined as~~Financial instruments for which the ~~price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at~~carrying amount did not equal 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
Carrying Amount Fair Value Carrying Amount Fair Value
Cash and cash equivalents ^(a)
$ 5
$ 5
$ 16
$ 16
Long-term debt, including current maturities ^{(b) (c)}
$ 339,965
$ 418,410
$ 339,895
$ 446,978



	June 30, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current maturities ^{(a) (b)}	$	340,105	$	447,036	$	340,035	$	412,894

_________________


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


(8)	SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION



	Six Months Ended June 30,
	2019			2018
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	15,316		$	7,477
Non-cash (decrease) to money pool notes receivable, net	$	—		$	(26,000	)
Non-cash dividend to Parent	$	—		$	26,000

Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(11,342	)	$	(10,930	)

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

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


(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.


(10)	~~INCOME TAXES~~LEASES

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. The Company remeasured deferred income taxes at the 21% federal tax rate as of December 31, 2017. We have ~~made our best estimate regarding~~a ground lease for the ~~probability~~Wygen III generating facility with an affiliate and communication tower site and operation center facility leases with third parties. Our leases have remaining terms ranging from less than one year to 30 years.

The components of settlements of net regulatory liabilities established pursuant to the TCJA. The amount of the settlements may change based on decisions and actions by the rate regulators, which could have a material impact on the Company’s future results of operations, cash flows or financial position. We revalued our deferred tax assets and liabilitieslease expense were as of December 31, 2017, which reflected our estimate of the impact of the TCJA. We will continue to evaluate subsequent regulations, clarifications and interpretations with the assumptions made, which could materially change our estimate.follows (in thousands):



	Income Statement Location	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Operating lease cost	Operations and maintenance	$	228	$	456
Variable lease cost	Operations and maintenance	39		82
Total lease cost		$	267	$	538

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



	Balance Sheet Location	As of June 30, 2019
Assets:
Operating lease assets	Other assets, non-current	$	14,244
Total lease assets		$	14,244

Liabilities:
Current:
Operating leases	Accrued liabilities	$	268

Noncurrent:
Operating leases	Other deferred credits and other liabilities	13,993
Total lease liabilities		$	14,261

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



	Six Months Ended June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	451
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	—



	As of June 30, 2019
Weighted average remaining lease term (years):
Operating leases	30 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)	$	463
2020	856
2021	856
2022	856
2023	853
Thereafter	21,947
Total lease payments	$	25,831
Less imputed interest	11,570
Present value of lease liabilities	$	14,261


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

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 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,~~23, 2019, Fitch affirmed South Dakota Electric’s credit rating at A.

South Dakota Electric and Wyoming Electric received approvals for the Renewable Ready Service Tariffs and related jointly-filed CPCN to construct the $57 million, 40-megawatt Corriedale Wind Energy Project. The wind project will be jointly owned by the two electric utilities to deliver renewable energy for large commercial and industrial customers and governmental agencies. The project is expected to be in service in 2020.

South Dakota Electric continued construction on a 175-mile electric transmission line from Stegall, Nebraska to Rapid City, South Dakota. The 94-mile final segment of the transmission line is expected to be in service in the fall of 2019.

On April 30, 2019, S&P 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 purchased power, ~~purchases,~~ natural gas and other fuel supply costs. However, while these fluctuating costs impact gross margin as a percentage of revenue, they only impact total gross margin if the costs cannot be passed through to our customers.

