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, 2016~~March 31, 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 31, 2016,~~April 30, 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~~ Months Ended ~~September 30,~~March 31, 2017 and 2016 ~~and 2015~~

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

	Condensed Statements of Cash Flows - unaudited	7
	~~Nine~~Three Months Ended ~~September 30,~~March 31, 2017 and 2016 ~~and 2015~~

	Notes to Condensed Financial Statements - unaudited	8

Item 2.	Managements’ Discussion and Analysis of Financial Condition and Results of Operations	14

Item 4.	Controls and Procedures	1817

PART II.	OTHER INFORMATION	1918

Item 1.	Legal Proceedings	1918

Item 1A.	Risk Factors	1918

Item 6.	Exhibits	1918

	Signatures	2019

	Exhibit Index	2120

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~~	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.
FASB	Financial Accounting Standards Board
FERC	United States Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Accounting principles generally accepted in the United States of America
Happy Jack	Happy Jack Wind Farms, LLC, a subsidiary of Duke Energy Generation Services
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~~	~~Megawatt-hours~~
SEC	U. S. Securities and Exchange Commission
Silver Sage	Silver Sage Windpower, LLC, a subsidiary of Duke Energy Generation Services
S&P	Standard & Poor’s, a division of The McGraw-Hill Companies, Inc.
~~WPSC~~	~~Wyoming Public Service Commission~~
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 March 31,
(unaudited)	2016			2015			2016			2015			2017			2016
	(in thousands)												(in thousands)
Revenue	$	66,728		$	72,111		$	197,389		$	210,432		$	73,794		$	68,642

Operating expenses:
Fuel and purchased power	18,421			21,983			55,375			63,440			23,149			20,730
Operations and maintenance	15,601			16,979			49,538			52,191			16,954			17,031
Depreciation and amortization	8,547			8,248			25,363			24,215			8,694			8,612
Taxes - property	1,749			1,445			4,987			4,497			1,621			1,489
Total operating expenses	44,318			48,655			135,263			144,343			50,418			47,862

Operating income	22,410			23,456			62,126			66,089			23,376			20,780

Other income (expense):
Interest expense	(5,454		)	(5,542		)	(16,322		)	(16,914		)	(6,336		)	(5,454		)
AFUDC - borrowed	319			239			840			322			192			223
Interest income	510			269			1,004			434			707			202
AFUDC - equity	606			434			1,595			584			471			423
Other income (expense), net	48			21			75			119			(53		)	74
Total other income (expense)	(3,971		)	(4,579		)	(12,808		)	(15,455		)	(5,019		)	(4,532		)

Income from continuing operations before income taxes	18,439			18,877			49,318			50,634			18,357			16,248
Income tax expense	(6,429		)	(6,590		)	(16,316		)	(17,397		)	(5,787		)	(5,062		)
Net income	12,010			12,287			33,002			33,237			12,570			11,186

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 $(6) and $(6) for the three months ended March 31, 2017 and 2016, respectively)													10			10
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(8) and $(7) for the three months ended March 31, 2017 and 2016, respectively)													14			14
Other comprehensive income	24			26			72			419			24			24

Comprehensive income	$	12,034		$	12,313		$	33,074		$	33,656		$	12,594		$	11,210

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			March 31, 2017			December 31, 2016
	(in thousands)						(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	10,250		$	7,559		$	1,127		$	234
Receivables - customers, net	25,633			27,856			27,457			30,614
Receivables - affiliates	5,216			5,747			5,390			9,526
Other receivables, net	453			236			420			351
Money pool notes receivable, net	51,279			76,813			32,949			28,409
Materials, supplies and fuel	21,364			24,282			23,244			22,389
Regulatory assets, current	18,212			14,096			20,536			18,119
Other, current assets	3,634			43,118			3,286			3,876
Total current assets	136,041			199,707			114,409			113,518

