10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended June 30, 2016
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from __________ to __________.

Commission File Number 1-7978

Black Hills Power, Inc.

Incorporated in South Dakota  IRS Identification Number 46-0111677

625 Ninth Street, 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 in Rule 12b-2 of the Exchange Act).

Large accelerated filer	o	Accelerated filer	o
Non-accelerated filer	x	Smaller reporting company	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 July 31, 2016, 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 Six Months Ended June 30, 2016 and 2015
	Condensed Balance Sheets - unaudited	5
	June 30, 2016 and December 31, 2015
	Condensed Statements of Cash Flows - unaudited	7
	Six Months Ended June 30, 2016 and 2015
	Notes to Condensed Financial Statements - unaudited	8
Item 2.	Managements’ Discussion and Analysis of Financial Condition and Results of Operations	13
Item 4.	Controls and Procedures	17
PART II.	OTHER INFORMATION	18
Item 1.	Legal Proceedings	18
Item 1A.	Risk Factors	18
Item 6.	Exhibits	18
	Signatures	19
	Exhibit Index	20

2

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
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	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Generally Accepted Accounting Principles 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 Investor Services, 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 Rating Services
WRDC	Wyodak Resources Development Corp., an indirect, wholly-owned subsidiary of BHC

3

BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

	Three Months Ended June 30,						Six Months Ended June 30,
(unaudited)	2016			2015			2016			2015
	(in thousands)
Revenue	$	62,019		$	68,038		$	130,661		$	138,321
Operating expenses:
Fuel and purchased power	16,224			19,353			36,954			41,457
Operations and maintenance	16,906			18,121			33,937			35,212
Depreciation and amortization	8,204			7,842			16,816			15,967
Taxes - property	1,749			1,579			3,238			3,052
Total operating expenses	43,083			46,895			90,945			95,688
Operating income	18,936			21,143			39,716			42,633
Other income (expense):
Interest expense	(5,414		)	(5,680		)	(10,868		)	(11,372		)
AFUDC - borrowed	298			44			521			83
Interest income	292			61			494			165
AFUDC - equity	566			80			989			150
Other income (expense), net	(47		)	63			27			98
Total other income (expense)	(4,305		)	(5,432		)	(8,837		)	(10,876		)
Income from continuing operations before income taxes	14,631			15,711			30,879			31,757
Income tax expense	(4,825		)	(5,164		)	(9,887		)	(10,807		)
Net income	9,806			10,547			20,992			20,950
Other comprehensive income (loss):
Reclassification adjustments of cash flow hedges settled and included in net income (net of tax (expense) benefit of $(5) and $(6) for the three months ended June 30, 2016 and 2015 and $(11) and $330 for the six months ended June 30, 2016 and 2015, respectively)	11			10			21			362
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(7) and $(8) for the three months ended June 30, 2016 and 2015 and $(14) and $(16) for the six months ended June 30, 2016 and 2015, respectively)	13			16			27			31
Other comprehensive income	24			26			48			393
Comprehensive income	$	9,830		$	10,573		$	21,040		$	21,343

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

4

BLACK HILLS POWER, INC.

CONDENSED BALANCE SHEETS

(unaudited)	June 30, 2016			December 31, 2015
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	19,625		$	7,559
Receivables - customers, net	27,283			27,856
Receivables - affiliates	5,492			5,747
Other receivables, net	169			236
Money pool notes receivable, net	56,599			76,813
Materials, supplies and fuel	22,017			24,282
Regulatory assets, current	21,297			14,096
Other, current assets	3,846			43,118
Total current assets	156,328			199,707
Investments	4,800			4,725
Property, plant and equipment	1,191,724			1,166,126
Less accumulated depreciation and amortization	(333,053		)	(326,074		)
Total property, plant and equipment, net	858,671			840,052
Other assets:
Regulatory assets, non-current	68,854			71,717
Other, non-current assets	3,835			152
Total other assets	72,689			71,869
TOTAL ASSETS	$	1,092,488		$	1,116,353

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

5

BLACK HILLS POWER, INC.

CONDENSED BALANCE SHEETS

(unaudited)	June 30, 2016			December 31, 2015
	(in thousands, except common stock par value and share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	30,098		$	21,297
Accounts payable - affiliates	25,719			30,032
Accrued liabilities	25,832			69,454
Regulatory liabilities, current	34			—
Total current liabilities	81,683			120,783
Long-term debt	339,686			339,616
Deferred credits and other liabilities:
Deferred income tax liability, net, non-current	207,886			188,961
Regulatory liabilities, non-current	52,672			51,583
Benefit plan liabilities	19,857			20,033
Other, non-current liabilities	2,185			3,398
Total deferred credits and other liabilities	282,600			263,975
Commitments and contingencies (Notes 4, 5 and 8)
Stockholder’s equity:
Common stock $1 par value; 50,000,000 shares authorized; 23,416,396 shares issued	23,416			23,416
Additional paid-in capital	39,575			39,575
Retained earnings	326,787			330,295
Accumulated other comprehensive loss	(1,259		)	(1,307		)
Total stockholder’s equity	388,519			391,979
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	1,092,488		$	1,116,353

