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~~June 30, ~~2016~~2017
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

~~Commission File Number 1-7978~~

~~Black Hills Power, Inc.~~



Black Hills Power, Inc.
Incorporated in South Dakota		IRS Identification Number 46-0111677
625 Ninth Street
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

~~625 Ninth Street, 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, ~~or a~~ smaller reporting company, ~~(as defined~~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).~~Act.



Large accelerated filer	o		Accelerated filer	o

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

			Smaller reporting company	o

			Emerging growth company	o

If an emerging growth company, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).



Yes o	No x

As of ~~October~~July 31, ~~2016,~~2017, there were issued and outstanding 23,416,396 shares of the Registrant’s common stock, $1.00 par value, all of which were held beneficially and of record by Black Hills Corporation.

Reduced Disclosure

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

TABLE OF CONTENTS



		Page
	GLOSSARY OF TERMS AND ABBREVIATIONS	3

PART 1.	FINANCIAL INFORMATION

Item 1.	Financial Statements

	Condensed Statements of Income and Comprehensive Income - unaudited	4
	Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2016~~2017 and ~~2015~~2016

	Condensed Balance Sheets - unaudited	5
	~~September~~June 30, ~~2016~~2017 and December 31, ~~2015~~2016

	Condensed Statements of Cash Flows - unaudited	7
	~~Nine~~Six Months Ended ~~September~~June 30, ~~2016~~2017 and ~~2015~~2016

	Notes to Condensed Financial Statements - unaudited	8

Item 2.	Managements’ Discussion and Analysis of Financial Condition and Results of Operations	1415

Item 4.	Controls and Procedures	1819

PART II.	OTHER INFORMATION	1920

Item 1.	Legal Proceedings	1920

Item 1A.	Risk Factors	1920

Item 6.	Exhibits	1920

	Signatures	2021

	Exhibit Index	2122

GLOSSARY OF TERMS AND ABBREVIATIONS

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



AFUDC	Allowance for Funds Used During Construction
ASC	Accounting Standards Codification
ASU	Accounting Standards Update issued by the FASB
BHC	Black Hills Corporation; the Parent Company
Black Hills Energy	The name used to conduct the business of BHC utility companies
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc. a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills Service Company	Black Hills Service Company, LLC, a direct, wholly-owned subsidiary of BHC
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Cooling ~~degree day~~Degree Day	A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.
DSM	Demand Side Management
ECA	Energy Cost Adjustment - adjustments that allow us to pass the prudently-incurred cost of fuel and purchased energy through to customers.
FASB	Financial Accounting Standards Board
FERC	United States Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Accounting principles generally accepted in the United States of America
Global Settlement	Settlement with a utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders.
Happy Jack	Happy Jack Wind Farms, LLC, a subsidiary of Duke Energy Generation Services
Heating degree day	A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.
kV	Kilovolt
LIBOR	London Interbank Offered Rate
Moody’s	Moody’s Investors Service, Inc.
MW	Megawatts
~~MWh~~SDPUC	~~Megawatt-hours~~South Dakota Public Utilities Commission
SEC	U. S. Securities and Exchange Commission
Silver Sage	Silver Sage Windpower, LLC, a subsidiary of Duke Energy Generation Services
South Dakota Electric	Includes Black Hills Power operations in South Dakota, Wyoming and Montana
S&P	Standard & Poor’s, a division of The McGraw-Hill Companies, Inc.
~~WPSC~~TCA	~~Wyoming Public Service Commission~~Transmission Cost Adjustment - adjustments passed through to the customer based on transmission costs that are higher or lower than the costs approved in the rate case.
Winter Storm Atlas	An October 2013 blizzard that impacted South Dakota Electric. It was the second most severe blizzard in Rapid City’s history.
WRDC	Wyodak Resources Development Corp., an indirect, wholly-owned subsidiary of BHC

BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended June 30,						Six Months Ended June 30,
(unaudited)	2016			2015			2016			2015			2017			2016			2017			2016
	(in thousands)												(in thousands)
Revenue	$	66,728		$	72,111		$	197,389		$	210,432		$	66,053		$	62,019		$	139,847		$	130,661

Operating expenses:
Fuel and purchased power	18,421			21,983			55,375			63,440			18,612			16,224			41,761			36,954
Operations and maintenance	15,601			16,979			49,538			52,191			18,888			16,906			35,842			33,937
Depreciation and amortization	8,547			8,248			25,363			24,215			8,831			8,204			17,525			16,816
Taxes - property	1,749			1,445			4,987			4,497			2,010			1,749			3,631			3,238
Total operating expenses	44,318			48,655			135,263			144,343			48,341			43,083			98,759			90,945

Operating income	22,410			23,456			62,126			66,089			17,712			18,936			41,088			39,716

Other income (expense):
Interest expense	(5,454		)	(5,542		)	(16,322		)	(16,914		)	(5,635		)	(5,414		)	(11,390		)	(10,868		)
AFUDC - borrowed	319			239			840			322			392			298			584			521
Interest income	510			269			1,004			434			243			292			369			494
AFUDC - equity	606			434			1,595			584			717			566			1,188			989
Other income (expense), net	48			21			75			119			(69		)	(47		)	(122		)	27
Total other income (expense)	(3,971		)	(4,579		)	(12,808		)	(15,455		)	(4,352		)	(4,305		)	(9,371		)	(8,837		)

