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, ~~2015~~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, ~~2015,~~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, ~~2015~~2016 and ~~2014~~2015

	Condensed Balance Sheets - unaudited	5
	June 30, ~~2015~~2016 and December 31, ~~2014~~2015

	Condensed Statements of Cash Flows - unaudited	7
	Six Months Ended June 30, ~~2015~~2016 and ~~2014~~2015

	Notes to Condensed Financial Statements - unaudited	8

Item 2.	Managements’ Discussion and Analysis of Financial Condition and Results of Operations	1413

Item 4.	Controls and Procedures	1917

PART II.	OTHER INFORMATION	2018

Item 1.	Legal Proceedings	2018

Item 1A.	Risk Factors	2018

Item 6.	Exhibits	2018

	Signatures	2119

	Exhibit Index	2220

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 ~~Black Hills Utility Holdings, Inc., and its subsidiaries~~BHC utility companies
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc. a direct, wholly-owned subsidiary of ~~BHC~~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 ~~BHC~~
~~Cheyenne Prairie~~	~~Cheyenne Prairie Generating Station is a 132 MW natural gas-fired generating facility in Cheyenne, Wyoming, jointly owned by Cheyenne Light and~~ Black Hills ~~Power. Cheyenne Prairie was placed into commercial operations on October 1, 2014.~~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.
~~CPCN~~	~~Certificate of Public Convenience and Necessity~~
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Generally Accepted Accounting Principles in the United States of America
~~Global Settlement~~	~~Settlement with a utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders.~~
Happy Jack	Happy Jack Wind Farms, LLC, a subsidiary of Duke Energy Generation Services
Heating degree day	A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.
kV	Kilovolt
LIBOR	London Interbank Offered Rate
Moody’s	Moody’s Investor Services, Inc.
MW	Megawatts
MWh	Megawatt-hours
~~SDPUC~~	~~South Dakota Public Utilities Commission~~
SEC	U.S. Securities and Exchange Commission
Silver Sage	Silver Sage Windpower, LLC, a subsidiary of Duke Energy Generation Services
S&P	Standard & Poor’s Rating Services
~~WPSC~~	~~Wyoming Public Service Commission~~
WRDC	Wyodak Resources Development Corp., an indirect, wholly-owned subsidiary of BHC

BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
(unaudited)	2015			2014			2015			2014			2016			2015			2016			2015
	(in thousands)												(in thousands)
Revenue	$	68,038		$	60,741		$	138,321		$	132,007		$	62,019		$	68,038		$	130,661		$	138,321

Operating expenses:
Fuel, purchased power and natural gas	19,353			21,278			41,457			48,323
Fuel and purchased power													16,224			19,353			36,954			41,457
Operations and maintenance	18,121			17,338			35,212			35,448			16,906			18,121			33,937			35,212
Depreciation and amortization	7,842			6,972			15,967			13,859			8,204			7,842			16,816			15,967
Taxes - property	1,579			1,371			3,052			3,050			1,749			1,579			3,238			3,052
Total operating expenses	46,895			46,959			95,688			100,680			43,083			46,895			90,945			95,688

Operating income	21,143			13,782			42,633			31,327			18,936			21,143			39,716			42,633

Other income (expense):
Interest expense	(5,680		)	(4,984		)	(11,372		)	(9,931		)	(5,414		)	(5,680		)	(10,868		)	(11,372		)
AFUDC - borrowed	44			57			83			129			298			44			521			83
Interest income	61			211			165			269			292			61			494			165
AFUDC - equity	80			117			150			262			566			80			989			150
Other income (expense), net	63			51			98			95			(47		)	63			27			98
Total other income (expense)	(5,432		)	(4,548		)	(10,876		)	(9,176		)	(4,305		)	(5,432		)	(8,837		)	(10,876		)

Income from continuing operations before income taxes	15,711			9,234			31,757			22,151			14,631			15,711			30,879			31,757
Income tax expense	(5,164		)	(3,004		)	(10,807		)	(7,278		)	(4,825		)	(5,164		)	(9,887		)	(10,807		)
Net income	10,547			6,230			20,950			14,873			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 $(6) and $(5) for the three months ended June 30, 2015 and 2014 and $330 and $(11) for the six months ended June 30, 2015 and 2014, respectively)	10			11			362			21
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(8) and $(4) for the three months ended June 30, 2015 and 2014 and $(16) and $(8) for the six months ended June 30, 2015 and 2014, respectively)	16			7			31			14
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	26			18			393			35			24			26			48			393

Comprehensive income	$	10,573		$	6,248		$	21,343		$	14,908		$	9,830		$	10,573		$	21,040		$	21,343

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

BLACK HILLS POWER, INC.