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

6

BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(unaudited)	Six Months Ended June 30,
	2016			2015
	(in thousands)
Operating activities:
Net income	$	20,992		$	20,950
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization	16,816			15,967
Deferred income tax	18,009			10,080
Employee benefits	886			1,202
AFUDC - equity	(989		)	(150		)
Other adjustments, net	(236		)	291
Change in operating assets and liabilities -
Accounts receivable and other current assets	3,234			6,094
Accounts payable and other current liabilities	538			(11,358		)
Regulatory assets - current	(7,026		)	(3,033		)
Regulatory liabilities - current	—			(2,479		)
Contributions to defined benefit pension plan	(820		)	—
Other operating activities, net	168			(2,409		)
Net cash provided by (used in) operating activities	51,572			35,155
Investing activities:
Property, plant and equipment additions	(35,153		)	(17,009		)
Change in money pool notes receivable, net	(4,286		)	55,145
Other investing activities	(67		)	(90		)
Net cash provided by (used in) investing activities	(39,506		)	38,046
Financing activities:
Net cash provided by (used in) financing activities	—			—
Net change in cash and cash equivalents	12,066			73,201
Cash and cash equivalents, beginning of period	7,559			6,620
Cash and cash equivalents, end of period	$	19,625		$	79,821

See Note 7 for supplemental cash flow information.

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

7

BLACK HILLS POWER, INC.

Notes to Condensed Financial Statements

(unaudited)

(Reference is made to Notes to Financial Statements

included in our 2015 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 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 all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the June 30, 2016, December 31, 2015 and June 30, 2015 financial information and are of a normal recurring nature. The results of operations for the three and six months ended June 30, 2016 and June 30, 2015, and our financial condition as of June 30, 2016 and December 31, 2015 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

Recently Issued and Adopted Accounting Standards

Leases, ASU 2016-02

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a 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 June 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.

8

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 revenue when the risks and rewards transfer to the customer under the existing revenue guidance. On July 9, 2015, FASB voted to defer the effective date of ASU 2014-09 by one year. The proposed guidance would be effective for annual and interim reporting periods beginning after December 15, 2017 and early adoption is permitted. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption. We are currently evaluating the impact of adoption, if any, that ASU 2014-09 will have on our financial position, results of operations or cash flows.

(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:

	June 30, 2016			December 31, 2015
Accounts receivable trade	$	15,519		$	15,268
Unbilled revenues	11,989			12,795
Allowance for doubtful accounts	(225		)	(207		)
Receivables - customers, net	$	27,283		$	27,856

(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)	June 30, 2016		December 31, 2015
Regulatory assets:
Unamortized loss on reacquired debt (a)	8	$	1,955	$	2,096
AFUDC (b)	45	8,945		8,571
Employee benefit plans (c)	12	20,866		20,866
Deferred energy and fuel cost adjustments - current (a)	Less than 1 year	21,800		19,875
Flow through accounting (a)	35	12,617		12,104
Decommissioning costs, net of amortization(b)	9	13,255		13,686
Other regulatory assets (a)(d)	2	10,713		8,615
Total regulatory assets		$	90,151	$	85,813

Regulatory liabilities:
Cost of removal for utility plant (a)	53	$	40,056	$	38,131
Employee benefit plans (c)	12	12,616		12,616
Other regulatory liabilities	13	34		836
Total regulatory liabilities		$	52,706	$	51,583

____________________

(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 $7.0 million and $5.0 million of vegetation management expenses at June 30, 2016 and December 31, 2015, respectively, for which we are allowed a rate of return.

9

(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:

	June 30, 2016		December 31, 2015
Receivables - affiliates	$	5,492	$	5,747
Accounts payable - affiliates	$	25,719	$	30,032

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 borrowings as defined under the Agreement, or if there are no external funds outstanding on that date, then the rate will be the daily one-month LIBOR plus 1.0%. At June 30, 2016, the average cost of borrowing under the Utility Money Pool was 1.75%.

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

	June 30, 2016		December 31, 2015
Money pool notes receivable, net	$	56,599	$	76,813

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Net interest income (expense)	$	290	$	288	$	568	$	546

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Revenue:
Energy sold to Cheyenne Light	$	648	$	379	$	1,309	$	705
Rent from electric properties	$	1,375	$	1,332	$	2,588	$	2,456
Fuel and purchased power:
Purchases of coal from WRDC	$	3,357	$	4,099	$	8,153	$	8,144
Purchase of excess energy from Cheyenne Light	$	53	$	213	$	108	$	689
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	353	$	280	$	1,017	$	829
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	602	$	498	$	1,729	$	1,434
Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	100	$	103	$	200	$	207
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	6,177	$	6,627	$	12,898	$	13,660

10

(5) EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

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 June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Service cost	$	151		$	199		$	302		$	398
Interest cost	625			739			1,250			1,478
Expected return on plan assets	(908		)	(984		)	(1,816		)	(1,968		)
Prior service cost	11			11			22			22
Net loss (gain)	499			549			998			1,098
Net periodic benefit cost	$	378		$	514		$	756		$	1,028

Defined Benefit Postretirement Healthcare Plan

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Service cost	$	51		$	59		$	102		$	117
Interest cost	47			53			94			107
Prior service cost (benefit)	(84		)	(84		)	(168		)	(168		)
Net periodic benefit cost	$	14		$	28		$	28		$	56

Supplemental Non-qualified Defined Benefit Plans

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Interest cost	$	30	$	36	$	60	$	72
Net loss (gain)	21		23		42		46
Net periodic benefit cost	$	51	$	59	$	102	$	118

11

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. Contributions to the Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions and anticipated contributions are as follows (in thousands):

	Contributions Six Months Ended June 30, 2016		Remaining Anticipated Contributions for 2016		Anticipated Contributions for 2017
Defined Benefit Pension Plan	$	820	$	—	$	1,615
Defined Benefit Postretirement Healthcare Plan	$	309	$	309	$	509
Supplemental Non-qualified Defined Benefit Plans	$	108	$	108	$	248

(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 Annual Report on Form 10-K filed with the SEC.