Income from continuing operations before income taxes	18,439			18,877			49,318			50,634
Income before income taxes													13,360			14,631			31,717			30,879
Income tax expense	(6,429		)	(6,590		)	(16,316		)	(17,397		)	(4,073		)	(4,825		)	(9,860		)	(9,887		)
Net income	12,010			12,287			33,002			33,237			9,287			9,806			21,857			20,992

Other comprehensive income (loss):
Reclassification adjustments of cash flow hedges settled and included in net income (net of tax (expense) benefit of $(6) and $(5) for the three months ended September 30, 2016 and 2015 and $(17) and $325 for the nine months ended September 30, 2016 and 2015, respectively)	10			11			31			373
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(8) and $(9) for the three months ended September 30, 2016 and 2015 and $(21) and $(25) for the nine months ended September 30, 2016 and 2015, respectively)	14			15			41			46
Reclassification adjustments of cash flow hedges settled and included in net income (net of tax (expense) benefit of $(5) and $(5) for the three months ended June 30, 2017 and 2016, and $(11) and $(11) for the six months ended June 30, 2017 and 2016, respectively)													11			11			21			21
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(8) and $(7) for the three months ended June 30, 2017 and 2016 and $(15) and $(14) for the six months ended June 30, 2017 and 2016, respectively)													14			13			28			27
Other comprehensive income	24			26			72			419			25			24			49			48

Comprehensive income	$	12,034		$	12,313		$	33,074		$	33,656		$	9,312		$	9,830		$	21,906		$	21,040

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, 2016			December 31, 2015			June 30, 2017			December 31, 2016
	(in thousands)						(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	10,250		$	7,559		$	1,156		$	234
Receivables - customers, net	25,633			27,856			26,702			30,614
Receivables - affiliates	5,216			5,747			6,596			9,526
Other receivables, net	453			236			334			351
Money pool notes receivable, net	51,279			76,813			12,471			28,409
Materials, supplies and fuel	21,364			24,282			22,989			22,389
Regulatory assets, current	18,212			14,096			21,453			18,119
Other, current assets	3,634			43,118			3,857			3,876
Total current assets	136,041			199,707			95,558			113,518

Investments	4,817			4,725			4,849			4,841

Property, plant and equipment	1,216,000			1,166,126			1,280,757			1,236,387
Less accumulated depreciation and amortization	(334,546		)	(326,074		)	(348,258		)	(338,828		)
Total property, plant and equipment, net	881,454			840,052			932,499			897,559

Other assets:
Regulatory assets, non-current	72,403			71,717			71,449			74,015
Other, non-current assets	3,900			152			3,586			3,816
Total other assets	76,303			71,869			75,035			77,831
TOTAL ASSETS	$	1,098,615		$	1,116,353		$	1,107,941		$	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, 2016			December 31, 2015			June 30, 2017			December 31, 2016
	(in thousands, except common stock par value and share amounts)						(in thousands, except common stock par value and share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	20,647		$	21,297		$	15,842		$	14,158
Accounts payable - affiliates	30,284			30,032			23,745			31,799
Accrued liabilities	32,286			69,454			46,744			37,436
Regulatory liabilities, current	52			—			825			84
Total current liabilities	83,269			120,783			87,156			83,477

Long-term debt	339,721			339,616			339,825			339,756

Deferred credits and other liabilities:
Deferred income tax liability, net, non-current	212,276			188,961			214,539			211,443
Regulatory liabilities, non-current	53,344			51,583			54,818			53,866
Benefit plan liabilities	20,161			20,033			19,645			19,544
Other, non-current liabilities	1,291			3,398			1,390			1,001
Total deferred credits and other liabilities	287,072			263,975			290,392			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			23,416			23,416
Additional paid-in capital	39,575			39,575			39,575			39,575
Retained earnings	326,797			330,295			328,790			322,933
Accumulated other comprehensive loss	(1,235		)	(1,307		)	(1,213		)	(1,262		)
Total stockholder’s equity	388,553			391,979			390,568			384,662
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	1,098,615		$	1,116,353		$	1,107,941		$	1,093,749

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,						Six Months Ended June 30,
	2016			2015			2017			2016
	(in thousands)						(in thousands)
Operating activities:
Net income	$	33,002		$	33,237		$	21,857		$	20,992
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization	25,363			24,215			17,525			16,816
Deferred income tax	22,267			8,161			1,605			18,009
Employee benefits	1,327			1,802			408			886
AFUDC - equity	(1,595		)	(584		)	(1,188		)	(989		)
Other adjustments, net	118			139			408			(236		)
Change in operating assets and liabilities -
Accounts receivable and other current assets	5,499			1,291			7,188			3,234
Accounts payable and other current liabilities	1,662			5,638			(3,486		)	(11,538		)
Regulatory assets - current	(4,029		)	(1,848		)	(315		)	(7,026		)
Regulatory liabilities - current	—			(2,479		)	741			—
Contributions to defined benefit pension plan	(820		)	—			—			(820		)
Other operating activities, net	(3,994		)	8,019			380			168
Net cash provided by (used in) operating activities	78,800			77,591			45,123			39,496

Investing activities:
Property, plant and equipment additions	(65,062		)	(39,338		)	(44,142		)	(35,153		)
Change in money pool notes receivable, net	(10,966		)	(14,694		)	(62		)	(4,286		)
Other investing activities	(81		)	(103		)	3			(67		)
Net cash provided by (used in) investing activities	(76,109		)	(54,135		)	(44,201		)	(39,506		)

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

Net change in cash and cash equivalents	2,691			23,456			922			(10		)

Cash and cash equivalents, beginning of period	7,559			6,620			234			297
Cash and cash equivalents, end of period	$	10,250		$	30,076		$	1,156		$	287

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.

