UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



x☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended	September 30, ~~2017~~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
~~625 Ninth Street~~7001 Mount Rushmore Road	Rapid City		South Dakota	57702
~~Rapid City, South Dakota 57701~~
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 October 31, ~~2017,~~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 Income and Comprehensive Income - unaudited~~	4
	~~Three and Nine Months Ended September 30, 2017 and 2016~~ Condensed Statements of Comprehensive Income		4

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

	Condensed Statements of Cash Flows ~~- unaudited~~		7
	~~Nine Months Ended September 30, 2017 and 2016~~ 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		1517
Item 4.	Controls and Procedures		21

~~Item 4.~~				~~Controls and Procedures~~	19PART II. OTHER INFORMATION

~~PART II.~~	~~OTHER INFORMATION~~	20

Item 1.	Legal Proceedings		2022
Item 6.	Exhibits		22

~~Item 1A.~~	~~Risk Factors~~	20Signatures

~~Item 6.~~	~~Exhibits~~	20

	~~Signatures~~	2123

GLOSSARY OF TERMS AND ABBREVIATIONS

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



AFUDC	Allowance for Funds Used During Construction
ASC	Accounting Standards Codification
ASU	Accounting Standards Update issued by the FASB
BHC	Black Hills Corporation; the Parent Company
Black Hills Energy	The name used to conduct the business of BHC utility companies
Black Hills ~~Utility Holdings~~	~~Black Hills Utility Holdings, Inc. a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)~~
~~Black Hills~~ Service Company	Black Hills Service Company, LLC, a direct, wholly-owned subsidiary of BHC
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills ~~Energy)~~Energy and providing electric service)
Cooling ~~Degree Day~~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.
~~DSM~~CPCN	~~Demand Side Management~~
~~ECA~~	~~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
~~Global Settlement~~	~~Settlement with a utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders.~~
Happy Jack	Happy Jack Wind Farms, LLC, a subsidiary of Duke Energy Generation Services
Heating degree day (HDD)	A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected ~~locations over a 30-year average.~~locations.
kVHorizon Point	~~Kilovolt~~BHC Corporate headquarters building in Rapid City, South Dakota, which was completed in 2017.
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
~~SourceGas~~	SourceGas Holdings LLC and its subsidiaries, a gas utility owned by funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) that was acquired by BHC on February 12, 2016, and is now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy)
South Dakota Electric	~~Includes~~ Black Hills Power, which includes operations in South Dakota, Wyoming and Montana
S&P	Standard & Poor’s, a division of The McGraw-Hill Companies, Inc.
~~TCA~~TCJA	~~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.~~Tax Cuts and Jobs Act enacted December 22, 2017
~~Winter Storm Atlas~~WPSC	~~An October 2013 blizzard that impacted South Dakota Electric. It was the second most severe blizzard in Rapid City’s history.~~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 South Dakota Electric. 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 ~~INCOME AND~~ COMPREHENSIVE INCOME


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
(unaudited)	2017			2016			2017			2016			2019			2018			2019			2018
	(in thousands)												(in thousands)
Revenue	$	73,938		$	66,728		$	213,785		$	197,389		$	77,022		$	78,067		$	225,309		$	222,558

Operating expenses:
Fuel and purchased power	22,843			18,421			64,604			55,375			21,805			25,207			62,919			68,400
Operations and maintenance	16,747			15,601			52,589			49,538			20,885			19,851			61,570			57,430
Depreciation and amortization	9,053			8,547			26,578			25,363			10,328			9,950			30,762			29,700
Taxes - property	1,597			1,749			5,228			4,987			2,000			1,631			6,102			5,741
Total operating expenses	50,240			44,318			148,999			135,263			55,018			56,639			161,353			161,271

Operating income	23,698			22,410			64,786			62,126			22,004			21,428			63,956			61,287

Other income (expense):
Interest expense	(5,483		)	(5,454		)	(16,873		)	(16,322		)
AFUDC - borrowed	369			319			953			840
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums, and discounts)													(6,101		)	(5,632		)	(17,807		)	(16,873		)
Allowance for funds used during construction - borrowed													456			199			1,166			399
Interest income	335			510			704			1,004			316			250			603			488
AFUDC - equity	676			606			1,864			1,595
Other income (expense), net	3			48			(119		)	75			112			(247		)	28			(606		)
Total other income (expense)	(4,100		)	(3,971		)	(13,471		)	(12,808		)
Total other income (expense), net													(5,217		)	(5,430		)	(16,010		)	(16,592		)

Income before income taxes	19,598			18,439			51,315			49,318			16,787			15,998			47,946			44,695
Income tax expense	(5,772		)	(6,429		)	(15,632		)	(16,316		)	(3,044		)	(2,681		)	(8,558		)	(8,493		)
Net income	13,826			12,010			35,683			33,002			13,743			13,317			39,388			36,202

Other comprehensive income (loss):
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax (expense) benefit of $(6) and $(6) for the three months ended September 30, 2017 and 2016, and $(17) and $(17) for the nine months ended September 30, 2017 and 2016, respectively)	10			10			31			31
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(8) and $(8) for the three months ended September 30, 2017 and 2016 and $(23) and $(21) for the nine months ended September 30, 2017 and 2016, respectively)	14			14			42			41
Other comprehensive income	24			24			73			72
Other comprehensive income (loss), net of tax:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(3), $(6), $(10) and $(17), respectively)													13			10			38			31
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(3), $(9), $(10) and $(27), respectively)													12			17			38			51
Other comprehensive income (loss), net of tax													25			27			76			82

Comprehensive income	$	13,850		$	12,034		$	35,756		$	33,074		$	13,768		$	13,344		$	39,464		$	36,284

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

~~BLACK HILLS POWER, INC.~~

~~CONDENSED BALANCE SHEETS~~

(unaudited) September 30, 2017 December 31, 2016
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 1,171
$ 234
Receivables - customers, net 27,579
30,614
Receivables - affiliates 5,498
9,526
Other receivables, net 335
351
Money pool notes receivable, net 8,881
28,409
Materials, supplies and fuel 23,622
22,389
Regulatory assets, current 18,819
18,119
Other, current assets 3,432
3,876
Total current assets 89,337
113,518

Investments 4,902
4,841

Property, plant and equipment 1,298,855
1,236,387
Less accumulated depreciation and amortization (354,788 ) (338,828 )
Total property, plant and equipment, net 944,067
897,559

Other assets:
Regulatory assets, non-current 73,178
74,015
Other, non-current assets 3,545
3,816
Total other assets 76,723
77,831
TOTAL ASSETS $ 1,115,029
$ 1,093,749

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

BLACK HILLS POWER, INC.