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

The following tables provide certain financial information and operating statistics:


	Three Months Ended June 30,									Six Months Ended June 30,									Three Months Ended June 30,									Six Months Ended June 30,
	2018			2017			Variance			2018			2017			Variance			2019			2018			Variance			2019			2018			Variance
	(in thousands)																		(in thousands)
Revenue	$	70,676		$	66,053		$	4,623		$	144,491		$	139,847		$	4,644		$	69,246		$	70,676		$	(1,430	)	$	148,287		$	144,491		$	3,796
Fuel and purchased power	20,753			18,612			2,141			43,193			41,761			1,432			18,381			20,753			(2,372		)	41,114			43,193			(2,079		)
Gross margin ^(a)	49,923			47,441			2,482			101,298			98,086			3,212
Gross margin (non-GAAP)																			50,865			49,923			942			107,173			101,298			5,875

Operating expenses	30,428			29,729			699			61,439			56,998			4,441			33,555			30,428			3,127			65,221			61,439			3,782
Operating income	19,495			17,712			1,783			39,859			41,088			(1,229		)	17,310			19,495			(2,185		)	41,952			39,859			2,093

Interest income (expense), net	(5,379		)	(5,000		)	(379		)	(10,803		)	(10,437		)	(366		)	(5,277		)	(5,379		)	102			(10,709		)	(10,803		)	94
Other income (expense), net	(242		)	648			(890		)	(359		)	1,066			(1,425		)	291			(242		)	533			(84		)	(359		)	275
Income tax expense	(2,749		)	(4,073		)	1,324			(5,812		)	(9,860		)	4,048			(2,176		)	(2,749		)	573			(5,514		)	(5,812		)	298
Net income	$	11,125		$	9,287		$	1,838		$	22,885		$	21,857		$	1,028		$	10,148		$	11,125		$	(977	)	$	25,645		$	22,885		$	2,760

~~________________~~


~~(a)~~	~~Non-GAAP measure~~

~~Three~~

Six Months Ended June 30, ~~2018~~2019 Compared to ~~Three~~Six Months Ended June 30, ~~2017.~~2018. Net income was ~~$11~~$26 million compared to ~~$9.3~~$23 million for the same period in the prior year primarily due to the following:

Gross margin increased primarily due to a $3.2 million reduction in the purchased power capacity charges and higher rider revenues of $1.4 million related to transmission investment recovery. Higher power marketing revenue, customer growth, and favorable weather, comprised the remainder of the increase.

Operating expenses increased primarily due to higher non-energy revenue of $2.4 million primarily related to Horizon Point shared facility revenue, higher commercial and industrial demand of $0.9 million, a $0.8 million increase in residential margins primarily from warmer weather in the current year,outside services expenses and higher ~~rider revenues of $1.0 million primarily related to transmission investment recovery. These increases were~~employee costs driven by increased headcount partially offset by a ~~$2.6 million reserve to revenue to reflect the reduction of the lower federal income tax rate from the TCJA on our existing rate tariffs.~~

~~Operating~~decrease in expenses ~~increased primarily~~ due to ~~increased depreciation from higher asset base driven by the prior year additions of Horizon Point and the Teckla-Lange transmission line.~~generation outages.

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

~~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:~~

~~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.

~~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										Electric Revenue by Customer Type
	Three Months Ended June 30,					Six Months Ended June 30,					Three Months Ended June 30,					Six Months Ended June 30,
	(in thousands)										(in thousands)
	2018		Percentage Change	2017		2018		Percentage Change	2017		2019		Percentage Change	2018		2019		Percentage Change	2018
Residential	$	16,426	5%	$	15,633	$	37,487	5%	$	35,704	$	15,570	(5)%	$	16,426	$	36,760	(2)%	$	37,487
Commercial	23,538		3%	22,858		47,082		—%	47,149		22,131		(6)%	23,538		45,275		(4)%	47,082
Industrial	8,170		—%	8,171		16,446		(1)%	16,625		8,576		5%	8,170		16,933		3%	16,446
Municipal	876		(7)%	942		1,687		(5)%	1,778		776		(11)%	876		1,557		(8)%	1,687
Total retail revenue	49,010		3%	47,604		102,702		1%	101,256		47,053		(4)%	49,010		100,525		(2)%	102,702
Wholesale ^(a)	8,191		22%	6,702		17,241		19%	14,545		6,780		(17)%	8,191		15,123		(12)%	17,241
Market - off-system sales ^(b)	3,449		42%	2,424		5,724		(9)%	6,257		2,393		(31)%	3,449		7,063		23%	5,724
Other revenue(c)	10,026		8%	9,323		18,824		6%	17,789		13,020		30%	10,026		25,576		36%	18,824
Total revenue	$	70,676	7%	$	66,053	$	144,491	3%	$	139,847	$	69,246	(2)%	$	70,676	$	148,287	3%	$	144,491