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

	June 30, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	19,625	$	19,625	$	7,559	$	7,559
Long-term debt, including current maturities (b)	$	339,686	$	445,571	$	339,616	$	404,864

_________________

(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

Six months ended June 30,	2016			2015
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	5,355		$	2,225
Non-cash (decrease) to money pool notes receivable, net	$	(24,500	)	$	(6,500	)
Non-cash dividend to Parent	$	24,500		$	6,500
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(10,547	)	$	(11,063	)

(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 Annual Report on Form 10-K.

12

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 will be placed in service by the end of 2016. The second segment of the project will 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 June 30,									Six Months Ended June 30,
	2016			2015			Variance			2016			2015			Variance
	(in thousands)
Revenue	$	62,019		$	68,038		$	(6,019	)	$	130,661		$	138,321		$	(7,660	)
Fuel and purchased power	16,224			19,353			(3,129		)	36,954			41,457			(4,503		)
Gross margin	45,795			48,685			(2,890		)	93,707			96,864			(3,157		)
Operating expenses	26,859			27,542			(683		)	53,991			54,231			(240		)
Operating income	18,936			21,143			(2,207		)	39,716			42,633			(2,917		)
Interest income (expense), net	(4,824		)	(5,575		)	751			(9,853		)	(11,124		)	1,271
Other income (expense), net	519			143			376			1,016			248			768
Income tax expense	(4,825		)	(5,164		)	339			(9,887		)	(10,807		)	920
Net income	$	9,806		$	10,547		$	(741	)	$	20,992		$	20,950		$	42

13

	Electric Revenue by Customer Type
	Three Months Ended June 30,					Six Months Ended June 30,
	(in thousands)
	2016		Percentage Change	2015		2016		Percentage Change	2015
Residential	$	16,241	5%	$	15,470	$	35,556	—%	$	35,610
Commercial	23,723		(3)%	24,433		47,312		(4)%	49,174
Industrial	7,764		(8)%	8,459		16,265		(3)%	16,758
Municipal	960		12%	859		1,791		4%	1,717
Total retail revenue	48,688		(1)%	49,221		100,924		(2)%	103,259
Contract wholesale	3,947		(1)%	3,979		8,121		(14)%	9,399
Wholesale off-system	2,734		(59)%	6,666		7,320		(45)%	13,301
Other revenue	6,650		(19)%	8,172		14,296		16%	12,362
Total revenue	$	62,019	(9)%	$	68,038	$	130,661	(6)%	$	138,321

	Megawatt Hours Sold by Customer Type
	Three Months Ended June 30,			Six Months Ended June 30,
	2016	Percentage Change	2015	2016	Percentage Change	2015
Residential	114,851	4%	110,017	257,604	—%	256,980
Commercial	190,207	—%	189,889	379,095	(2)%	384,967
Industrial	102,620	—%	102,494	210,641	(2)%	214,353
Municipal	8,487	21%	7,036	15,928	8%	14,736
Total retail quantity sold	416,165	2%	409,436	863,268	(1)%	871,036
Contract wholesale	56,087	(14)%	64,896	119,540	(20)%	149,167
Wholesale off-system	117,064	(52)%	246,213	310,437	(37)%	491,851
Total quantity sold	589,316	(18)%	720,545	1,293,245	(14)%	1,512,054
Losses and company use	30,528	(35)%	46,993	69,852	(5)%	73,639
Total energy	619,844	(19)%	767,538	1,363,097	(14)%	1,585,693

	Megawatt Hours Generated and Purchased
	Three Months Ended June 30,			Six Months Ended June 30,
Generated -	2016	Percentage Change	2015	2016	Percentage Change	2015
Coal-fired (a)	265,032	(34)%	399,763	653,033	(16)%	776,597
Gas-fired	39,433	134%	16,883	54,995	178%	19,761
Total generated	304,465	(27)%	416,646	708,028	(11)%	796,358
Total purchased	315,379	(10)%	350,892	655,069	(17)%	789,335
Total generated and purchased	619,844	(19)%	767,538	1,363,097	(14)%	1,585,693

____________________

(a) Decrease is due to a planned outage at Wygen III and an extended planned outage at Wyodak.

14

	Power Plant Availability
	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Coal-fired plants (a)	64.5	%	95.1	%	78.4	%	91.4	%
Other plants	99.2	%	96.9	%	98.7	%	96.0	%
Total availability	84.2	%	96.1	%	90.0	%	94.0	%

____________________

(a) Decrease is due to 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,
	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:
Heating degree days	877	(13	)%	1,005	—	%	3,683	(13	)%	3,878	(8	)%
Cooling degree days	186	74	%	96	(10	)%	186	74	%	96	(10	)%

Three Months Ended June 30, 2016 Compared to Three Months Ended June 30, 2015. Net income was $10 million compared to $11 million for the same period in the prior year primarily due to the following:

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

Operations and maintenancedecreased primarily due to lower employee costs due to integration activities and transition expenses charged to our Parent Company related to its acquisition of SourceGas, and lower costs driven by a change in operating expense and capital 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 is comparable to the prior year.