CONDENSED BALANCE SHEETS

(unaudited) September 30, 2017 December 31, 2016
(in thousands, except common stock par value and share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable $ 14,701
$ 14,158
Accounts payable - affiliates 26,828
31,799
Accrued liabilities 50,337
37,436
Regulatory liabilities, current 825
84
Total current liabilities 92,691
83,477

Long-term debt 339,860
339,756

Deferred credits and other liabilities:
Deferred income tax liability, net, non-current 220,857
211,443
Regulatory liabilities, non-current 55,822
53,866
Benefit plan liabilities 15,721
19,544
Other, non-current liabilities 1,393
1,001
Total deferred credits and other liabilities 293,793
285,854

Commitments and contingencies (Notes 4, 5 and 8)

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 326,883
322,933
Accumulated other comprehensive loss (1,189 ) (1,262 )
Total stockholder’s equity 388,685
384,662
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY $ 1,115,029
$ 1,093,749



	As of
(unaudited)	September 30, 2019			December 31, 2018
	(in thousands)
ASSETS
Current assets:
Cash	$	5		$	112
Accounts receivable, net	24,154			28,431
Accounts receivable from affiliates	6,721			8,119
Materials, supplies and fuel	26,190			24,853
Regulatory assets, current	20,555			19,052
Other current assets	4,296			4,538
Total current assets	81,921			85,105

Investments	4,860			4,889

Property, plant and equipment	1,454,337			1,381,045
Less: accumulated depreciation and amortization	(393,013		)	(376,160		)
Total property, plant and equipment, net	1,061,324			1,004,885

Other assets:
Regulatory assets, non-current	54,234			56,680
Other assets, non-current	24,006			9,729
Total other assets, non-current	78,240			66,409

TOTAL ASSETS	$	1,226,345		$	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) Nine Months Ended September 30,
2017 2016
(in thousands)
Operating activities:
Net income $ 35,683
$ 33,002
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization 26,578
25,363
Deferred income tax 6,188
22,267
Employee benefits 613
1,327
AFUDC (2,817 ) (1,595 )
Other adjustments, net 2,298
118
Change in operating assets and liabilities -
Accounts receivable and other current assets 6,567
5,499
Accounts payable and other current liabilities 3,077
(501 )
Regulatory assets - current 1,543
(4,029 )
Contributions to defined benefit pension plan (4,000 ) (820 )
Other operating activities, net (1,097 ) (3,994 )
Net cash provided by (used in) operating activities 74,633
76,637

Investing activities:
Property, plant and equipment additions (61,537 ) (65,062 )
Change in money pool notes receivable, net (12,472 ) (10,966 )
Other investing activities 313
(81 )
Net cash provided by (used in) investing activities (73,696 ) (76,109 )

Financing activities:
Net cash provided by (used in) financing activities —
—

Net change in cash and cash equivalents 937
528

Cash and cash equivalents, beginning of period 234
297
Cash and cash equivalents, end of period $ 1,171
$ 825



	As of
(unaudited)	September 30, 2019			December 31, 2018
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	17,492		$	25,122
Accounts payable to affiliates	26,648			25,804
Accrued liabilities	45,223			34,193
Money pool notes payable	17,370			38,690
Notes payable to Parent	25,000			—
Regulatory liabilities, current	2,821			2,574
Total current liabilities	134,554			126,383

Long-term debt	340,141			340,035

Deferred credits and other liabilities:
Deferred income tax liabilities, net	116,965			114,009
Regulatory liabilities, non-current	162,821			160,642
Benefit plan liabilities	12,823			14,606
Other deferred credits and other liabilities	15,337			1,368
Total deferred credits and other liabilities	307,946			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	381,528			342,145
Accumulated other comprehensive loss	(815		)	(891		)
Total stockholder’s equity	443,704			404,245

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	1,226,345		$	1,161,288

~~See Note 7 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)	Nine Months Ended September 30,
	2019			2018
	(in thousands)
Operating activities:
Net income	$	39,388		$	36,202
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	30,762			29,700
Deferred income tax	951			4,619
Employee benefits	584			1,139
Other adjustments, net	2,559			2,123
Change in operating assets and liabilities:
Accounts receivable and other current assets	4,290			224
Accounts payable and other current liabilities	9,370			2,337
Regulatory assets - current	(2,306		)	2,004
Regulatory liabilities - current	298			8,224
Contributions to defined benefit pension plan	(1,753		)	(1,795		)
Other operating activities, net	(667		)	(1,400		)
Net cash provided by (used in) operating activities	83,476			83,377

Investing activities:
Property, plant and equipment additions	(86,395		)	(47,527		)
Proceeds from sale of assets	—			4,994
Other investing activities	(868		)	(5,338		)
Net cash provided by (used in) investing activities	(87,263		)	(47,871		)

Financing activities:
Change in money pool notes payable, net	(21,320		)	(35,509		)
Notes payable to Parent	25,000			—
Net cash provided by (used in) financing activities	3,680			(35,509		)

Net change in cash	(107		)	(3		)

Cash, beginning of period	112			16
Cash, end of period	$	5		$	13

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



(unaudited)	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
Net income (loss) available for common stock	—	—		—		13,743			—			13,743
Other comprehensive income (loss), net of tax	—	—		—		—			25			25
September 30, 2019	23,416,396	$	23,416	$	39,575	$	381,528		$	(815	)	$	443,704



	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
Net income (loss) available for common stock	—	—		—		13,317			—			13,317
Other comprehensive income (loss), net of tax	—	—		—		—			27			27
Dividend to Parent company	—	—		—		(10,000		)	—			(10,000		)
Other adjustments	—	—		—		1			—			1
September 30, 2018	23,416,396	$	23,416	$	39,575	$	332,703		$	(1,176	)	$	394,518

BLACK HILLS POWER, INC.