____________________


(a)	~~Increase~~Decrease for the ~~three and~~ six months ended June 30, ~~2018~~2019 was primarily driven by ~~increased volumes on long term wholesale contracts.~~


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

Megawatt Hours Sold by Customer Type
Three Months Ended June 30, Six Months Ended June 30,
2018 Percentage Change 2017 2018 Percentage Change 2017
Residential 115,905
8% 107,521
279,018
9% 257,093
Commercial 186,784
8% 173,720
381,715
3% 370,126
Industrial 106,100
3% 103,497
210,402
(1)% 213,293
Municipal 7,479
(8)% 8,104
14,982
(5)% 15,709
Total retail quantity sold 416,268
6% 392,842
886,117
3% 856,221
Wholesale ^(a)
218,132
31% 165,881
455,836
29% 351,997
Market - off-system sales ^(b)
141,866
38% 102,966
233,968
(9)% 257,462
Total quantity sold 776,266
17% 661,689
1,575,921
8% 1,465,680
Losses and company use ^(c)
61,677
8% 57,189
90,199
(9)% 99,030
Total energy 837,943
17% 718,878
1,666,120
6% 1,564,710

~~____________________~~


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


(b)	Increase for ~~three~~the six months ended June 30, ~~2018~~2019 was ~~due to improved pricing in markets compared to same period in prior year.~~driven by weather and energy prices.


(c)	Increase for the six months ended June 30, 2019 was primarily due to the prior year reserve to revenue to reflect the reduction of the lower federal income tax rate from the TCJA on our existing rate tariffs.



	Megawatt Hours Sold by Customer Type
	Three Months Ended June 30,			Six Months Ended June 30,
	2019	Percentage Change	2018	2019	Percentage Change	2018
Residential	114,399	(1)%	115,905	284,335	2%	279,018
Commercial	180,966	(3)%	186,784	375,760	(2)%	381,715
Industrial	112,623	6%	106,100	220,819	5%	210,402
Municipal	6,756	(10)%	7,479	14,329	(4)%	14,982
Total retail quantity sold	414,744	—%	416,268	895,243	1%	886,117
Wholesale	194,222	(11)%	218,132	417,242	(8)%	455,836
Market - off-system sales	113,014	(20)%	141,866	212,586	(9)%	233,968
Total quantity sold	721,980	(7)%	776,266	1,525,071	(3)%	1,575,921
Losses and Company use ^(a)	35,660	(42)%	61,677	77,570	(14)%	90,199
Total energy	757,640	(10)%	837,943	1,602,641	(4)%	1,666,120

____________________


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


	Megawatt Hours Generated and Purchased						Megawatt Hours Generated and Purchased
	Three Months Ended June 30,			Six Months Ended June 30,			Three Months Ended June 30,			Six Months Ended June 30,
Generated -	2018	Percentage Change	2017	2018	Percentage Change	2017	2019	Percentage Change	2018	2019	Percentage Change	2018
Coal-fired ^(a)	388,081	34%	289,540	787,168	16%	677,525	287,201	(26)%	388,081	696,867	(11)%	787,168
Natural Gas and Oil ^(b)	23,758	116%	11,024	36,865	72%	21,374	28,724	21%	23,758	76,427	107%	36,865
Total generated	411,839	37%	300,564	824,033	18%	698,899	315,925	(23)%	411,839	773,294	(6)%	824,033

Total purchased	426,104	2%	418,314	842,087	(3)%	865,811	441,715	4%	426,104	829,347	(2)%	842,087
Total generated and purchased	837,943	17%	718,878	1,666,120	6%	1,564,710	757,640	(10)%	837,943	1,602,641	(4)%	1,666,120

____________________

(a) ~~Increase~~Decrease for the ~~three and~~ six months ended June 30, ~~2018 compared~~2019 is due to ~~same periods in prior year is driven primarily by~~ planned outages at Neil Simpson II ~~Wyodak,~~ and Wygen ~~II in 2017.~~III and unplanned outages at Wyodak Plant.