CONDENSED BALANCE SHEETS

(unaudited) June 30, 2015 December 31, 2014
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 79,821
$ 6,620
Receivables - customers, net 27,028
34,684
Receivables - affiliates 7,502
5,350
Other receivables, net 265
259
Money pool notes receivable, net 6,981
68,626
Materials, supplies and fuel 22,720
20,965
Deferred income tax assets, net, current 2,679
13,661
Regulatory assets, current 13,465
10,257
Other, current assets 32,108
4,954
Total current assets 192,569
165,376

Investments 4,681
4,584

Property, plant and equipment 1,119,407
1,115,061
Less accumulated depreciation and amortization (315,873 ) (309,767 )
Total property, plant and equipment, net 803,534
805,294

Other assets:
Regulatory assets, non-current 69,132
68,427
Other, non-current assets 15,033
11,708
Total other assets 84,165
80,135
TOTAL ASSETS $ 1,084,949
$ 1,055,389

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

~~BLACK HILLS POWER, INC.~~

~~CONDENSED BALANCE SHEETS~~

(unaudited) June 30, 2015 December 31, 2014
(in thousands, except common stock par value and share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable $ 17,644
$ 30,543
Accounts payable - affiliates 21,801
19,242
Accrued liabilities 42,100
16,415
Regulatory liabilities, current 431
3,073
Total current liabilities 81,976
69,273

Long-term debt, net of current maturities 342,754
342,752

Deferred credits and other liabilities:
Deferred income tax liability, net, non-current 192,749
193,042
Regulatory liabilities, non-current 52,219
51,916
Benefit plan liabilities 21,880
20,981
Other, non-current liabilities 3,734
2,631
Total deferred credits and other liabilities 270,582
268,570

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 328,072
313,622
Accumulated other comprehensive loss (1,426 ) (1,819 )
Total stockholders’ equity 389,637
374,794
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY $ 1,084,949
$ 1,055,389



(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.

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.

BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF CASH FLOWS


(unaudited)	Six Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2016			2015
	(in thousands)						(in thousands)
Operating activities:
Net income	$	20,950		$	14,873		$	20,992		$	20,950
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization	15,967			13,859			16,816			15,967
Deferred income tax	10,080			7,237			18,009			10,080
Employee benefits	1,202			647			886			1,202
AFUDC - equity	(150		)	(262		)	(989		)	(150		)
Other adjustments, net	291			(1,720		)	(236		)	291
Change in operating assets and liabilities -
Accounts receivable and other current assets	582			(8,743		)	3,234			6,094
Accounts payable and other current liabilities	(11,358		)	7,802			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	(2,409		)	(2,002		)	168			(2,409		)
Net cash provided by (used in) operating activities	35,155			31,691			51,572			35,155

Investing activities:
Property, plant and equipment additions	(17,009		)	(43,478		)	(35,153		)	(17,009		)
Change in money pool notes receivable, net	55,145			14,052			(4,286		)	55,145
Other investing activities	(90		)	(105		)	(67		)	(90		)
Net cash provided by (used in) investing activities	38,046			(29,531		)	(39,506		)	38,046

Financing activities:
Other financing activities	—			(133		)
Net cash provided by (used in) financing activities	—			(133		)	—			—

Net change in cash and cash equivalents	73,201			2,027			12,066			73,201

Cash and cash equivalents, beginning of period	6,620			2,259			7,559			6,620
Cash and cash equivalents, end of period	$	79,821		$	4,286		$	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.

BLACK HILLS POWER, INC.

Notes to Condensed Financial Statements

(unaudited)

(Reference is made to Notes to Financial Statements

included in our ~~2014~~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 ~~2014~~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, ~~2015~~2016, December 31, ~~2014~~2015 and June 30, ~~2014~~2015 financial information and are of a normal recurring nature. The results of operations for the three ~~months~~ and six months ended June 30, ~~2015~~2016 and June 30, ~~2014~~2015, and our financial condition as of June 30, ~~2015~~2016 and December 31, ~~2014~~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

~~We have implemented~~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 ~~new~~leases with terms of more than 12 months. Lessees are permitted to make an accounting ~~pronouncements that are in effect~~policy election to not recognize the asset and ~~may impact our financial statements.~~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 ~~any other new accounting pronouncements~~ that ~~have been issued may~~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.~~Costs. Debt issuance costs related to a recognized debt liability ~~will be~~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. ~~Early adoption is permitted.~~ We ~~are currently evaluating the impact of adoption that~~adopted ASU 2015-03 ~~will~~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, results of operations, or cash flows.~~position.