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

Property, plant and equipment	1,216,000			1,166,126			1,254,710			1,236,387
Less accumulated depreciation and amortization	(334,546		)	(326,074		)	(342,400		)	(338,828		)
Total property, plant and equipment, net	881,454			840,052			912,310			897,559

Other assets:
Regulatory assets, non-current	72,403			71,717			73,445			74,015
Other, non-current assets	3,900			152			3,545			3,816
Total other assets	76,303			71,869			76,990			77,831
TOTAL ASSETS	$	1,098,615		$	1,116,353		$	1,108,558		$	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			March 31, 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		$	16,809		$	14,158
Accounts payable - affiliates	30,284			30,032			27,289			31,799
Accrued liabilities	32,286			69,454			44,891			37,436
Regulatory liabilities, current	52			—			—			84
Total current liabilities	83,269			120,783			88,989			83,477

Long-term debt	339,721			339,616			339,791			339,756

Deferred credits and other liabilities:
Deferred income tax liability, net, non-current	212,276			188,961			214,657			211,443
Regulatory liabilities, non-current	53,344			51,583			53,896			53,866
Benefit plan liabilities	20,161			20,033			19,617			19,544
Other, non-current liabilities	1,291			3,398			1,351			1,001
Total deferred credits and other liabilities	287,072			263,975			289,521			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			328,504			322,933
Accumulated other comprehensive loss	(1,235		)	(1,307		)	(1,238		)	(1,262		)
Total stockholder’s equity	388,553			391,979			390,257			384,662
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	1,098,615		$	1,116,353		$	1,108,558		$	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,						Three Months Ended March 31,
	2016			2015			2017			2016
	(in thousands)						(in thousands)
Operating activities:
Net income	$	33,002		$	33,237		$	12,570		$	11,186
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization	25,363			24,215			8,694			8,612
Deferred income tax	22,267			8,161			2,704			18,076
Employee benefits	1,327			1,802			205			443
AFUDC - equity	(1,595		)	(584		)	(471		)	(423		)
Other adjustments, net	118			139			559			296
Change in operating assets and liabilities -
Accounts receivable and other current assets	5,499			1,291			7,908			(3,409		)
Accounts payable and other current liabilities	1,662			5,638			(380		)	(7,656		)
Regulatory assets - current	(4,029		)	(1,848		)	(2,170		)	(4,193		)
Regulatory liabilities - current	—			(2,479		)	(84		)	—
Contributions to defined benefit pension plan	(820		)	—
Other operating activities, net	(3,994		)	8,019			(152		)	481
Net cash provided by (used in) operating activities	78,800			77,591			29,383			23,413

Investing activities:
Property, plant and equipment additions	(65,062		)	(39,338		)	(16,976		)	(18,928		)
Change in money pool notes receivable, net	(10,966		)	(14,694		)	(11,540		)	13,683
Other investing activities	(81		)	(103		)	26			(27		)
Net cash provided by (used in) investing activities	(76,109		)	(54,135		)	(28,490		)	(5,272		)

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

Net change in cash and cash equivalents	2,691			23,456			893			18,141

Cash and cash equivalents, beginning of period	7,559			6,620			234			297
Cash and cash equivalents, end of period	$	10,250		$	30,076		$	1,127		$	18,438

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 30, 2016~~March 31, 2017, December 31, ~~2015~~2016 and ~~September 30, 2015~~March 31, 2016 financial information and are of a normal recurring nature. The results of operations for the three ~~and nine~~ months ended ~~September 30, 2016~~March 31, 2017 and ~~September 30, 2015~~March 31, 2016, and our financial condition as of ~~September 30, 2016~~March 31, 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 years’ financial information to conform to the current year presentation.

We revised our presentation of cash and certain cash transactions processed on behalf of affiliates. 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 $11 million as of March 31, 2016. It also decreased net cash flows provided by operations by $3.3 million for the three months ended March 31, 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 March 31, 2016 and to the Statements of Cash Flows for the three months ended March 31, 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. ASU 2017-07 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. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. We are currently assessing the changes to the standard. 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.