15

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

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

Operations and maintenancedecreased primarily due to lower employee costs due to integration activities and transition expenses charged to our Parent Company related to its acquisition of SourceGas and lower costs driven by a change in operating expense and capital allocations impacting us as a result of our Parent Company integrating the acquired SourceGas utilities. These decreases are partially offsetting by higher depreciation expense driven by additional plant in service and higher maintenance expenses driven by current 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 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 decreased due primarily to a favorable re-measurement of an uncertain tax position liability involving research and development credits and deductions, as a result of an agreement reached during the first quarter of 2016 with the IRS.

Credit Ratings

Credit ratings impact our ability to obtain short and long-term financing, the cost of such financing, and vendor payment terms, including collateral requirements. The following table represents our secured credit rating from each agency’s review which was in effect at June 30, 2016:

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 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 10Q.

16

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.

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) as of June 30, 2016. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective as of June 30, 2016.

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

Changes in Internal Control over Financial Reporting

During the quarter ended June 30, 2016, 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.

17

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 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.

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.

18

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: August 10, 2016

19

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* 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.

20

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, David R. Emery, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Black Hills Power, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; and

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; and

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting.

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	August 10, 2016
		/S/ DAVID R. EMERY
		David R. Emery
		Chairman and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Richard W. Kinzley, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Black Hills Power, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting.

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	August 10, 2016
		/S/ RICHARD W. KINZLEY
		Richard W. Kinzley
		Senior Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Black Hills Power, Inc. (the “Company”) on Form 10-Q for the period ended June 30, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David R. Emery, Chairman and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13 (a) or

15 (d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material

respects, the financial condition and results of operations of the Company.

Date:	August 10, 2016
		/S/ DAVID R. EMERY
		David R. Emery
		Chairman and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Black Hills Power, Inc. (the “Company”) on Form 10-Q for the period ended June 30, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Richard W. Kinzley, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13 (a) or

15 (d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material

respects, the financial condition and results of operations of the Company.

Date:	August 10, 2016
		/S/ RICHARD W. KINZLEY
		Richard W. Kinzley
		Senior Vice President and Chief Financial Officer

XML

Document and Entity Information Document - shares	6 Months Ended
	Jun. 30, 2016	Jul. 31, 2016
Document Information [Line Items]
Entity Registrant Name	BLACK HILLS POWER INC
Entity Central Index Key	0000012400
Document Type	10-Q
Document Period End Date	Jun. 30, 2016
Amendment Flag	false
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		23,416,396

XML

Condensed Statements of Income and Comprehensive Income - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Income Statement [Abstract]
Revenue	$ 62,019	$ 68,038	$ 130,661	$ 138,321
Operating expenses:
Fuel, purchased power and natural gas	16,224	19,353	36,954	41,457
Operations and maintenance	16,906	18,121	33,937	35,212
Depreciation and amortization	8,204	7,842	16,816	15,967
Taxes - property	1,749	1,579	3,238	3,052
Total operating expenses	43,083	46,895	90,945	95,688
Operating income	18,936	21,143	39,716	42,633
Other income (expense):
Interest expense	(5,414)	(5,680)	(10,868)	(11,372)
AFUDC - borrowed	298	44	521	83
Interest income	292	61	494	165
AFUDC - equity	566	80	989	150
Other income (expense), net	(47)	63	27	98
Total other income (expense)	(4,305)	(5,432)	(8,837)	(10,876)
Income from continuing operations before income taxes	14,631	15,711	30,879	31,757
Income tax expense	(4,825)	(5,164)	(9,887)	(10,807)
Net Income	9,806	10,547	20,992	20,950
Other comprehensive income (loss):
Reclassification adjustments of cash flow hedges settled and included in net income (net of tax (expense) benefit of $(5) and $(6) for the three months ended June 30, 2016 and 2015 and $(11) and $330 for the six months ended June 30, 2016 and 2015, respectively)	11	10	21	362
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(7) and $(8) for the three months ended June 30, 2016 and 2015 and $(14) and $(16) for the six months ended June 30, 2016 and 2015, respectively)	13	16	27	31
Other comprehensive income	24	26	48	393
Comprehensive income	$ 9,830	$ 10,573	$ 21,040	$ 21,343

XML

Condensed Statements of Income and Comprehensive Income OCI Parenthetical - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Income Statement [Abstract]
Reclassification adjustment of cash flow hedges settled, (tax) benefit	$ (5)	$ (6)	$ (11)	$ 330
Reclassification adjustment of benefit and other postretirement plans included in net income, (tax) benefit	$ (7)	$ (8)	$ (14)	$ (16)