Revenue from Contracts with Customers, ASU 2014-09

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with ~~Customers.~~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, ~~2018~~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, 2015			December 31, 2014			June 30, 2016			December 31, 2015
Accounts receivable trade	$	16,089		$	24,946		$	15,519		$	15,268
Unbilled revenues	11,137			9,999			11,989			12,795
Allowance for doubtful accounts	(198		)	(261		)	(225		)	(207		)
Receivables - customers, net	$	27,028		$	34,684		$	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, 2015		December 31, 2014		Recovery/Amortization Period (in years)	June 30, 2016		December 31, 2015
Regulatory assets:
Unamortized loss on reacquired debt ^(a)	10	$	2,236	$	2,377	8	$	1,955	$	2,096
AFUDC ^(b)	45	8,308		8,365		45	8,945		8,571
Employee benefit plans ^(c)	12	24,418		24,418		12	20,866		20,866
Deferred energy and fuel cost adjustments - current^(a)	Less than 1 year	16,446		14,696		Less than 1 year	21,800		19,875
Flow through accounting ^(a)	35	11,956		11,171		35	12,617		12,104
Decommissioning costs, net of amortization^(d)(b)	10	12,175		11,786		9	13,255		13,686
Other	10	7,058		5,871
Other regulatory assets ^(a) ^(d)						2	10,713		8,615
Total regulatory assets		$	82,597	$	78,684		$	90,151	$	85,813


Regulatory liabilities:
Cost of removal for utility plant ^(a)	53	$	36,523	$	35,510	53	$	40,056	$	38,131
Employee benefit plans ^(c)	12	14,539		14,538		12	12,616		12,616
Other	13	1,588		4,941
Other regulatory liabilities						13	34		836
Total regulatory liabilities		$	52,650	$	54,989		$	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)	~~Approximately $12~~Includes approximately $7.0 million and $5.0 million of ~~decommissioning costs~~vegetation management expenses at June 30, 2016 and December 31, 2015, respectively, for which we are allowed a rate of ~~return, in addition to recovery of costs.~~return.


(4)	RELATED-PARTY TRANSACTIONS

Receivables and Payables

We have accounts receivable and accounts payable balances related to transactions with other BHC subsidiaries. The balances were as follows (in thousands) as of:


	June 30, 2015		December 31, 2014		June 30, 2016		December 31, 2015
Receivables - affiliates	$	7,502	$	5,350	$	5,492	$	5,747
Accounts payable - affiliates	$	21,801	$	19,242	$	25,719	$	30,032

Money Pool Notes Receivable and Notes Payable

We have entered into a Utility Money Pool Agreement (the “Agreement”) with BHC, ~~Cheyenne Light~~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, ~~2015~~2016, the average cost of borrowing under the Utility Money Pool was ~~1.41%~~1.75%.

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

June 30, 2015 December 31, 2014
Money pool notes receivable, net $ 6,981
$ 68,626



	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,
2015 2014 2015 2014
Net interest income (expense) $ 288
$ 27
$ 546
$ 84



	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,				Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014		2016		2015		2016		2015
Revenue:
Energy sold to Cheyenne Light	$	379	$	397	$	705	$	1,076	$	648	$	379	$	1,309	$	705
Rent from electric properties	$	1,332	$	1,051	$	2,456	$	2,074	$	1,375	$	1,332	$	2,588	$	2,456

Fuel and purchased power:
Purchases of coal from WRDC	$	4,099	$	4,018	$	8,144	$	9,032	$	3,357	$	4,099	$	8,153	$	8,144
Purchase of excess energy from Cheyenne Light	$	213	$	584	$	689	$	1,213	$	53	$	213	$	108	$	689
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	280	$	465	$	829	$	1,129	$	353	$	280	$	1,017	$	829
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	498	$	750	$	1,434	$	1,844	$	602	$	498	$	1,729	$	1,434

Gas transportation service agreement
Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	103	$	—	$	207	$	—	$	100	$	103	$	200	$	207

Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	6,627	$	6,703	$	13,660	$	14,190	$	6,177	$	6,627	$	12,898	$	13,660