Notes to Condensed Financial Statements

(unaudited)

(Reference is made to Notes to Financial Statements

included in our ~~2016~~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,”~~“Company”, “we”, “us”, or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These condensed financial statements should be read in conjunction with the financial statements and the notes thereto, included in our ~~2016~~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 30, ~~2017~~, 2019, December 31, ~~2016~~2018 and September 30, ~~2016~~2018 financial information and are of a normal recurring nature. The results of operations for the three and nine months ended September 30, ~~2017~~2019 and September 30, ~~2016~~,2018, and our financial condition as of September 30, ~~2017~~2019 and December 31, ~~2016~~2018 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

~~Revisions~~

~~Certain revisions have been made to prior year’s financial information to conform to the current year presentation.~~

We revised our presentation of cash and certain cash transactions processed on behalf of affiliates as of December 31, 2016. We have banking arrangements at certain financial institutions whereby if required, payments of one account are cleared with cash from other accounts at the same financial institution; therefore, book overdrafts are presented on a combined basis by bank as cash and cash equivalents. Cash collected or disbursed on behalf of affiliates is presented as Receivables - affiliates or Accounts payable - affiliates. Prior year amounts were corrected to conform to the current year presentation, which decreased cash and cash equivalents by $9.4 million as of September 30, 2016. It also decreased net cash flows provided by operations by $2.2 million for the nine months ended September 30, 2016. We assessed the materiality of these changes, taking into account quantitative and qualitative factors, and determined them to be immaterial to the balance sheet as of September 30, 2016 and to the Statements of Cash Flows for the nine months ended September 30, 2016. There is no impact to the Statements of Income or Statements of Comprehensive Income (Loss) for any period reported.

Recently Issued Accounting Standards

~~Revenue from Contracts with Customers,~~Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, ASU ~~2014-09~~2018-19

In ~~May 2014,~~June 2016, the FASB issued ASU ~~2014-09,~~ ~~Revenue from Contracts with Customers~~.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 ~~provides companies with a single~~introduces new accounting guidance for credit losses on financial instruments within its scope, including trade receivables. This new guidance adds an impairment model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the modelthat is to recognize revenue when control of the goods or services transfers to the customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidancebased on expected losses rather than incurred losses. It is effective for ~~annual~~interim and ~~interim~~annual reporting periods beginning after December 15, 2017 with early adoption on January 1, 2017 permitted. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption.

~~We currently expect to implement the standard on a modified retrospective basis effective January 1, 2018. We have substantially completed our assessment of all sources of revenue~~2019, and are currently determining the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. A majority of our revenues are from regulated tariff offerings that provide electricity with a defined contractual term. For such arrangements, we expect that revenue from contracts with the customer will be equivalent to the electricity delivered during that period. Therefore, we do not expect there will be a significant shift in the timing or pattern of revenue recognition for regulated tariff based sales. We

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

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

~~In March 2017, the FASB issued ASU 2017-07,~~ ~~Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost~~. The changes to the standard require employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. This ASU will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and post-retirement benefit costs in the income statement. The capitalization of the service cost component of net period pension and post-retirement benefit costs in assets will be applied on a ~~prospective basis. This new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods.~~modified-retrospective basis through a cumulative-effect adjustment to retained earnings as of January 1, 2020. We ~~continue to assess~~do not anticipate the ~~impact~~adoption of this ~~new standard on our financial statements and disclosures, and we monitor regulated utility industry implementation discussions and guidance. For our rate-regulated entities, we currently expect~~guidance to capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities. The presentation changes required for net periodic pension and post-retirement costs will result in offsetting changes to Operating income and Other income and are not expected to be material. We will implement this standard effective January 1, 2018.

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

~~In August 2016, the FASB issued ASU 2016-15,~~ ~~Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force).~~ T~~his ASU requires changes in the pres~~entation of certain items including but not limited to debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. ~~The ASU will be effective for fiscal years beginning after December 15, 2017.We will use the retrospective transition method to adopt this standard with fiscal years beginning after December 15, 2017. This standard will not~~ have a material impact on our financial position, results of operations or cash flows.

Recently Adopted Accounting Standards

Leases, ASU 2016-02

In February 2016, the FASB issued ASU ~~No.~~ 2016-02, Leases (Topic 842)~~, which supersedes ASC 840,~~ ~~Leases. This ASU requires lessees~~ to ~~recognize a~~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 ~~all~~most leases, ~~with a term greater than 12 months,~~ whereas ~~today~~previously only ~~financing type~~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 the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Lessees 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.leases.

We ~~currently expect to adopt this~~adopted the standard oneffective January 1, 2019. We ~~continue~~elected the option to ~~evaluate~~not recast comparative periods presented with transitioning to the ~~impact~~new lease standard and will report these comparative periods as presented under previous lease guidance. In addition, we elected the package of ~~this~~practical expedients permitted under the transition guidance with the new standard, 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 January 1, 2019. The lease standard did not materially impact our net earnings and had no impact on cash flows.

(2) REVENUE

Revenue Recognition

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). 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 ~~financial position, results~~customers. The following table depicts the disaggregation of ~~operations~~revenue, from contracts with customers by customer type and ~~cash flows as well as monitor emerging guidance on such topics as easements~~timing of revenue recognition for the three and ~~right of ways, pipeline laterals, purchase power agreements,~~nine months ended September 30, 2019 and 2018. Sales tax and other ~~industry-related areas.~~similar taxes are excluded from revenues.