Notes to Condensed Financial Statements

(unaudited)

(Reference is made to Notes to Financial Statements

included in our ~~2015~~2016 Annual Report on Form 10-K)

(1) MANAGEMENT’S STATEMENT

The unaudited condensed financial statements included herein have been prepared by Black Hills Power, Inc. (the “Company,” “we,” “us,” or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These condensed financial statements should be read in conjunction with the financial statements and the notes thereto, included in our ~~2015~~2016 Annual Report on Form 10-K filed with the SEC.

~~Accounting methods historically employed require certain estimates as of interim dates.~~ 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~~June 30, ~~2016~~2017, December 31, ~~2015~~2016 and ~~September~~June 30, ~~2015~~2016 financial information and are of a normal recurring nature. The results of operations for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016~~2017 and ~~September~~June 30, ~~2015~~2016, and our financial condition as of ~~September~~June 30, ~~2016~~2017 and December 31, ~~2015~~2016 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 $19 million as of June 30, 2016. It also decreased net cash flows provided by operations by $12 million for the six months ended June 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 June 30, 2016 and to the Statements of Cash Flows for the six months ended June 30, 2016. There is no impact to the Statements of Income or Statements of Comprehensive Income (Loss) for any period reported.

Recently Issued and Adopted Accounting Standards

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 periodic pension and post-retirement benefit costs in assets will be applied on a prospective basis. This new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. We continue to assess the impact of this new standard on our financial statements and disclosures and monitor utility industry implementation discussions and guidance. 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). ~~This~~This ASU requires changes in the ~~presentation~~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. The ASU will be effective for fiscal years beginning after December 15, 2017. We ~~are currently assessing~~will use the ~~impact that adoption of ASU 2016-15~~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 ~~and~~or cash flows.

Leases, ASU 2016-02

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for all leases with ~~terms of more~~a term greater than 12 ~~months. Lessees~~months, whereas today only financing type lease liabilities (capital leases) are ~~permitted~~recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to ~~make~~when an ~~accounting policy election~~arrangement conveys the right to ~~not recognize~~control the use of the identified asset ~~and liability for leases with~~under the arrangement which may result in changes to the classification of an arrangement as a ~~term of 12 months or less.~~lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ~~ASC~~ASU is largely unchanged from the previous accounting standard. ~~In addition, the~~The ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which ~~includes a number~~requires application of ~~practical expedients.~~the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for usinterim and annual reporting periods beginning after December 15, ~~2018. Early~~2018, with early adoption is permitted.

We ~~are~~ currently ~~assessing~~expect to adopt this standard on January 1, 2019. We continue to evaluate the impact ~~that adoption~~ of ~~ASU 2016-02 will have~~this new standard on our financial position, results of operations orand cash ~~flows.~~

~~Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent), ASU 2015-07~~

~~On May 1, 2015, the FASB issued ASU 2015-07,~~ ~~Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent)~~. ~~This~~ ~~ASU removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient~~flows as well as monitor emerging guidance on such topics as easements and also removes certain disclosure requirements. The new requirements were effective for us beginning January 1, 2016 and will be applied retrospectively to all periods presented, in our 2016 Form 10-K. This ASU will not materially affect our financial statements and disclosures, but will change certain presentation and disclosureright of ~~the fair value of certain plan assets in our pension~~ways, pipeline laterals, purchase power agreements, pole attachments and other ~~postretirement benefit plan disclosures~~industry-related areas. We also expect to implement changes to systems, processes and procedures in ~~our 2016 Form 10-K, for all periods presented.~~

~~Simplifying the Presentation of Debt Issuance Costs, ASU 2015-03~~

~~In April 2015, the FASB issued ASU 2015-03,~~ ~~Simplifying the Presentation of Debt Issuance Costs. Debt issuance costs related~~order to ~~a recognized debt liability are presented~~recognize and measure leases recorded on the balance sheet that are currently classified as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as an asset. Amortization of these costs will continue to be reported as interest expense. ASU 2015-03 is effective for annual and interim reporting periods beginning after December 15, 2015. We adopted ASU 2015-03 in the first quarter of 2016 on a retrospective basis. As of September 30, 2016, we have presented the debt issuance costs, previously reported in other assets, as direct deductions from the carrying amount of long-term debt. The implementation of this standard resulted in reductions of other non-current assets and long-term debt of $3.1 million in the Condensed Balance Sheets as of December 31, 2015. Adoption of ASU 2015-03 did not have a material impact on our financial position.operating leases.