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 ASU requires changes in the presentation of certain items including but not limited to debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. 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. ~~We are currently assessing the impact that~~The adoption of ~~ASU 2016-15~~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 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability for all leases with terms of more than 12 months. Lessees are permitted to make an accounting policy election to not recognize the asset and liability for leases with a term of 12 months or less. 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 is largely unchanged from the previous accounting standard. In addition, the ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which includes a number of practical expedients. The guidance is effective for us beginning after December 15, 2018. Early adoption is permitted. We are currently assessing the impact that adoption of ASU 2016-02 will have on our financial position, results of operations or 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 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 disclosure of the fair value of certain plan assets in our pension and other postretirement benefit plan disclosures 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 to a recognized debt liability are presented on the balance sheet 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.

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 will adopt this standard for annual and interim reporting periods beginning after December 15, 2017. 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 electricity with a defined contractual term. For such arrangements, we expect that the revenue from contracts with the customer will be equivalent to the electricity delivered in that period. Therefore, we do not expect that 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 those tied to longer term contractual commitments. However, a number of industry-specific implementation issues are still unresolved and the final resolution of these issues could impact our current accounting policies and/or patterns for revenue recognition, as well as the transition method selected.


(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			March 31, 2017			December 31, 2016
Accounts receivable trade	$	15,171		$	15,268		$	16,197		$	16,972
Unbilled revenues	10,651			12,795			11,524			13,799
Allowance for doubtful accounts	(189		)	(207		)	(264		)	(157		)
Receivables - customers, net	$	25,633		$	27,856		$	27,457		$	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)	March 31, 2017		December 31, 2016
Regulatory assets:
Unamortized loss on reacquired debt ^(a)	8	$	1,885	$	2,096	8	$	1,745	$	1,815
AFUDC ^(b)	45	9,184		8,571
Deferred taxes on AFUDC ^(b)						45	9,607		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	23,075		23,016
Flow through accounting ^(a)	35	12,498		12,104
Deferred taxes on flow through accounting ^(a)						35	12,802		12,545
Decommissioning costs, net of amortization^(b)	9	12,625		13,686		8	12,025		12,456
Other regulatory assets ^(a) ^(d)	2	10,741		8,615		2	14,627		12,835
Total regulatory assets		$	90,615	$	85,813		$	93,981	$	92,134


Regulatory liabilities:
Cost of removal for utility plant ^(a)	44	$	40,728	$	38,131	61	$	41,592	$	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	—		105
Total regulatory liabilities		$	53,396	$	51,583		$	53,896	$	53,950

____________________


(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 approximately ~~$9.8~~$14 million and ~~$5.0~~$12 million of vegetation management expenses at ~~September 30, 2016~~March 31, 2017 and December 31, ~~2015,~~2016, respectively, for which we are allowed a rate of return.


(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		March 31, 2017		December 31, 2016
Receivables - affiliates	$	5,216	$	5,747	$	5,390	$	9,526
Accounts payable - affiliates	$	30,284	$	30,032	$	27,289	$	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 30, 2016~~March 31, 2017, the average cost of borrowing under the Utility Money Pool was ~~1.81%~~1.47%.

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



	March 31, 2017		December 31, 2016
Money pool notes receivable, net	$	32,949	$	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

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


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2016		2015		2016		2015		2017		2016
Revenue:
Energy sold to Cheyenne Light	$	599	$	553	$	1,908	$	1,258	$	878	$	661
Rent from electric properties	$	1,229	$	1,158	$	3,817	$	3,614	$	1,272	$	1,213

Fuel and purchased power:
Purchases of coal from WRDC	$	4,122	$	4,580	$	12,275	$	12,724	$	4,280	$	4,796
Purchase of excess energy from Cheyenne Light	$	64	$	111	$	172	$	800	$	40	$	55
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	312	$	268	$	1,329	$	1,097	$	606	$	664
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	547	$	476	$	2,276	$	1,910	$	1,019	$	1,127

Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	100	$	103	$	300	$	310	$	99	$	136

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	$	6,611	$	6,721


(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 March 31,
	2016			2015			2016			2015			2017			2016
Service cost	$	151		$	199		$	453		$	597		$	136		$	151
Interest cost	625			739			1,875			2,217			585			625
Expected return on plan assets	(908		)	(984		)	(2,724		)	(2,952		)	(897		)	(908		)
Prior service cost	11			11			33			33			11			11
Net loss (gain)	498			549			1,496			1,647			307			499
Net periodic benefit cost	$	377		$	514		$	1,133		$	1,542		$	142		$	378

Defined Benefit Postretirement Healthcare Plan

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


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2016			2015			2016			2015			2017			2016
Service cost	$	51		$	59		$	153		$	176		$	52		$	51
Interest cost	47			53			141			160			44			47
Prior service cost (benefit)	(84		)	(84		)	(252		)	(252		)	(84		)	(84		)
Net periodic benefit cost	$	14		$	28		$	42		$	84		$	12		$	14

Supplemental Non-qualified Defined Benefit Plans

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


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2016		2015		2016		2015		2017		2016
Interest cost	$	30	$	35	$	90	$	107	$	29	$	30
Net loss (gain)	20		23		62		69		22		21
Net periodic benefit cost	$	50	$	58	$	152	$	176	$	51	$	51

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.~~Trust. 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 Three Months Ended March 31, 2017		Remaining Anticipated Contributions for 2017		Anticipated Contributions for 2018
Defined Benefit Pension Plan	$	820	$	—	$	1,615	$	—	$	1,305	$	660
Defined Benefit Postretirement Healthcare Plan	$	464	$	155	$	509	$	135	$	406	$	565
Supplemental Non-qualified Defined Benefit Plans	$	162	$	54	$	248	$	62	$	185	$	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				March 31, 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	$	1,127	$	1,127	$	234	$	234
Long-term debt, including current maturities^(b)	$	339,721	$	445,104	$	339,616	$	404,864	$	339,791	$	424,453	$	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 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
Three months ended March 31,							2017			2016
	(in thousands)						(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	5,565		$	2,074		$	10,998		$	5,087
Non-cash (decrease) to money pool notes receivable, net	$	(36,500	)	$	(18,500	)	$	(7,000	)	$	(12,500	)
Non-cash dividend to Parent	$	36,500		$	18,500		$	7,000		$	12,500

Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(13,486	)	$	(14,192	)	$	(3,014	)	$	(2,989	)


(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 the first quarter of 2016, we commenced construction of the $54 million, 230-kV, 144 mile-long transmission line that will connect 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 on August 31, 2016. The second segment of the project is expected to be placed in service in the first half of 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,									Three Months Ended March 31,
	2016			2015			Variance			2016			2015			Variance			2017			2016			Variance
	(in thousands)																		(in thousands)
Revenue	$	66,728		$	72,111		$	(5,383	)	$	197,389		$	210,432		$	(13,043	)	$	73,794		$	68,642		$	5,152
Fuel and purchased power	18,421			21,983			(3,562		)	55,375			63,440			(8,065		)	23,149			20,730			2,419
Gross margin	48,307			50,128			(1,821		)	142,014			146,992			(4,978		)	50,645			47,912			2,733

Operating expenses	25,897			26,672			(775		)	79,888			80,903			(1,015		)	27,269			27,132			137
Operating income	22,410			23,456			(1,046		)	62,126			66,089			(3,963		)	23,376			20,780			2,596

Interest income (expense), net	(4,625		)	(5,034		)	409			(14,478		)	(16,158		)	1,680			(5,437		)	(5,029		)	(408		)
Other income (expense), net	654			455			199			1,670			703			967			418			497			(79		)
Income tax expense	(6,429		)	(6,590		)	161			(16,316		)	(17,397		)	1,081			(5,787		)	(5,062		)	(725		)
Net income	$	12,010		$	12,287		$	(277	)	$	33,002		$	33,237		$	(235	)	$	12,570		$	11,186		$	1,384