	Three Months Ended September 30, 2019		Three Months Ended September 30, 2018		Nine Months Ended September 30, 2019		Nine Months Ended September 30, 2018
	(in thousands)
Customer types:
Retail	$	51,056	$	49,874	$	150,941	$	147,040
Wholesale	7,918		8,255		23,041		25,496
Market - off-system sales	5,122		7,625		12,185		13,349
Transmission/Other	12,798		12,183		38,712		36,273
Revenue from contracts with customers	76,894		77,937		224,879		222,158
Other revenues	128		130		430		400
Total revenues	$	77,022	$	78,067	$	225,309	$	222,558

Timing of revenue recognition:
Services transferred over time	$	76,894	$	77,937	$	224,879	$	222,158
Revenue from contracts with customers	$	76,894	$	77,937	$	224,879	$	222,158

Contract Balances

The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts receivable and is further discussed in Note 3. We ~~have begun the process of identifying and categorizing our lease contracts and evaluating our current business processes.~~do not typically incur costs that would be capitalized to obtain or fulfill a revenue contract.


(2) (3)	ACCOUNTS RECEIVABLE ~~AND ALLOWANCE FOR DOUBTFUL ACCOUNTS~~

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



	September 30, 2019			December 31, 2018
Accounts receivable, trade	$	14,367		$	16,236
Unbilled revenues	9,894			12,333
Less allowance for doubtful accounts	(107		)	(138		)
Accounts receivable, net	$	24,154		$	28,431

September 30, 2017 December 31, 2016
Accounts receivable trade $ 17,356
$ 16,972
Unbilled revenues 10,348
13,799
Allowance for doubtful accounts (125 ) (157 )
Receivables - customers, net $ 27,579
$ 30,614


(3) (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, 2019			December 31, 2018
Regulatory assets:
Loss on reacquired debt ^(a)	$	1,056		$	1,259
Deferred taxes on AFUDC ^(b)	4,946			5,020
Employee benefit plans and related deferred taxes ^(c)	19,935			19,868
Deferred energy and fuel cost adjustments^(b)	22,270			20,334
Deferred taxes on flow through accounting^(c)	9,392			8,749
Decommissioning costs ^(a)	6,654			8,196
Vegetation management ^(a)	8,638			10,366
Other regulatory assets ^(a)	1,898			1,940
Total regulatory assets	$	74,789		$	75,732
Less current regulatory assets	(20,555		)	(19,052		)
Regulatory assets, non-current	$	54,234		$	56,680

Maximum Amortization
(in years)
September 30, 2017 December 31, 2016
Regulatory assets:
Unamortized loss on reacquired debt ^(a)
8 $ 1,604
$ 1,815
Deferred taxes on AFUDC ^(b)
45 10,192
9,367
Employee benefit plans^(c)

12 20,180
20,100
Deferred energy and fuel cost adjustments - current^(a)
1 13,754
18,119
Deferred gas cost adjustments ^{(a) (e)}
1 5,324
4,897
Deferred taxes on flow through accounting ^(a)
35 14,906
12,545
Decommissioning costs, net of amortization^(d)
6 10,766
12,456
Other regulatory assets ^(a) ^(d)
6 15,271
12,835
Total regulatory assets $ 91,997
$ 92,134



Regulatory liabilities:
Cost of removal for utility plant ^(a)	$	56,113		$	52,366
Employee benefit plan costs and related deferred taxes ^(c)	7,518			7,518
Excess deferred income taxes ^(c)	98,858			100,276
TCJA revenue reserve	2,821			2,523
Other regulatory liabilities^(c)	332			533
Total regulatory liabilities	$	165,642		$	163,216
Less current regulatory liabilities	(2,821		)	(2,574		)
Regulatory liabilities, non-current	$	162,821		$	160,642

Regulatory liabilities:
Cost of removal for utility plant ^(a)
61 $ 43,518
$ 41,541
Employee benefit plan costs and related deferred taxes ^(c)
12 12,304
12,304
Other regulatory liabilities 13 825
105
Total regulatory liabilities $ 56,647
$ 53,950

____________________


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


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


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

~~(d)~~

In accordance with a settlement agreement approved by the SDPUC on June 16, 2017, the amortization of South Dakota Electric’s decommissioning costs of approximately $11 million, vegetation management costs of approximately $14 million, and Winter Storm Atlas costs of approximately $2.0 million are being amortized over 6 years, effective July 1, 2017. Decommissioning costs and Winter Storm Atlas costs were previously amortized over a 10 year period ending September 30, 2024. The vegetation management costs were previously unamortized. The change in amortization periods for these costs will increase annual amortization expense by approximately $2.7 million.

~~(e)~~

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

Regulatory Matters

There have been no significant changes to our Regulatory Matters from those previously disclosed in Note 1 of the Notes to the Financial Statements in our 2018 Annual Report on Form 10-K except as reported below.

Renewable Ready Service Tariffs and Corriedale Wind Energy Project

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 MW Corriedale Wind Energy Project. The wind project will be jointly owned by the 2 electric utilities to deliver renewable energy for large commercial, industrial and governmental agency customers. The project is expected to be in service by the end of 2020. In September 2019, the customer subscription period was completed with customer interest fulfilling the 40 MW of available energy. On November 1, 2019, South Dakota Electric filed with the SDPUC an amendment seeking approval to increase the generating capacity under the tariff for the South Dakota portion by 12.5 MW to a total of 32.5 MW.


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

Dividend to Parent

We did not record any dividends for the nine months ended September 30, 2019. We recorded non-cash dividends to our Parent of $36 million and decreased the utility Money pool note receivable by $36 million for the nine months ended September 30, 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:



	September 30, 2019		December 31, 2018
Accounts receivable from affiliates	$	6,721	$	8,119
Accounts payable to affiliates	$	26,648	$	25,804

September 30, 2017 December 31, 2016
Receivables - affiliates $ 5,498
$ 9,526
Accounts payable - affiliates $ 26,828
$ 31,799

Money Pool Notes Receivable and Notes Payable

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

We ~~will continue to~~ participate in the Utility Money Pool Agreement (the Agreement). Under the Agreement, we may borrow from the pool; however the Agreement restricts the pool from loaning funds to BHC or to any of BHC’s non-utility subsidiaries. The Agreement does not restrict us from paying dividends to BHC. Borrowings under the Agreement bear interest at the weighted average daily cost of our parent company’s external borrowings as defined under the Agreement, or if there are no external funds outstanding on that date, then the rate will be the daily one-month LIBOR plus 1.0%. At September 30, ~~2017~~,2019, the average cost of borrowing under the Utility Money Pool was ~~1.66%~~2.57%.