XML

Condensed Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 19,625	$ 7,559
Receivables - customers, net	27,283	27,856
Receivables - affiliates	5,492	5,747
Other receivables, net	169	236
Money pool notes receivable, net	56,599	76,813
Materials, supplies and fuel	22,017	24,282
Regulatory assets, current	21,297	14,096
Other, current assets	3,846	43,118
Total current assets	156,328	199,707
Investments	4,800	4,725
Property, plant and equipment	1,191,724	1,166,126
Less accumulated depreciation and amortization	(333,053)	(326,074)
Total property, plant and equipment, net	858,671	840,052
Other assets:
Regulatory assets, non-current	68,854	71,717
Other, non-current assets	3,835	152
Total other assets	72,689	71,869
TOTAL ASSETS	1,092,488	1,116,353
Current liabilities:
Accounts payable	30,098	21,297
Accounts payable - affiliates	25,719	30,032
Accrued liabilities	25,832	69,454
Regulatory liabilities, current	34	0
Total current liabilities	81,683	120,783
Long-term debt	339,686	339,616
Deferred credits and other liabilities:
Deferred income tax liability, net, non-current	207,886	188,961
Regulatory liabilities, non-current	52,672	51,583
Benefit plan liabilities	19,857	20,033
Other, non-current liabilities	2,185	3,398
Total deferred credits and other liabilities	282,600	263,975
Commitments and contingencies (Notes 4, 5 and 8)
Stockholder’s equity:
Common stock $1 par value; 50,000,000 shares authorized; 23,416,396 shares issued	23,416	23,416
Additional paid-in capital	39,575	39,575
Retained earnings	326,787	330,295
Accumulated other comprehensive loss	(1,259)	(1,307)
Total stockholder’s equity	388,519	391,979
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$ 1,092,488	$ 1,116,353

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Balance Sheet Parentheticals - $ / shares	Jun. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Common Stock, Par Value (usd per share)	$ 1	$ 1
Common Stock, Shares Authorized	50,000,000	50,000,000
Common Stock, Shares Issued	23,416,396	23,416,396

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Condensed Statements of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Operating activities:
Net income	$ 20,992	$ 20,950
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization	16,816	15,967
Deferred income tax	18,009	10,080
Employee benefits	886	1,202
AFUDC - equity	(989)	(150)
Other adjustments, net	(236)	291
Change in operating assets and liabilities -
Accounts receivable and other current assets	3,234	6,094
Accounts payable and other current liabilities	538	(11,358)
Regulatory assets - current	(7,026)	(3,033)
Regulatory liabilities - current	0	(2,479)
Pension Contributions	(820)	0
Other operating activities, net	168	(2,409)
Net cash provided by (used in) operating activities	51,572	35,155
Investing activities:
Property, plant and equipment additions	(35,153)	(17,009)
Change in money pool notes receivable, net	(4,286)	55,145
Other investing activities	(67)	(90)
Net cash provided by (used in) investing activities	(39,506)	38,046
Financing activities:
Net cash provided by (used in) financing activities	0	0
Net change in cash and cash equivalents	12,066	73,201
Cash and Cash Equivalents:
Cash and cash equivalents, beginning of period	7,559	6,620
Cash and cash equivalents, end of period	$ 19,625	$ 79,821

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Management's Statement:

6 Months Ended

Jun. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Management's Statement

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 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 all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the June 30, 2016, December 31, 2015 and June 30, 2015 financial information and are of a normal recurring nature. The results of operations for the three and six months ended June 30, 2016 and June 30, 2015, and our financial condition as of June 30, 2016 and December 31, 2015 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

Recently Issued and Adopted Accounting Standards

Leases, ASU 2016-02

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a 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 June 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 revenue when the risks and rewards transfer to the customer under the existing revenue guidance. On July 9, 2015, FASB voted to defer the effective date of ASU 2014-09 by one year. The proposed guidance would be effective for annual and interim reporting periods beginning after December 15, 2017 and early adoption is permitted. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption. We are currently evaluating the impact of adoption, if any, that ASU 2014-09 will have on our financial position, results of operations or cash flows.

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Accounts Receivable and Allowance For Doubtful Accounts:

6 Months Ended

Jun. 30, 2016

Accounts Receivable, Net [Abstract]

Accounts Receivable and Allowance for Doubtful Accounts

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:

	June 30, 2016			December 31, 2015
Accounts receivable trade	$	15,519		$	15,268
Unbilled revenues	11,989			12,795
Allowance for doubtful accounts	(225		)	(207		)
Receivables - customers, net	$	27,283		$	27,856

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Regulatory Accounting:

6 Months Ended

Jun. 30, 2016

Regulated Operations [Abstract]

Regulatory Accounting

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)	June 30, 2016		December 31, 2015
Regulatory assets:
Unamortized loss on reacquired debt (a)	8	$	1,955	$	2,096
AFUDC (b)	45	8,945		8,571
Employee benefit plans (c)	12	20,866		20,866
Deferred energy and fuel cost adjustments - current (a)	Less than 1 year	21,800		19,875
Flow through accounting (a)	35	12,617		12,104
Decommissioning costs, net of amortization(b)	9	13,255		13,686
Other regulatory assets (a)(d)	2	10,713		8,615
Total regulatory assets		$	90,151	$	85,813

Regulatory liabilities:
Cost of removal for utility plant (a)	53	$	40,056	$	38,131
Employee benefit plans (c)	12	12,616		12,616
Other regulatory liabilities	13	34		836
Total regulatory liabilities		$	52,706	$	51,583

____________________

(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 $7.0 million and $5.0 million of vegetation management expenses at June 30, 2016 and December 31, 2015, respectively, for which we are allowed a rate of return.

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Related Party Transactions:

6 Months Ended

Jun. 30, 2016

Related Party Transactions [Abstract]

Related Party Transactions

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:

	June 30, 2016		December 31, 2015
Receivables - affiliates	$	5,492	$	5,747
Accounts payable - affiliates	$	25,719	$	30,032

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 borrowings as defined under the Agreement, or if there are no external funds outstanding on that date, then the rate will be the daily one-month LIBOR plus 1.0%. At June 30, 2016, the average cost of borrowing under the Utility Money Pool was 1.75%.