Revenue from Contracts with Customers, ASU 2014-09

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the ~~customer, as opposed to recognizing~~customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue ~~when the risks~~ and ~~rewards transfer to the customer under the existing~~cash flows from revenue ~~guidance. On July 9, 2015, FASB voted to defer the effective date of ASU 2014-09 by one year.~~contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017 ~~and~~with early adoption ison 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. ~~As of September 30, 2016, we were~~

We currently expect to implement the standard on a modified retrospective basis effective January 1, 2018. We continue to actively ~~evaluating~~assess all of our sources of revenue to determine the impact that adoption of ~~ASU 2014-09~~the new standard will have on our financial position, results of operations and cash flows. Our evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. A majority of our revenues are from regulated tariff offerings that provide natural gas or electricity with a defined contractual term. For such arrangements, we expect that revenue from contracts with the customer will be equivalent to the electricity or gas delivered in 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. The evaluation of other revenue streams is ongoing, including our non-regulated revenues and those tied to longer term contractual commitments. We also continue to monitor outstanding industry implementation issues and assess the impacts to our current accounting policies and/or patterns of revenue recognition.


(2)	ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

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


	September 30, 2016			December 31, 2015			June 30, 2017			December 31, 2016
Accounts receivable trade	$	15,171		$	15,268		$	15,731		$	16,972
Unbilled revenues	10,651			12,795			11,137			13,799
Allowance for doubtful accounts	(189		)	(207		)	(166		)	(157		)
Receivables - customers, net	$	25,633		$	27,856		$	26,702		$	30,614


(3)	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:


	Recovery/Amortization Period (in years)	September 30, 2016		December 31, 2015		Recovery/Amortization Period (in years)	June 30, 2017		December 31, 2016
Regulatory assets:
Unamortized loss on reacquired debt ^(a)	8	$	1,885	$	2,096	8	$	1,674	$	1,815
AFUDC ^(b)	45	9,184		8,571
Deferred taxes on AFUDC ^(b)						45	9,913		9,367
Employee benefit plans ^(c)	12	20,866		20,866		12	20,100		20,100
Deferred energy and fuel cost adjustments - current^(a)	Less than 1 year	22,816		19,875		Less than 1 year	20,397		23,016
Flow through accounting ^(a)	35	12,498		12,104
Deferred taxes on flow through accounting ^(a)						35	13,464		12,545
Decommissioning costs, net of amortization^(b)(d)	9	12,625		13,686		6	11,201		12,456
Other regulatory assets ^(a) ^(d)	2	10,741		8,615		6	16,153		12,835
Total regulatory assets		$	90,615	$	85,813		$	92,902	$	92,134


Regulatory liabilities:
Cost of removal for utility plant ^(a)	44	$	40,728	$	38,131	61	$	42,514	$	41,541
Employee benefit plans ^(c)	12	12,616		12,616
Employee benefit plan costs and related deferred taxes ^(c)						12	12,304		12,304
Other regulatory liabilities	13	52		836		13	825		105
Total regulatory liabilities		$	53,396	$	51,583		$	55,643	$	53,950

____________________


(a)	~~Recovery~~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, respectively.

(d)

~~Includes~~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 ~~$9.8~~$11 million, vegetation management costs of approximately $14 million, and ~~$5.0~~Winter Storm Atlas costs of approximately $2.0 million ofwill be 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 ~~expenses at September 30, 2016 and December 31, 2015, respectively,~~costs were previously unamortized. The change in amortization periods for ~~which we are allowed a rate of return.~~these costs will increase annual amortization expense by approximately $2.7 million.


(4)	RELATED-PARTY TRANSACTIONS

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, 2016		December 31, 2015		June 30, 2017		December 31, 2016
Receivables - affiliates	$	5,216	$	5,747	$	6,596	$	9,526
Accounts payable - affiliates	$	30,284	$	30,032	$	23,745	$	31,799

Money Pool Notes Receivable and Notes Payable

We have entered into a Utility Money Pool Agreement (the “Agreement”) with BHC, Black Hills Service Company and the utility companies conducting business as Black Hills Energy. We are the administrator of the Money Pool. Under the Agreement, we may borrow from BHC; however the Agreement restricts us 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 and advances under the Agreement bear interest at the weighted average daily cost of our parent company’s ~~credit facility~~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~~June 30, ~~2016~~2017, the average cost of borrowing under the Utility Money Pool was ~~1.81%~~1.61%.

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

September 30, 2016 December 31, 2015
Money pool notes receivable, net $ 51,279
$ 76,813



	June 30, 2017		December 31, 2016
Money pool notes receivable, net	$	12,471	$	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,
2016 2015 2016 2015
Net interest income (expense) $ 277
$ 309
$ 845
$ 855



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Net interest income (expense)	$	90	$	290	$	216	$	568

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


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015		2017		2016		2017		2016
Revenue:
Energy sold to Cheyenne Light	$	599	$	553	$	1,908	$	1,258	$	625	$	648	$	1,505	$	1,309
Rent from electric properties	$	1,229	$	1,158	$	3,817	$	3,614	$	935	$	1,375	$	1,870	$	2,588

Fuel and purchased power:
Purchases of coal from WRDC	$	4,122	$	4,580	$	12,275	$	12,724	$	3,052	$	3,357	$	7,332	$	8,153
Purchase of excess energy from Cheyenne Light	$	64	$	111	$	172	$	800	$	76	$	53	$	116	$	108
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	312	$	268	$	1,329	$	1,097	$	369	$	353	$	975	$	1,017
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	547	$	476	$	2,276	$	1,910	$	637	$	602	$	1,656	$	1,729

Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	100	$	103	$	300	$	310	$	99	$	100	$	198	$	200

Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	6,257	$	6,213	$	19,155	$	19,873	$	7,109	$	6,177	$	13,720	$	12,898


(5)	EMPLOYEE BENEFIT PLANS

Beginning in 2016, we changed the method used to estimate the service and interest cost components of the net periodic pension, supplemental non-qualified defined benefit and other postretirement benefit costs. The new method uses the spot yield curve approach to estimate the service and interest costs by applying the specific spot rates along the yield curve used to determine the benefit obligations to relevant projected cash outflows. Previously, those costs were determined using a single weighted-average discount rate. The change does not affect the measurement of the total benefit obligations as the change in service and interest costs offsets the actuarial gains and losses recorded in other comprehensive income, regulatory assets or regulatory liabilities. The new method provides a more precise measure of interest and service costs by improving the correlation between the projected benefit cash flows and the discrete spot yield curve rates. We accounted for this change as a change in estimate prospectively beginning in the first quarter of 2016. The discount rates used to measure the 2016 service costs are 4.81%, 4.88% and 4.18% for pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively. The discount rates used to measure the 2016 interest costs are 3.90%, 3.82% and 3.17% for pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively. The previous method would have used a discount rate for both service and interest costs of 4.63% for pension, 4.50% for supplemental non-qualified defined benefit and 4.03% for other postretirement benefit costs. The decrease in the total 2016 service and interest costs is approximately $0.5 million, $0.3 million and $0.1 million for the pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively, as compared to the previous method.

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


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015			2017			2016			2017			2016
Service cost	$	151		$	199		$	453		$	597		$	136		$	151		$	272		$	302
Interest cost	625			739			1,875			2,217			585			625			1,170			1,250
Expected return on plan assets	(908		)	(984		)	(2,724		)	(2,952		)	(897		)	(908		)	(1,794		)	(1,816		)
Prior service cost	11			11			33			33			11			11			22			22
Net loss (gain)	498			549			1,496			1,647			307			499			614			998
Net periodic benefit cost	$	377		$	514		$	1,133		$	1,542		$	142		$	378		$	284		$	756

Defined Benefit Postretirement Healthcare Plan

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


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015			2017			2016			2017			2016
Service cost	$	51		$	59		$	153		$	176		$	51		$	51		$	103		$	102
Interest cost	47			53			141			160			44			47			88			94
Prior service cost (benefit)	(84		)	(84		)	(252		)	(252		)	(84		)	(84		)	(168		)	(168		)
Net periodic benefit cost	$	14		$	28		$	42		$	84		$	11		$	14		$	23		$	28

Supplemental Non-qualified Defined Benefit Plans

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


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015		2017		2016		2017		2016
Interest cost	$	30	$	35	$	90	$	107	$	29	$	30	$	58	$	60
Net loss (gain)	20		23		62		69		21		21		43		42
Net periodic benefit cost	$	50	$	58	$	152	$	176	$	50	$	51	$	101	$	102

Contributions

~~We anticipate we will make contributions to the benefit plans during 2016 and 2017.~~ Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust accounts. On July 24, 2017, we made contributions to the Defined Benefit Pension Plan in the amount of approximately $1.8 million. Contributions to the Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made for 2017 and anticipated contributions for 2017 and 2018 are as follows (in thousands):


	Contributions Nine Months Ended September 30, 2016		Remaining Anticipated Contributions for 2016		Anticipated Contributions for 2017		Contributions Six Ended June 30, 2017		Remaining Anticipated Contributions for 2017		Anticipated Contributions for 2018
Defined Benefit Pension Plan	$	820	$	—	$	1,615	$	—	$	1,834	$	1,834
Defined Benefit Postretirement Healthcare Plan	$	464	$	155	$	509	$	271	$	271	$	565
Supplemental Non-qualified Defined Benefit Plans	$	162	$	54	$	248	$	124	$	124	$	246


(6)	FAIR VALUE OF FINANCIAL INSTRUMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance on fair value measurements establishes a hierarchy for grouping assets and liabilities, based on significance of inputs. For additional information see Note 1 included in our ~~2015~~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, 2016				December 31, 2015				June 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents ^(a)	$	10,250	$	10,250	$	7,559	$	7,559	$	1,156	$	1,156	$	234	$	234
Long-term debt, including current maturities^(b)	$	339,721	$	445,104	$	339,616	$	404,864
Long-term debt, net of deferred financing costs ^(b)									$	339,825	$	434,228	$	339,756	$	410,466

_________________


(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 ~~using the market approach~~ based on observable inputs ~~of quoted market prices and yields~~ available ~~for debt instruments~~ either directly or indirectly for similar ~~maturities and debt ratings~~liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy. ~~The carrying amount of our variable rate debt approximates fair value due to the variable interest rates with short reset periods.~~


(7)	SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION


Nine months ended September 30,	2016			2015
Six months ended June 30,							2017			2016
	(in thousands)						(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	5,565		$	2,074		$	10,495		$	5,355
Non-cash (decrease) to money pool notes receivable, net	$	(36,500	)	$	(18,500	)	$	(16,000	)	$	(24,500	)
Non-cash dividend to Parent	$	36,500		$	18,500		$	16,000		$	24,500

Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(13,486	)	$	(14,192	)	$	(10,786	)	$	(10,547	)


(8)	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 ~~2015~~2016 Annual Report on Form 10-K.