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

September 30, 2017 December 31, 2016
Money pool notes receivable, net $ 8,881
$ 28,409

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,
	2019			2018			2019			2018
Net interest income (expense)	$	(111	)	$	(75	)	$	(582	)	$	(207	)

Notes payable to Parent

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Net interest income (expense) $ 53
$ 277
$ 269
$ 845

(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 September 30, 2019.

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Revenue:
Energy sold to Cheyenne Light	$	326	$	311	$	1,240	$	1,515
Rent from electric properties	$	896	$	908	$	2,687	$	3,025
Horizon Point shared facility revenues	$	3,007	$	2,826	$	9,020	$	8,078

Fuel and purchased power:
Purchases of coal from WRDC	$	4,368	$	4,161	$	12,241	$	12,477
Purchase of excess energy from Cheyenne Light	$	239	$	193	$	412	$	361
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	316	$	262	$	1,193	$	1,284
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	607	$	582	$	2,201	$	2,371
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	76	$	96	$	227	$	288

Operations and maintenance:
Corporate support services and fees from Black Hills Service Company	$	9,291	$	9,836	$	28,933	$	25,046
Wygen III ground lease with WRDC	$	247	$	241	$	740	$	722

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

Fuel and purchased power:

Purchases of coal from WRDC $ 4,054
$ 4,122
$ 11,386
$ 12,275
Purchase of excess energy from Cheyenne Light $ 208
$ 64
$ 324
$ 172
Purchase of renewable wind energy from Cheyenne Light - Happy Jack $ 199
$ 312
$ 1,174
$ 1,329
Purchase of renewable wind energy from Cheyenne Light - Silver Sage $ 351
$ 547
$ 2,007
$ 2,276

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

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


(5) (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,
	2019			2018			2019			2018
Service cost	$	91		$	129		$	274		$	387
Interest cost	603			548			1,808			1,645
Expected return on plan assets	(851		)	(887		)	(2,554		)	(2,660		)
Prior service cost	3			11			8			33
Net loss (gain)	305			516			915			1,548
Net periodic benefit cost	$	151		$	317		$	451		$	953

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Service cost $ 137
$ 151
$ 409
$ 453
Interest cost 585
625
1,755
1,875
Expected return on plan assets (898 ) (908 ) (2,692 ) (2,724 )
Prior service cost 10
11
32
33
Net loss (gain) 308
498
922
1,496
Net periodic benefit cost $ 142
$ 377
$ 426
$ 1,133

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,
	2019			2018			2019			2018
Service cost	$	38		$	48		$	112		$	145
Interest cost	46			45			139			134
Prior service cost (benefit)	(84		)	(84		)	(252		)	(252		)
Net periodic benefit cost	$	—		$	9		$	(1	)	$	27

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Service cost $ 52
$ 51
$ 155
$ 153
Interest cost 44
47
132
141
Prior service cost (benefit) (84 ) (84 ) (252 ) (252 )
Net periodic benefit cost $ 12
$ 14
$ 35
$ 42

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,
	2019		2018		2019		2018
Interest cost	$	29	$	27	$	86	$	81
Net loss (gain)	15		26		48		78
Net periodic benefit cost	$	44	$	53	$	134	$	159

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Interest cost $ 29
$ 30
$ 87
$ 90
Net loss (gain) 22
20
65
62
Net periodic benefit cost $ 51
$ 50
$ 152
$ 152

Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. ~~On July 24, 2017, we made contributions~~Contributions to the Defined Benefit Pension Plan in the amount of approximately $1.8 million. On September 15, 2017, we made an additional contribution of approximately $2.2 million to reduce Pension Benefit Guaranty Corporation premiums and offset the forecasted increase in pension expense due to low bond yields which impact the pension discount rate. Contributions to thePostretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made for ~~2017~~2019 and anticipated contributions for ~~2017~~2019 and ~~2018~~2020 are as follows (in thousands):



	Contributions		Remaining Anticipated Contributions for		Anticipated Contributions for
	Nine Months Ended September 30, 2019		2019		2020
Defined Benefit Pension Plan	$	1,753	$	—	$	1,720
Defined Benefit Postretirement Healthcare Plan	$	350	$	117	$	477
Supplemental Non-qualified Defined Benefit Plans	$	173	$	58	$	217

Contributions
Nine Months Ended
September 30, 2017
Remaining Anticipated Contributions for 2017 Anticipated Contributions for 2018
Defined Benefit Pension Plan $ 4,000
$ —
$ 1,834
Defined Benefit Postretirement Healthcare Plan $ 406
$ 135
$ 565
Supplemental Non-qualified Defined Benefit Plans $ 185
$ 62
$ 246


~~(6)~~(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~~ ~~2016~~ ~~Annual Report on Form 10-K filed with the SEC.~~

~~The estimated fair values of our financial instruments~~ were as follows (in thousands) as of:

September 30, 2017 December 31, 2016
Carrying Amount Fair Value Carrying Amount Fair Value
Cash and cash equivalents ^(a)
$ 1,171
$ 1,171
$ 234
$ 234
Long-term debt, including current maturities ^{(b) (c)}
$ 339,860
$ 439,973
$ 339,756
$ 410,466



	September 30, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current maturities ^{(a) (b)}	$	340,141	$	467,040	$	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.


~~(7)~~(8)	SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION



	Nine Months Ended September 30,
	2019			2018
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	8,858		$	10,540
Non-cash (decrease) to money pool notes receivable, net	$	—		$	(36,000	)
Non-cash dividend to Parent	$	—		$	36,000

Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(14,946	)	$	(14,104	)

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

Cash (paid) refunded during the period for -
Interest (net of amounts capitalized) $ (12,838 ) $ (13,486 )


~~(8)~~(9)	COMMITMENTS AND CONTINGENCIES

There have been no significant changes to commitments and contingencies from those previously disclosed in Note 11 of our Notes to the Financial Statements in our ~~2016~~2018 Annual Report on Form 10-K.


(10)	LEASES

We have a ground lease for the 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 31 years.