(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.~~2019.


	Power Plant Availability								Power Plant Availability
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017		2019		2018		2019		2018
Coal-fired plants ^(a)	91.3	%	67.6	%	92.1	%	78.4	%	71.9	%	91.3	%	85.0	%	92.1	%
Other plants(b)	97.5	%	98.0	%	98.4	%	98.7	%	79.7	%	97.5	%	83.5	%	98.4	%
Total availability	94.6	%	83.7	%	95.5	%	89.2	%	76.0	%	94.6	%	84.2	%	95.5	%

____________________


(a)	~~2017~~2019 included planned outages at Neil Simpson II ~~Wyodak~~ and Wygen ~~II.~~III unplanned outages at Wyodak Plant, and 2018 included planned outages at Neil Simpson II and Wyodak Plant.


(b)	2019 included planned outages at Neil Simpson CT and Lange CT.


	Degree Days						Degree Days						Degree Days						Degree Days
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017			2019			2018			2019			2018
	Actual	Variance from 30-year Average		Actual	Variance from 30-year Average		Actual	Variance from 30-year Average		Actual	Variance from 30-year Average		Actual	Variance from Normal		Actual	Variance from Normal		Actual	Variance from Normal		Actual	Variance from Normal

Heating degree days	1,037	1	%	910	(11	)%	4,736	12	%	4,040	(5	)%	1,279	25	%	1,037	1	%	5,195	23	%	4,736	12	%
Cooling degree days	132	33	%	114	15	%	132	33	%	114	15	%	38	(62	)%	132	33	%	38	(62	)%	132	33	%

Credit Ratings

Credit ratings impact our ability to obtain short and long-term financing, the cost of such financing, and vendor payment terms, including collateral requirements. The following table represents our secured credit rating from each agency’s review which was in effect at June 30, ~~2018:~~2019:



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

__________


(a)	On April 30, 2019, S&P affirmed A rating.


(b)	On December 12, 2018, Moody’s affirmed A1 rating.


(c)	On July ~~19, 2018,~~23, 2019, 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~~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 June 30, ~~2018.~~2019. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective as of June 30, ~~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 June 30, ~~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.

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.~~


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~~101.INS	~~Financial Statements for~~ XBRL ~~Format~~Instance Document - the instance document does not appear in the Interactive Data File because its XBRL 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.

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: August ~~7, 2018~~6, 2019

2324



	Maximum Amortization (in years)	June 30, 2018		December 31, 2017
Regulatory assets:
Unamortized loss on reacquired debt ^(a)	7	$	1,393	$	1,534
Deferred taxes on AFUDC ^(b)	45	5,038		5,095
Employee benefit plans^(c)	12	19,665		19,465
Deferred energy and fuel cost adjustments^(a)	1	16,923		19,602
Deferred taxes on flow through accounting	54	8,137		7,579
Decommissioning costs, net of amortization	5	9,224		10,252
Vegetation management, net of amortization	5	11,518		12,669
Other regulatory assets ^(a)	5	2,183		2,507
Total regulatory assets		$	74,081	$	78,703



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



	June 30, 2018		December 31, 2017
Receivables - affiliates	$	5,426	$	5,664
Accounts payable - affiliates	$	25,185	$	25,653



	Contributions Six Months Ended June 30, 2018		Remaining Anticipated Contributions for 2018		Anticipated Contributions for 2019
Defined Benefit Pension Plan	$	—	$	1,795	$	1,789
Defined Benefit Postretirement Healthcare Plan	$	267	$	267	$	554
Supplemental Non-qualified Defined Benefit Plans	$	123	$	123	$	241

June 30, 2019

December 31, 2018

Money pool notes payable