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

~~Name Rebranding~~

~~We now operate with the trade name Black Hills Energy. BHC rebranded all of its regulated utilities to operate under the name Black Hills Energy.~~

Regulatory Matters

~~During~~On June 16, 2017, South Dakota Electric received approval from the ~~first quarter~~SDPUC on a settlement reached with the SDPUC staff agreeing to a six-year moratorium period effective July 1, 2017. As part of ~~2016, we commenced construction~~this agreement, South Dakota Electric will not increase base rates, absent an extraordinary event. The moratorium period also includes a suspension of both the ~~$54~~Transmission Facility Adjustment and the Environmental Improvement Adjustment, and a $1.0 million ~~230-kV,~~increase to the annual power marketing margin guarantee during this period. Additionally, existing regulatory asset balances of approximately $13 million related to decommissioning and Winter Storm Atlas will be amortized over the moratorium period. These balances were previously amortized over a 10-year period ending September 30, 2024. The vegetation management regulatory asset of $14 million, previously unamortized, will also be amortized over the moratorium period. The change in amortization periods for these costs will increase annual amortization expense by approximately $2.7 million.

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



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

Transmission

Construction was completed on the 144 mile-long transmission line ~~that will connect~~connecting the Teckla Substation in northeast Wyoming to the Lange Substation near Rapid City, South Dakota. The first segment of this project connecting Teckla to Osage, WY was ~~energized~~placed in service on August 31, 2016. The second segment ~~of the project is expected~~connecting Osage to beLange was placed in service ~~in the first half of~~on May 30, 2017.

Results of Operations

The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, gross margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of depreciation from the measure. The presentation of gross margin is intended to supplement investors’ understanding of our operating performance.

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

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

The following tables provide certain financial information and operating statistics:

Three Months Ended September 30, Nine Months Ended September 30,
2016 2015 Variance 2016 2015 Variance
(in thousands)
Revenue $ 66,728
$ 72,111
$ (5,383 ) $ 197,389
$ 210,432
$ (13,043 )
Fuel and purchased power 18,421
21,983
(3,562 ) 55,375
63,440
(8,065 )
Gross margin 48,307
50,128
(1,821 ) 142,014
146,992
(4,978 )

Operating expenses 25,897
26,672
(775 ) 79,888
80,903
(1,015 )
Operating income 22,410
23,456
(1,046 ) 62,126
66,089
(3,963 )

Interest income (expense), net (4,625 ) (5,034 ) 409
(14,478 ) (16,158 ) 1,680
Other income (expense), net 654
455
199
1,670
703
967
Income tax expense (6,429 ) (6,590 ) 161
(16,316 ) (17,397 ) 1,081
Net income $ 12,010
$ 12,287
$ (277 ) $ 33,002
$ 33,237
$ (235 )

Electric Revenue by Customer Type
Three Months Ended September 30, Nine Months Ended September 30,
(in thousands)
2016 Percentage Change 2015 2016 Percentage Change 2015
Residential $ 17,501
(5)% $ 18,471
$ 53,057
(2)% $ 54,081
Commercial 25,714
(5)% 27,156
73,026
(4)% 76,330
Industrial 8,275
(1)% 8,364
24,540
(2)% 25,122
Municipal 1,053
3% 1,024
2,844
4% 2,741
Total retail revenue 52,543
(4)% 55,015
153,467
(3)% 158,274
Contract wholesale 4,596
1% 4,563
12,717
(9)% 13,962
Wholesale off-system 3,984
(26)% 5,417
11,304
(40)% 18,718
Other revenue 5,605
(21)% 7,116
19,901
2% 19,478
Total revenue $ 66,728
(7)% $ 72,111
$ 197,389
(6)% $ 210,432



	Three Months Ended June 30,									Six Months Ended June 30,
	2017			2016			Variance			2017			2016			Variance
	(in thousands)
Revenue	$	66,053		$	62,019		$	4,034		$	139,847		$	130,661		$	9,186
Fuel and purchased power	18,612			16,224			2,388			41,761			36,954			4,807
Gross margin	47,441			45,795			1,646			98,086			93,707			4,379

Operating expenses	29,729			26,859			2,870			56,998			53,991			3,007
Operating income	17,712			18,936			(1,224		)	41,088			39,716			1,372

Interest income (expense), net	(5,000		)	(4,824		)	(176		)	(10,437		)	(9,853		)	(584		)
Other income (expense), net	648			519			129			1,066			1,016			50
Income tax expense	(4,073		)	(4,825		)	752			(9,860		)	(9,887		)	27
Net income	$	9,287		$	9,806		$	(519	)	$	21,857		$	20,992		$	865

Megawatt Hours Sold by Customer Type
Three Months Ended September 30, Nine Months Ended September 30,
2016 Percentage Change 2015 2016 Percentage Change 2015
Residential 124,012
(3)% 128,474
381,616
(1)% 385,454
Commercial 213,276
(2)% 218,305
592,371
(2)% 603,272
Industrial 110,220
—% 109,725
320,861
(1)% 324,078
Municipal 9,927
6% 9,322
25,855
7% 24,058
Total retail quantity sold 457,435
(2)% 465,826
1,320,703
(1)% 1,336,862
Contract wholesale 62,547
(5)% 65,952
182,087
(15)% 215,119
Wholesale off-system 128,415
(17)% 154,215
438,852
(32)% 646,066
Total quantity sold 648,397
(5)% 685,993
1,941,642
(12)% 2,198,047
Losses and company use 41,585
(16)% 49,496
111,437
(10)% 123,135
Total energy 689,982
(6)% 735,489
2,053,079
(12)% 2,321,182