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



	Income Statement Location	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Operating lease cost	Operations and maintenance	$	227	$	683
Variable lease cost	Operations and maintenance	39		121
Total lease cost		$	266	$	804

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



	Balance Sheet Location	As of September 30, 2019
Assets:
Operating lease assets	Other assets, non-current	$	14,171
Total lease assets		$	14,171

Liabilities:
Current:
Operating leases	Accrued liabilities	$	198

Noncurrent:
Operating leases	Other deferred credits and other liabilities	13,993
Total lease liabilities		$	14,191

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



	Nine Months Ended September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	676
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	—



	As of September 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)	$	231
2020	856
2021	856
2022	856
2023	853
Thereafter	21,947
Total lease payments	$	25,599
Less imputed interest	11,408
Present value of lease liabilities	$	14,191


(a)	Includes lease obligations for the remaining three 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

~~Regulatory Matters~~

On ~~June 16, 2017,~~October 15, 2019, Moody’s affirmed South Dakota Electric’s credit rating at A1.

On September 17, 2019, South Dakota Electric received approval from the SDPUC on a settlement reached with the SDPUC staff agreeing to a six-year moratorium period effective July 1, 2017. As part of this agreement, South Dakota Electric will not increase base rates, absent an extraordinary event. The moratorium period also includes a suspension of both the Transmission Facility Adjustment and the Environmental Improvement Adjustment, and a $1.0 million increase to the annual power marketing margin guarantee during this period. Additionally, existing regulatory asset balances of approximately $13 million related to decommissioning and Winter Storm Atlas will be amortized over the moratorium period. These balances were previously amortized over a 10-year period ending September 30, 2024. The vegetation management regulatory asset of $14 million, previously unamortized, will also be amortized over the moratorium period. The change in amortization periods for these costs will increase annual amortization expense by approximately $2.7 million.

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

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

~~Transmission~~

~~Construction was~~ completed construction on the ~~144 mile-long~~final 94-mile segment of a 175-mile electric transmission line ~~connecting the Teckla Substation in northeast Wyoming to the Lange Substation near~~from Rapid City, South ~~Dakota.~~Dakota, to Stegall, Nebraska. The first 48-mile segment ~~of this project connecting Teckla to Osage, WY~~ was placed in service on ~~August 31, 2016. The~~July 25, 2018, and the second 33-mile segment ~~connecting Osage to Lange~~ was placed in service on ~~May 30, 2017.~~November 20, 2018.

~~Tax Matters - Potential Corporate Tax Reform~~On August 29, 2019, Fitch affirmed South Dakota Electric’s credit rating at A.

~~President Trump~~South Dakota Electric and ~~Congressional Republicans have stated that one~~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, industrial and governmental agency customers. The project is expected to be in service by the end of ~~their top priorities is enactment~~2020. In September 2019, the customer subscription period was completed with customer interest fulfilling the 40 MW of ~~comprehensive tax reform.~~available energy. On November ~~2, 2017,~~1, 2019, South Dakota Electric filed with the ~~House Ways and Means Committee released its tax reform bill. Significant uncertainty exists as~~SDPUC an amendment seeking approval to increase the ~~ultimate legislation that will be enacted into law. We are evaluating~~generating capacity under the ~~proposed legislation; any impact on our future results~~tariff for the South Dakota portion by 12.5 MW to a total of ~~operations, financial position and cash flows as a result of the potential changes cannot yet be determined and such changes could be material.~~32.5 MW.

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 September 30,									Nine Months Ended September 30,									Three Months Ended September 30,									Nine Months Ended September 30,
	2017			2016			Variance			2017			2016			Variance			2019			2018			Variance			2019			2018			Variance
	(in thousands)																		(in thousands)
Revenue	$	73,938		$	66,728		$	7,210		$	213,785		$	197,389		$	16,396		$	77,022		$	78,067		$	(1,045	)	$	225,309		$	222,558		$	2,751
Fuel and purchased power	22,843			18,421			4,422			64,604			55,375			9,229			21,805			25,207			(3,402		)	62,919			68,400			(5,481		)
Gross margin	51,095			48,307			2,788			149,181			142,014			7,167
Gross margin (non-GAAP)																			55,217			52,860			2,357			162,390			154,158			8,232

Operating expenses	27,397			25,897			1,500			84,395			79,888			4,507			33,213			31,432			1,781			98,434			92,871			5,563
Operating income	23,698			22,410			1,288			64,786			62,126			2,660			22,004			21,428			576			63,956			61,287			2,669

Interest income (expense), net	(4,779		)	(4,625		)	(154		)	(15,216		)	(14,478		)	(738		)	(5,329		)	(5,183		)	(146		)	(16,038		)	(15,986		)	(52		)
Other income (expense), net	679			654			25			1,745			1,670			75			112			(247		)	359			28			(606		)	634
Income tax expense	(5,772		)	(6,429		)	657			(15,632		)	(16,316		)	684			(3,044		)	(2,681		)	(363		)	(8,558		)	(8,493		)	(65		)
Net income	$	13,826		$	12,010		$	1,816		$	35,683		$	33,002		$	2,681		$	13,743		$	13,317		$	426		$	39,388		$	36,202		$	3,186

~~Three~~

Nine Months Ended September 30, ~~2017~~2019 Compared to ~~Three~~Nine Months Ended September 30, ~~2016.~~2018. Net income was ~~$14~~$39 million compared to ~~$12~~$36 million for the same period in the prior year primarily due to the following:

Gross margin increased ~~over~~primarily due to a $4.9 million reduction in the ~~prior year reflecting a $2.8 million increase in~~power capacity charges and increased rider revenues ~~primarily~~of $2.5 million related to transmission investment recovery. ~~Higher cooling degree days were offset by lower~~Increased industrial usage ~~per~~(partially due to a prior year customer outage), customer growth, and ~~lower commercial and industrial demand. Cooling degree days were 11% higher than normal in~~favorable weather comprised the ~~current year compared to 18% lower than normal for~~remainder of the ~~same period in the prior year.~~increase.

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

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

~~Income tax expense:~~ ~~The effective tax rate was lower than the prior year, primarily~~higher depreciation due to a higher ~~flow-through benefits in the current year.~~

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

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

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

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

~~Income tax expense:~~ ~~The effective tax rate was lower than the prior year, primarily~~ due to ~~higher flow-through benefits in the current year.~~generation outages.