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

	June 30, 2016		December 31, 2015
Money pool notes receivable, net	$	56,599	$	76,813

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Net interest income (expense)	$	290	$	288	$	568	$	546

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Revenue:
Energy sold to Cheyenne Light	$	648	$	379	$	1,309	$	705
Rent from electric properties	$	1,375	$	1,332	$	2,588	$	2,456
Fuel and purchased power:
Purchases of coal from WRDC	$	3,357	$	4,099	$	8,153	$	8,144
Purchase of excess energy from Cheyenne Light	$	53	$	213	$	108	$	689
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	353	$	280	$	1,017	$	829
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	602	$	498	$	1,729	$	1,434
Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	100	$	103	$	200	$	207
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	6,177	$	6,627	$	12,898	$	13,660

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Employee Benefit Plans:

6 Months Ended

Jun. 30, 2016

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

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 June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Service cost	$	151		$	199		$	302		$	398
Interest cost	625			739			1,250			1,478
Expected return on plan assets	(908		)	(984		)	(1,816		)	(1,968		)
Prior service cost	11			11			22			22
Net loss (gain)	499			549			998			1,098
Net periodic benefit cost	$	378		$	514		$	756		$	1,028

Defined Benefit Postretirement Healthcare Plan

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Service cost	$	51		$	59		$	102		$	117
Interest cost	47			53			94			107
Prior service cost (benefit)	(84		)	(84		)	(168		)	(168		)
Net periodic benefit cost	$	14		$	28		$	28		$	56

Supplemental Non-qualified Defined Benefit Plans

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Interest cost	$	30	$	36	$	60	$	72
Net loss (gain)	21		23		42		46
Net periodic benefit cost	$	51	$	59	$	102	$	118

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. Contributions to the Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions and anticipated contributions are as follows (in thousands):

	Contributions Six Months Ended June 30, 2016		Remaining Anticipated Contributions for 2016		Anticipated Contributions for 2017
Defined Benefit Pension Plan	$	820	$	—	$	1,615
Defined Benefit Postretirement Healthcare Plan	$	309	$	309	$	509
Supplemental Non-qualified Defined Benefit Plans	$	108	$	108	$	248

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Fair Value of Financial Instruments:

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

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 Annual Report on Form 10-K filed with the SEC.

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

	June 30, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	19,625	$	19,625	$	7,559	$	7,559
Long-term debt, including current maturities (b)	$	339,686	$	445,571	$	339,616	$	404,864

_________________

(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.

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Supplemental Disclosure of Cash Flow Information:

6 Months Ended

Jun. 30, 2016

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosure of Cash Flow Information

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Six months ended June 30,	2016			2015
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	5,355		$	2,225
Non-cash (decrease) to money pool notes receivable, net	$	(24,500	)	$	(6,500	)
Non-cash dividend to Parent	$	24,500		$	6,500
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(10,547	)	$	(11,063	)

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Commitment and Contingencies:

6 Months Ended

Jun. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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 Annual Report on Form 10-K.

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Accounts Receivable and Allowance For Doubtful Accounts: Accounts Receivable and Allowance For Doubtful Accounts (Tables)

6 Months Ended

Jun. 30, 2016

Accounts Receivable, Net [Abstract]

Schedule of Accounts Receivable

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

	June 30, 2016			December 31, 2015
Accounts receivable trade	$	15,519		$	15,268
Unbilled revenues	11,989			12,795
Allowance for doubtful accounts	(225		)	(207		)
Receivables - customers, net	$	27,283		$	27,856

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Regulatory Accounting: Regulatory Accounting (Tables)

6 Months Ended

Jun. 30, 2016

Regulated Operations [Abstract]

Schedule of Regulatory Assets

Our regulatory assets and liabilities were as follows (in thousands) as of:

	Recovery/Amortization Period (in years)	June 30, 2016		December 31, 2015
Regulatory assets:
Unamortized loss on reacquired debt (a)	8	$	1,955	$	2,096
AFUDC (b)	45	8,945		8,571
Employee benefit plans (c)	12	20,866		20,866
Deferred energy and fuel cost adjustments - current (a)	Less than 1 year	21,800		19,875
Flow through accounting (a)	35	12,617		12,104
Decommissioning costs, net of amortization(b)	9	13,255		13,686
Other regulatory assets (a)(d)	2	10,713		8,615
Total regulatory assets		$	90,151	$	85,813

Schedule of Regulatory Liabilities

Regulatory liabilities:
Cost of removal for utility plant (a)	53	$	40,056	$	38,131
Employee benefit plans (c)	12	12,616		12,616
Other regulatory liabilities	13	34		836
Total regulatory liabilities		$	52,706	$	51,583

____________________

(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 $7.0 million and $5.0 million of vegetation management expenses at June 30, 2016 and December 31, 2015, respectively, for which we are allowed a rate of return.