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

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 30, 2016~~March 31, 2017 Compared to Three Months Ended ~~September 30, 2015.~~March 31, 2016. Net income was $1213 million compared to $1211 million for the same period in the prior year primarily due to the following:

Gross margin ~~decreased~~increased primarily due to ~~lower retail volumes~~higher transmission revenue and ~~the impact of a decrease in cooling degree days~~colder weather as compared to the same period in the prior year.

~~Operations and maintenance~~Operating expenses decreased primarily due to lower employee costs driven by a change in operating expense allocations impacting us as a result of our Parent Company integrating the acquired SourceGas utilities and lower generation and outside services, partially offset by higher depreciation expense driven by additional plant in service comparedwere comparable to the same period in the prior year.

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 to the same period in the prior year.



	Electric Revenue by Customer Type
	Three Months Ended March 31,
	(in thousands)
	2017		Percentage Change	2016
Residential	$	20,071	4%	$	19,315
Commercial	24,291		3%	23,589
Industrial	8,454		(1)%	8,501
Municipal	836		1%	831
Total retail revenue	53,652		3%	52,236
Contract wholesale ^(a)	7,843		88%	4,174
Wholesale off-system ^(b)	3,833		(16)%	4,586
Other revenue	8,466		11%	7,646
Total revenue	$	73,794	8%	$	68,642

____________________


(a)	Increase from the prior year is primarily due to a new power-sales agreement which was effective January 1, 2017.


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



	Megawatt Hours Sold by Customer Type
	Three Months Ended March 31,
	2017	Percentage Change	2016
Residential	149,572	5%	142,753
Commercial	196,406	4%	188,888
Industrial	109,796	2%	108,021
Municipal	7,605	2%	7,441
Total retail quantity sold	463,379	4%	447,103
Contract wholesale ^(a)	186,116	193%	63,453
Wholesale off-system ^(b)	154,496	(20)%	193,373
Total quantity sold	803,991	14%	703,929
Losses and company use	41,841	6%	39,324
Total energy	845,832	14%	743,253

____________________


(a)	Effective January 1, 2017, we have an energy sales agreement with Cargill through December 31, 2021 to supply 50 MW of energy during heavy and light load timing intervals.


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

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



	Megawatt Hours Generated and Purchased
	Three Months Ended March 31,
Generated -	2017	Percentage Change	2016
Coal-fired	387,985	—%	388,001
Gas-fired ^(a)	10,350	(33)%	15,562
Total generated	398,335	(1)%	403,563

Total purchased ^(b)	447,497	32%	339,690
Total generated and purchased ^(b)	845,832	14%	743,253

____________________


(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 months ended March 31, 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 March 31,
	2017		2016
Coal-fired plants ^(a)	89.2	%	92.4	%
Other plants	99.4	%	98.3	%
Total availability	94.6	%	95.8	%

____________________


(a)	Decrease is primarily due to a planned outage at Neil Simpson II during the three months ended March 31, 2017.

~~Gross margin~~ decreased 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 employee costs driven by a change in operating expense allocations impacting us as a result of our Parent Company integrating the acquired SourceGas utilities, partially offset by higher depreciation expense driven by additional plant in service compared to the same period in the prior year.

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

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

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



	Degree Days
	Three Months Ended March 31,
	2017			2016
	Actual	Variance from 30-year Average		Actual	Variance from 30-year Average

Heating degree days	3,130	(3	)%	2,806	(13	)%

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, 2016:~~March 31, 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 30, 2016.~~March 31, 2017. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective as of ~~September 30, 2016.~~March 31, 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 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, 2016~~March 31, 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~~May 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.

2120

Three Months Ended March 31,

Net interest income (expense)