Megawatt Hours Generated and Purchased
Three Months Ended September 30, Nine Months Ended September 30,
Generated - 2016 Percentage Change 2015 2016 Percentage Change 2015
Coal-fired ^(a)
401,231
3% 389,784
1,054,264
(10)% 1,166,381
Gas-fired 41,654
10% 37,721
96,649
68% 57,482
Total generated 442,885
4% 427,505
1,150,913
(6)% 1,223,863

Total purchased 247,097
(20)% 307,984
902,166
(18)% 1,097,319
Total generated and purchased 689,982
(6)% 735,489
2,053,079
(12)% 2,321,182

~~____________________~~


~~(a)~~	~~Decrease is primarily due to a planned outage at Wygen III and an extended planned outage at Wyodak for the nine months ended September 30, 2016.~~

Power Plant Availability
Three Months Ended September 30, Nine Months Ended September 30,
2016 2015 2016 2015
Coal-fired plants ^(a)
92.8 % 93.6 % 83.2 % 92.1 %
Other plants 97.7 % 93.7 % 98.4 % 95.3 %
Total availability 95.6 % 93.7 % 91.8 % 93.9 %

~~____________________~~


~~(a)~~	~~Decrease is primarily due to a planned outage at Wygen III and an extended planned outage at Wyodak during the nine months ended September 30, 2016.~~

Degree Days Degree Days
Three Months Ended September 30, Nine Months Ended September 30,
2016 2015 2016 2015
Actual Variance from 30-year Average Actual Variance from 30-year Average Actual Variance from 30-year Average Actual Variance from 30-year Average

Heating degree days 161
(23 )% 127
(40 )% 3,844
(13 )% 4,005
(10 )%
Cooling degree days 460
(18 )% 477
(15 )% 646
(3 )% 573
(14 )%

Three Months Ended ~~September~~June 30, ~~2016~~2017 Compared to Three Months Ended ~~September~~June 30, ~~2015.~~2016. Net income was $129.3 million compared to $129.8 million for the same period in the prior year primarily due to the following:

Gross margin ~~decreased~~increased over the prior year reflecting a $2.5 million increase in rider revenues primarily ~~due~~related to transmission investment recovery. Partially offsetting these increases was $0.4 million in lower ~~retail volumes and the impact of a decrease in~~residential margins driven primarily by lower cooling degree days. Compared to normal, cooling degree days were 15% higher than normal in the current year compared to 74% higher than normal for the same period in the prior year.

~~Operations and maintenance~~Operating expenses ~~decreased~~increased primarily due to ~~lower~~higher employee costs ~~driven by a change in operating expense allocations impacting us~~ as a result of prior year integration activities and transition expenses charged to our Parent Company ~~integrating the acquired~~related to its prior year acquisition of SourceGas, ~~utilities~~higher property taxes with increased asset base, and ~~lower generation and outside services, partially offset by~~increased maintenance costs from higher ~~depreciation expense driven by additional plant in service compared to the same period in the prior year.~~outages.

Interest expense, net ~~decreased primarily due to higher AFUDC income in the current year driven by higher construction work-in-process balances compared~~was comparable to the same period in the prior year.

Other income, net was comparable to the same period in the prior year.

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

~~Nine~~Six Months Ended ~~September~~June 30, ~~2016~~2017 Compared to ~~Nine~~Six Months Ended ~~September~~June 30, ~~2015.~~2016. Net income was ~~$33~~$22 million compared to ~~$33~~$21 million for the same period in the prior year primarily due to the following:

Gross margin ~~decreased~~increased over the prior year reflecting a $3.0 million increase in rider revenues primarily related to transmission investment recovery.

Operating expenses increased primarily due to a prior year increase in return on invested capital of $1.2 million from a rate case, a $1.8 million decrease due to third party billing true-ups related to the current and prior years and a decrease in commercial MW sold driven by lower demand, partially offset by the weather impact from the increase in cooling degree days compared to the same period in the prior year.

~~Operations and maintenance~~ ~~decreased primarily due to lower~~higher employee costs ~~driven by a change in operating expense allocations impacting us~~ as a result of prior year integration activities and transition expenses charged to our Parent Company ~~integrating the acquired~~related to its prior year acquisition of SourceGas, ~~utilities, partially offset by~~ higher ~~depreciation expense driven by additional plant in service compared to the same period in the prior year.~~property taxes with increased asset base, and increased maintenance costs from higher outages.

Other income, net was comparable to the same period in the prior year.

Income tax ~~expense~~expense:: The effective tax rate was comparable to the same period in the prior year.