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Related Party Transactions: Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2016

Related Party Transactions [Abstract]

Schedule of Related Party Accounts Receivable and Payable

The balances were as follows (in thousands) as of:

	June 30, 2016		December 31, 2015
Receivables - affiliates	$	5,492	$	5,747
Accounts payable - affiliates	$	25,719	$	30,032

Schedule of Related Party Notes

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

	June 30, 2016		December 31, 2015
Money pool notes receivable, net	$	56,599	$	76,813

Schedule of Related Party Interest Income Expense

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Net interest income (expense)	$	290	$	288	$	568	$	546

Schedule of Revenues and Purchases from Related Parties

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Revenue:
Energy sold to Cheyenne Light	$	648	$	379	$	1,309	$	705
Rent from electric properties	$	1,375	$	1,332	$	2,588	$	2,456
Fuel and purchased power:
Purchases of coal from WRDC	$	3,357	$	4,099	$	8,153	$	8,144
Purchase of excess energy from Cheyenne Light	$	53	$	213	$	108	$	689
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	353	$	280	$	1,017	$	829
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	602	$	498	$	1,729	$	1,434
Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	100	$	103	$	200	$	207
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	6,177	$	6,627	$	12,898	$	13,660

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Employee Benefit Plans: Employee Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2016

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Schedule of Net Benefit Costs

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Service cost	$	151		$	199		$	302		$	398
Interest cost	625			739			1,250			1,478
Expected return on plan assets	(908		)	(984		)	(1,816		)	(1,968		)
Prior service cost	11			11			22			22
Net loss (gain)	499			549			998			1,098
Net periodic benefit cost	$	378		$	514		$	756		$	1,028

Defined Benefit Postretirement Healthcare Plan

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Service cost	$	51		$	59		$	102		$	117
Interest cost	47			53			94			107
Prior service cost (benefit)	(84		)	(84		)	(168		)	(168		)
Net periodic benefit cost	$	14		$	28		$	28		$	56

Supplemental Non-qualified Defined Benefit Plans

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Interest cost	$	30	$	36	$	60	$	72
Net loss (gain)	21		23		42		46
Net periodic benefit cost	$	51	$	59	$	102	$	118

Schedule of Defined Benefit Plans Contributions

Contributions and anticipated contributions are as follows (in thousands):

	Contributions Six Months Ended June 30, 2016		Remaining Anticipated Contributions for 2016		Anticipated Contributions for 2017
Defined Benefit Pension Plan	$	820	$	—	$	1,615
Defined Benefit Postretirement Healthcare Plan	$	309	$	309	$	509
Supplemental Non-qualified Defined Benefit Plans	$	108	$	108	$	248

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Fair Value of Financial Instruments: Fair Value of Financial Instruments(Tables)

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

Schedule of Fair Value of Financial Instruments

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

	June 30, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	19,625	$	19,625	$	7,559	$	7,559
Long-term debt, including current maturities (b)	$	339,686	$	445,571	$	339,616	$	404,864

_________________

(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.

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Supplemental Disclosure of Cash Flow Information: Supplemental Disclosures of Cash Flow Information (Tables)

6 Months Ended

Jun. 30, 2016

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

Six months ended June 30,	2016			2015
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	5,355		$	2,225
Non-cash (decrease) to money pool notes receivable, net	$	(24,500	)	$	(6,500	)
Non-cash dividend to Parent	$	24,500		$	6,500
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(10,547	)	$	(11,063	)

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Management's Statement: Simplifying the Presentation of Debt Issuance Costs (Details) $ in Millions	Dec. 31, 2015 USD ($)
Other Noncurrent Liabilities [Member]
New Accounting Pronouncement - Deferred Financing Costs	$ 3.1

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Accounts Receivable and Allowance For Doubtful Accounts: Accounts Receivable and Allowance For Doubtful Accounts (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Accounts Receivable [Line Items]
Allowance for doubtful accounts	$ (225)	$ (207)
Receivables - customers, net	27,283	27,856
Billed Revenues [Member]
Accounts Receivable [Line Items]
Accounts receivable, trade	15,519	15,268
Unbilled Revenues [Member]
Accounts Receivable [Line Items]
Accounts receivable, trade	$ 11,989	$ 12,795

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Regulatory Accounting: Regulatory Accounting (Details) - USD ($) $ in Thousands		6 Months Ended
		Jun. 30, 2016	Dec. 31, 2015
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets		$ 90,151	$ 85,813
Regulatory Liabilities		$ 52,706	51,583
Cost of removal for utility plant [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities Amortization Period		53 years
Regulatory Liabilities	[1]	$ 40,056	38,131
Employee benefit plans [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities Amortization Period		12 years
Regulatory Liabilities	[2]	$ 12,616	12,616
Other regulatory liabilities [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities Amortization Period		13 years
Regulatory Liabilities		$ 34	836
Unamortized Loss on reacquired debt [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets Amortization Period		8 years
Regulatory Assets	[1]	$ 1,955	2,096
Allowance For Funds Used During Construction [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets Amortization Period		45 years
Regulatory Assets	[3]	$ 8,945	8,571
Employee benefit plans [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets Amortization Period		12 years
Regulatory Assets	[2]	$ 20,866	20,866
Deferred energy and fuel cost adjustments - current [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	[1]	$ 21,800	19,875
Flow through accounting [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets Amortization Period		35 years
Regulatory Assets	[1]	$ 12,617	12,104
Decommissioning costs, net of amortization [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets Amortization Period		9 years
Regulatory Assets		$ 13,255	13,686
Other regulatory assets [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets Amortization Period		2 years
Regulatory Assets	[1],[4]	$ 10,713	8,615
Vegetation Management [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets		$ 7,000	$ 5,000

[1] Recovery of costs, but we are not allowed a rate of return.

[2] 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.

[3] In addition to recovery of costs, we are allowed a rate of return.

[4] Includes approximately $7.0 million and $5.0 million of vegetation management expenses at June 30, 2016 and December 31, 2015, respectively, for which we are allowed a rate of return.