	Electric Revenue by Customer Type
	Three Months Ended September 30,					Nine Months Ended September 30,
	(in thousands)
	2019		Percentage Change	2018		2019		Percentage Change	2018
Residential	$	17,215	(4)%	$	17,971	$	53,975	(3)%	$	55,458
Commercial	24,430		(5)%	25,601		69,705		(4)%	72,683
Industrial	8,853		15%	7,685		25,786		7%	24,131
Municipal	896		(11)%	1,005		2,453		(9)%	2,692
Total retail revenue	51,394		(2)%	52,262		151,919		(2)%	154,964
Wholesale ^(a)	7,917		(4)%	8,255		23,040		(10)%	25,496
Market - off-system sales ^(b)	5,122		(33)%	7,625		12,185		(9)%	13,349
Other revenue ^(c)	12,589		27%	9,925		38,165		33%	28,749
Total revenue	$	77,022	(1)%	$	78,067	$	225,309	1%	$	222,558

____________________


(a)	Decrease for the nine months ended September 30, 2019 was primarily driven by prior year increased volumes on long-term wholesale contracts.


(b)	Decrease for the nine months ended September 30, 2019 was driven by lower wholesale volume opportunities driven by weather and energy prices.


(c)	Increase for the nine months ended September 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.

Electric Revenue by Customer Type
Three Months Ended September 30, Nine Months Ended September 30,
(in thousands)
2017 Percentage Change 2016 2017 Percentage Change 2016
Residential $ 18,020
3% $ 17,501
$ 53,724
1% $ 53,057
Commercial 25,459
(1)% 25,714
72,608
(1)% 73,026
Industrial 8,149
(2)% 8,275
24,774
1% 24,540
Municipal 1,071
2% 1,053
2,849
—% 2,844
Total retail revenue 52,699
—% 52,543
153,955
—% 153,467
Contract wholesale ^(a)
8,048
75% 4,596
22,593
78% 12,717
Wholesale off-system ^(b)
4,787
20% 3,984
11,044
(2)% 11,304
Other revenue ^(c)
8,404
50% 5,605
26,193
32% 19,901
Total revenue $ 73,938
11% $ 66,728
$ 213,785
8% $ 197,389



	Megawatt Hours Sold by Customer Type
	Three Months Ended September 30,			Nine Months Ended September 30,
	2019	Percentage Change	2018	2019	Percentage Change	2018
Residential	124,656	—%	125,159	408,991	1%	404,178
Commercial	203,761	—%	204,621	579,521	(1)%	586,336
Industrial ^(a)	118,792	24%	95,473	339,611	11%	305,875
Municipal	8,399	(7)%	9,070	22,728	(6)%	24,052
Total retail quantity sold	455,608	5%	434,323	1,350,851	2%	1,320,441
Wholesale	211,968	(4)%	221,327	629,210	(7)%	677,163
Market - off-system sales ^(b)	129,433	(25)%	172,141	342,019	(16)%	406,109
Total quantity sold	797,009	(4)%	827,791	2,322,080	(3)%	2,403,713
Losses and Company use ^(c)	38,716	(18)%	47,171	116,286	(15)%	137,369
Total energy	835,725	(4)%	874,962	2,438,366	(4)%	2,541,082

____________________


(a)	Increase for the ~~three and~~ nine months ended September 30, ~~2017~~2019 was primarily due to a ~~new 50 MW power sales agreement effective January 1, 2017.~~


~~(b)~~	Increase for three months ended September 30, 2017 was driven by higher commodity prices on similar MWh quantities sold. For the nine months ended September 30, 2017 higher commodity prices primarily offset lower MWh quantities sold.


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

Megawatt Hours Sold by Customer Type
Three Months Ended September 30, Nine Months Ended September 30,
2017 Percentage Change 2016 2017 Percentage Change 2016
Residential 129,616
5% 124,012
386,709
1% 381,616
Commercial 212,773
—% 213,276
582,899
(2)% 592,371
Industrial 109,745
—% 110,220
323,038
1% 320,861
Municipal 10,156
2% 9,927
25,865
—% 25,855
Total retail quantity sold 462,290
1% 457,435
1,318,511
—% 1,320,703
Contract wholesale ^(a)
185,723
197% 62,547
537,720
195% 182,087
Wholesale off-system ^(b)
130,825
2% 128,415
388,287
(12)% 438,852
Total quantity sold 778,838
20% 648,397
2,244,518
16% 1,941,642
Losses and company use ^(c)
56,447
36% 41,585
155,477
40% 111,437
Total energy 835,285
21% 689,982
2,399,995
17% 2,053,079

~~____________________~~


~~(a)~~	~~Increase for the three~~customer outage and ~~nine months ended September 30, 2017 was primarily due to a new 50 MW power sales agreement effective January 1, 2017.~~customer usage growth.


(b)	Decrease ~~in 2017~~for the nine months ended September 30, 2019 was primarily due to lower wholesale volume opportunities driven by ~~commodity prices that impacted power marketing sales.~~weather and energy prices.


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


	Megawatt Hours Generated and Purchased						Megawatt Hours Generated and Purchased
	Three Months Ended September 30,			Nine Months Ended September 30,			Three Months Ended September 30,			Nine Months Ended September 30,
Generated -	2017	Percentage Change	2016	2017	Percentage Change	2016	2019	Percentage Change	2018	2019	Percentage Change	2018
Coal-fired	423,766	6%	401,231	1,101,291	4%	1,054,264	389,565	(5)%	407,936	1,086,432	(9)%	1,195,104
Natural Gas and Oil ^(a)	54,466	31%	41,654	75,840	(22)%	96,649	99,477	61%	61,744	175,904	78%	98,609
Total generated	478,232	8%	442,885	1,177,131	2%	1,150,913	489,042	4%	469,680	1,262,336	(2)%	1,293,713

Total purchased ^(b)(a)	357,053	44%	247,097	1,222,864	36%	902,166	346,683	(14)%	405,282	1,176,030	(6)%	1,247,369
Total generated and purchased ^(b)	835,285	21%	689,982	2,399,995	17%	2,053,079	835,725	(4)%	874,962	2,438,366	(4)%	2,541,082

____________________

(a) Increase is primarily due to low natural gas prices and the ability to generate at a lower cost than to purchase generation on the open market for the nine months ended September 30, 2019.