	Electric Revenue by Customer Type
	Three Months Ended June 30,					Six Months Ended June 30,
	(in thousands)
	2017		Percentage Change	2016		2017		Percentage Change	2016
Residential	$	15,633	(4)%	$	16,241	$	35,704	—%	$	35,556
Commercial	22,858		(4)%	23,723		47,149		—%	47,312
Industrial	8,171		5%	7,764		16,625		2%	16,265
Municipal	942		(2)%	960		1,778		(1)%	1,791
Total retail revenue	47,604		(2)%	48,688		101,256		—%	100,924
Contract wholesale ^(a)	6,702		70%	3,947		14,545		79%	8,121
Wholesale off-system ^(b)	2,424		(11)%	2,734		6,257		(15)%	7,320
Other revenue ^(c)	9,323		40%	6,650		17,789		24%	14,296
Total revenue	$	66,053	7%	$	62,019	$	139,847	7%	$	130,661

____________________


(a)	Increase for the three and six months ended June 30, 2017 was primarily due to a new 50 MW power sales agreement with Cargill effective January 1, 2017.


(b)	Decrease in 2017 revenue was primarily driven by commodity prices that impacted power marketing sales.


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



	Megawatt Hours Sold by Customer Type
	Three Months Ended June 30,			Six Months Ended June 30,
	2017	Percentage Change	2016	2017	Percentage Change	2016
Residential	107,521	(6)%	114,851	257,093	—%	257,604
Commercial	173,720	(9)%	190,207	370,126	(2)%	379,095
Industrial	103,497	1%	102,620	213,293	1%	210,641
Municipal	8,104	(5)%	8,487	15,709	(1)%	15,928
Total retail quantity sold	392,842	(6)%	416,165	856,221	(1)%	863,268
Contract wholesale ^(a)	165,881	196%	56,087	351,997	194%	119,540
Wholesale off-system ^(b)	102,966	(12)%	117,064	257,462	(17)%	310,437
Total quantity sold	661,689	12%	589,316	1,465,680	13%	1,293,245
Losses and company use ^(c)	57,189	87%	30,528	99,030	42%	69,852
Total energy	718,878	16%	619,844	1,564,710	15%	1,363,097

____________________


(a)	Increase for the three and six months ended June 30, 2017 was primarily due to a new 50 MW power sales agreement with Cargill effective January 1, 2017.


(b)	Decrease in 2017 sales was primarily driven by commodity prices that impacted power marketing sales.


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



	Megawatt Hours Generated and Purchased
	Three Months Ended June 30,			Six Months Ended June 30,
Generated -	2017	Percentage Change	2016	2017	Percentage Change	2016
Coal-fired	289,540	9%	265,032	677,525	4%	653,033
Gas-fired ^(a)	11,024	(72)%	39,433	21,374	(61)%	54,995
Total generated	300,564	(1)%	304,465	698,899	(1)%	708,028

Total purchased ^(b)	418,314	33%	315,379	865,811	32%	655,069
Total generated and purchased ^(b)	718,878	16%	619,844	1,564,710	15%	1,363,097

____________________


(a)	Decrease is primarily due to the ability to purchase excess generation in the open market at a lower cost than to generate for the three and six months ended June 30, 2017.


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



	Power Plant Availability
	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Coal-fired plants ^(a)	67.6	%	64.5	%	78.4	%	78.4	%
Other plants	98.0	%	99.2	%	98.7	%	98.7	%
Total availability	83.7	%	84.2	%	89.2	%	90.0	%

____________________


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



	Degree Days						Degree Days
	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	Actual	Variance from 30-year Average		Actual	Variance from 30-year Average		Actual	Variance from 30-year Average		Actual	Variance from 30-year Average

Heating degree days	910	(11	)%	877	(13	)%	4,040	(5	)%	3,683	(13	)%
Cooling degree days	114	15	%	186	74	%	114	15	%	186	74	%

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~~June 30, ~~2016:~~2017:



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

FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements as defined by the SEC. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words “anticipates”, “estimates”, “expects”, “intends”, “plans”, “predicts” and similar expressions, and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 2 - Management’s Discussion & Analysis of Financial Condition and Results of Operations.

Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. Nonetheless, the Company’s expectations, beliefs or projections may not be achieved or accomplished.

Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements described in Item 1A of our ~~2015~~2016 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, ~~2015.~~2016.

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~~June 30, ~~2016.~~2017. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective as of ~~September~~June 30, ~~2016.~~2017.

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~~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~~June 30, ~~2016~~2017, 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 ~~2015~~2016 Annual Report on Form 10-K and Note 8 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.


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, ~~2015.~~2016.


Item 6.	Exhibits


Exhibit 3.1*	Restated Articles of Incorporation of the Registrant dated March 30, 2015 (filed as Exhibit 3.1 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2015).


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

Exhibit 4.1*

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


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


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


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


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


Exhibit 101	Financial Statements for XBRL Format

_________________________


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

BLACK HILLS POWER, INC.

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

BLACK HILLS POWER, INC.

/S/ DAVID R. EMERY

David R. Emery, Chairman

and Chief Executive Officer

/S/ RICHARD W. KINZLEY

Richard W. Kinzley, Senior Vice President

and Chief Financial Officer

Dated: ~~November 4, 2016~~August 8, 2017

EXHIBIT INDEX


Exhibit Number	Description


Exhibit 3.1*	Restated Articles of Incorporation of the Registrant dated March 30, 2015 (filed as Exhibit 3.1 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2015).


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*


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


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


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


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


Exhibit 101	Financial Statements for XBRL Format

_________________________


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

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