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Related Party Transactions: Related Party Transactions (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
Receivables - affiliates	$ 5,492		$ 5,492		$ 5,747
Accounts payable - affiliates	25,719		$ 25,719		30,032
Related Party Transaction, Utility Money Pool Interest Rate			1.75%
Money pool notes receivable, net	56,599		$ 56,599		$ 76,813
Parent [Member]
Related Party Transaction [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage			1.00%
Utility Money Pool [Member]
Related Party Transaction [Line Items]
Net interest income (expense)	290	$ 288	$ 568	$ 546
Subsidiary of Common Parent [Member] | Allocated Costs From Related Parties [Member]
Related Party Transaction [Line Items]
Costs and expenses, related parties	6,177	6,627	12,898	13,660
Subsidiary of Common Parent [Member] | Purchase Of Natural Gas, Cheyenne Light [Member]
Related Party Transaction [Line Items]
Costs and expenses, related parties	100	103	200	207
Subsidiary of Common Parent [Member] | Coal, Purchased [Member]
Related Party Transaction [Line Items]
Costs and expenses, related parties	3,357	4,099	8,153	8,144
Subsidiary of Common Parent [Member] | Purchase of Excess Energy, Cheyenne Light [Member]
Related Party Transaction [Line Items]
Costs and expenses, related parties	53	213	108	689
Subsidiary of Common Parent [Member] | Happy Jack Wind Purchase Power Agreeement [Member]
Related Party Transaction [Line Items]
Costs and expenses, related parties	353	280	1,017	829
Subsidiary of Common Parent [Member] | Silver Sage Wind Power Purchase Agreement [Member]
Related Party Transaction [Line Items]
Costs and expenses, related parties	602	498	1,729	1,434
Subsidiary of Common Parent [Member] | Energy sold to Cheyenne Light [Member]
Related Party Transaction [Line Items]
Revenue from related parties	648	379	1,309	705
Subsidiary of Common Parent [Member] | Lease Agreements [Member]
Related Party Transaction [Line Items]
Revenue from related parties	$ 1,375	$ 1,332	$ 2,588	$ 2,456

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Employee Benefit Plans: Employee Benefit Plans (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Defined Benefit Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Decrease In Interest and Service Costs Resulting From New Spot Method Approach			$ 500
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	$ 151	$ 199	302	$ 398
Interest cost	625	739	1,250	1,478
Expected return on plan assets	(908)	(984)	(1,816)	(1,968)
Prior service cost (benefit)	11	11	22	22
Net loss (gain)	499	549	998	1,098
Net periodic benefit cost	378	514	756	1,028
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions made by Employer			820
Remaining Anticipated Contributions for Current Year			0
Anticipated Contributions for Next Year			1,615
Defined Benefit Postretirement Healthcare Plan
Defined Benefit Plan Disclosure [Line Items]
Decrease In Interest and Service Costs Resulting From New Spot Method Approach			100
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	51	59	102	117
Interest cost	47	53	94	107
Prior service cost (benefit)	(84)	(84)	(168)	(168)
Net periodic benefit cost	14	28	28	56
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions made by Employer			309
Remaining Anticipated Contributions for Current Year			309
Anticipated Contributions for Next Year			509
Supplemental Non-qualified Defined Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Decrease In Interest and Service Costs Resulting From New Spot Method Approach			300
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Interest cost	30	36	60	72
Net loss (gain)	21	23	42	46
Net periodic benefit cost	$ 51	$ 59	102	$ 118
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions made by Employer			108
Remaining Anticipated Contributions for Current Year			108
Anticipated Contributions for Next Year			$ 248
Scenario, Previously Reported [Member] | Defined Benefit Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.63%		4.63%
Scenario, Previously Reported [Member] | Defined Benefit Postretirement Healthcare Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.03%		4.03%
Scenario, Previously Reported [Member] | Supplemental Non-qualified Defined Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.50%		4.50%
Service Cost [Member] | Defined Benefit Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.81%		4.81%
Service Cost [Member] | Defined Benefit Postretirement Healthcare Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.18%		4.18%
Service Cost [Member] | Supplemental Non-qualified Defined Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.88%		4.88%
Interest Cost [Member] | Defined Benefit Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.90%		3.90%
Interest Cost [Member] | Defined Benefit Postretirement Healthcare Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.17%		3.17%
Interest Cost [Member] | Supplemental Non-qualified Defined Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.82%		3.82%

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Fair Value of Financial Instruments: Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands		Jun. 30, 2016	Dec. 31, 2015	Jun. 30, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, carrying amount		$ 19,625	$ 7,559	$ 79,821	$ 6,620
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, carrying amount	[1]	19,625	7,559
Long-term debt, including current maturities, carrying amount	[2]	339,686	339,616
Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, fair value	[1]	19,625	7,559
Long-term debt, including current maturities, fair value	[2]	$ 445,571	$ 404,864

[1] 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.

[2] 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.

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Supplemental Disclosure of Cash Flow Information: Supplemental Disclosures of Cash Flow Information (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Noncash Investing and Financing Items [Abstract]
Property, plant and equipment acquired with accrued liabilities	$ 5,355	$ 2,225
Interest and Income Taxes Paid Net [Abstract]
Interest paid, (net of amounts capitalized)	(10,547)	(11,063)
Subsidiary of Common Parent [Member]
Noncash Investing and Financing Items [Abstract]
Non-cash (decrease) to money pool notes receivable, net	(24,500)	(6,500)
Parent [Member]
Noncash Investing and Financing Items [Abstract]
Non-cash dividend to Parent	$ 24,500	$ 6,500