	Power Plant Availability
	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Coal-fired plants ^(a)	94.9	%	93.8	%	88.3	%	92.7	%
Other plants^(b)	81.8	%	96.0	%	83.0	%	97.6	%
Total availability	88.0	%	95.0	%	85.5	%	95.3	%

____________________

(a)

~~Variances for the three~~2019 included planned outages at Neil Simpson II and ~~nine months ended September 30, 2017 compared to the same periods in the prior year are driven primarily by the ability to purchase excess generation in the open market~~Wygen III, unplanned outages at ~~a lower or higher cost than to generate.~~Wyodak Plant and Wygen III, and 2018 included planned outages at Neil Simpson II and Wyodak Plant.


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

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

~~____________________~~


~~(a)~~	~~Both years included outages. 2017~~2019 included planned outages at Neil Simpson ~~II, Wyodak~~CT and ~~Wygen II, and 2016 included a planned outage at Wygen III and an extended planned outage at Wyodak.~~Lange CT.


	Degree Days						Degree Days						Degree Days						Degree Days
	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			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	202	(10	)%	161	(23	)%	4,242	(5	)%	3,844	(13	)%	175	(22	)%	236	5	%	5,370	20	%	4,972	11	%
Cooling degree days	595	11	%	460	(18	)%	709	12	%	646	(3	)%	366	(31	)%	356	(33	)%	404	(36	)%	488	(23	)%

Credit Ratings

Credit ratings impact our ability to obtain short and long-term financing, the cost of such financing, and vendor payment terms including collateral requirements. The following table represents our secured credit rating from each agency’s review which was in effect at September 30, ~~2017:~~2019:



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

__________


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


(b)	On October 15, 2019, Moody’s affirmed A1 rating.


(c)	On August 29, 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 ~~2016~~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, ~~2016.~~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 30, ~~2017.~~2019. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective as of September 30, ~~2017.~~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 30, ~~2017,~~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 ~~2016~~2018 Annual Report on Form 10-K and Note 89 of our Notes to Condensed Financial Statements in this Quarterly Report on Form ~~10-Q, which information from Note 8 is incorporated by reference into this item.~~10-Q.


~~Item 1A.~~	~~Risk Factors~~

~~There are no material changes to the Risk Factors previously disclosed in Item 1A of Part I in our Annual Report on Form 10-K for the year ended December 31, 2016.~~


Item 6.	Exhibits


Exhibit 3.1*	Restated Articles of Incorporation of the Registrant dated ~~March~~January 30, ~~2015~~2018 (filed as Exhibit ~~3.1~~3 to Registrant’s Form ~~10-Q for the quarterly period ended March 31, 2015)~~8-K filed on February 5, 2018).


Exhibit 3.2*	Amended and Restated Bylaws of the Registrant dated March 30, 2015 (filed as Exhibit 3.2 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2015).

Exhibit 4.1*

Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to J.P. Morgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registration Statement on Form S-3 (No. 333-150669-01)). Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014).

First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to J.P. Morgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)).

Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registration Statement on Form S-3 (No. 333-150669-01)).

Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014).


Exhibit 31.1	Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.


Exhibit 31.2	Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.


Exhibit 32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.


Exhibit 32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.


101.INS	XBRL 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


104	Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit ~~101~~	~~Financial Statements for XBRL Format~~101)

_________________________


*	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: November ~~3, 2017~~5, 2019

2123



(unaudited)	September 30, 2017			December 31, 2016
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	1,171		$	234
Receivables - customers, net	27,579			30,614
Receivables - affiliates	5,498			9,526
Other receivables, net	335			351
Money pool notes receivable, net	8,881			28,409
Materials, supplies and fuel	23,622			22,389
Regulatory assets, current	18,819			18,119
Other, current assets	3,432			3,876
Total current assets	89,337			113,518

Investments	4,902			4,841

Property, plant and equipment	1,298,855			1,236,387
Less accumulated depreciation and amortization	(354,788		)	(338,828		)
Total property, plant and equipment, net	944,067			897,559

Other assets:
Regulatory assets, non-current	73,178			74,015
Other, non-current assets	3,545			3,816
Total other assets	76,723			77,831
TOTAL ASSETS	$	1,115,029		$	1,093,749



	September 30, 2017			December 31, 2016
Accounts receivable trade	$	17,356		$	16,972
Unbilled revenues	10,348			13,799
Allowance for doubtful accounts	(125		)	(157		)
Receivables - customers, net	$	27,579		$	30,614



	Maximum Amortization (in years)	September 30, 2017		December 31, 2016
Regulatory assets:
Unamortized loss on reacquired debt ^(a)	8	$	1,604	$	1,815
Deferred taxes on AFUDC ^(b)	45	10,192		9,367
Employee benefit plans^(c)	12	20,180		20,100
Deferred energy and fuel cost adjustments - current^(a)	1	13,754		18,119
Deferred gas cost adjustments ^{(a) (e)}	1	5,324		4,897
Deferred taxes on flow through accounting ^(a)	35	14,906		12,545
Decommissioning costs, net of amortization^(d)	6	10,766		12,456
Other regulatory assets ^(a) ^(d)	6	15,271		12,835
Total regulatory assets		$	91,997	$	92,134



Regulatory liabilities:
Cost of removal for utility plant ^(a)	61	$	43,518	$	41,541
Employee benefit plan costs and related deferred taxes ^(c)	12	12,304		12,304
Other regulatory liabilities	13	825		105
Total regulatory liabilities		$	56,647	$	53,950



	Contributions Nine Months Ended September 30, 2017		Remaining Anticipated Contributions for 2017		Anticipated Contributions for 2018
Defined Benefit Pension Plan	$	4,000	$	—	$	1,834
Defined Benefit Postretirement Healthcare Plan	$	406	$	135	$	565
Supplemental Non-qualified Defined Benefit Plans	$	185	$	62	$	246



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

September 30, 2019

December 31, 2018

Money pool notes payable