(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,						Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014			2016			2015			2016			2015
Service cost	$	199		$	176		$	398		$	352		$	151		$	199		$	302		$	398
Interest cost	739			748			1,478			1,496			625			739			1,250			1,478
Expected return on plan assets	(984		)	(925		)	(1,968		)	(1,851		)	(908		)	(984		)	(1,816		)	(1,968		)
Prior service cost	11			10			22			21			11			11			22			22
Net loss (gain)	549			235			1,098			470			499			549			998			1,098
Net periodic benefit cost	$	514		$	244		$	1,028		$	488		$	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,						Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014			2016			2015			2016			2015
Service cost	$	59		$	56		$	117		$	112		$	51		$	59		$	102		$	117
Interest cost	53			60			107			120			47			53			94			107
Prior service cost (benefit)	(84		)	(84		)	(168		)	(168		)	(84		)	(84		)	(168		)	(168		)
Net loss (gain)	—			—			—			—
Net periodic benefit cost	$	28		$	32		$	56		$	64		$	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,				Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014		2016		2015		2016		2015
Interest cost	$	36	$	36	$	72	$	73	$	30	$	36	$	60	$	72
Net loss (gain)	23		11		46		22		21		23		42		46
Net periodic benefit cost	$	59	$	47	$	118	$	95	$	51	$	59	$	102	$	118

Contributions

We anticipate we will make contributions to the benefit plans during ~~2015~~2016 and ~~2016~~.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, 2015		Remaining Anticipated Contributions for 2015		Anticipated Contributions for 2016		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	$	260	$	260	$	577	$	309	$	309	$	509
Supplemental Non-qualified Defined Benefit Plans	$	109	$	109	$	184	$	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 ~~2014~~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, 2015				December 31, 2014				June 30, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents ^(a)	$	79,821	$	79,821	$	6,620	$	6,620	$	19,625	$	19,625	$	7,559	$	7,559
Long-term debt, including current maturities^(b)	$	342,754	$	401,081	$	342,752	$	430,497	$	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,	2015			2014			2016			2015
	(in thousands)						(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	2,225		$	9,824		$	5,355		$	2,225
Non-cash (decrease) to money pool notes receivable, net	$	(6,500	)	$	—		$	(24,500	)	$	(6,500	)
Non-cash dividend to Parent	$	6,500		$	—		$	24,500		$	6,500

Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(11,063	)	$	(9,678	)	$	(10,547	)	$	(11,063	)
Income taxes, net	$	—		$	—


(8)	COMMITMENTS AND CONTINGENCIES

~~Other than the item discussed below, there~~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 ~~2014~~2015 Annual Report on Form 10-K.

~~Oil Creek Fire~~

On June 29, 2012, a forest and grassland fire occurred in the western Black Hills of Wyoming. A fire investigator retained by the Weston County Fire Protection District concluded that the fire was caused by the failure of a transmission structure owned, operated and maintained by Black Hills Power. On April 16, 2013, a large group of private landowners filed suit in the United States District Court for the District of Wyoming. There are approximately 36 Plaintiff groups (including property jointly owned by multiple family members or entities), or approximately 73 individually named private plaintiffs. In addition, the State of Wyoming has intervened in the lawsuit. Both the private landowners and the State of Wyoming assert claims for damages against Black Hills Power. The claims include allegations of negligence, negligence per se, common law nuisance and trespass. In addition to claims for compensatory damages, the lawsuit seeks recovery of punitive damages. We have denied and will vigorously defend all claims arising out of the fire. We cannot predict the outcome of expert investigation, the viability of alleged claims or the outcome of the litigation.

Civil litigation of this kind, however, is likely to lead to settlement negotiations, including negotiations prompted by pre-trial civil court procedures. We believe such negotiations would effect a settlement of all claims. Regardless of whether the litigation is determined at trial or through settlement, we expect to incur significant investigation, legal and expert services expenses associated with the litigation. We maintain insurance coverage to limit our exposure to losses due to civil liability claims, and related litigation expense, and we will pursue recoveries to the maximum extent available under the policies. The deductible applicable to some types of claims arising out of this fire is $1.0 million. Based upon information currently available, we believe that a loss associated with settlement of pending claims is probable. Accordingly, we recorded a loss contingency liability related to these claims and we recorded a receivable for costs we believe are reimbursable and probable of recovery under our insurance coverage. Both of these entries reflect our reasonable estimate of probable future litigation expense and settlement costs; we did not base these contingencies on any determination that it is probable we would be found liable for these claims were they to be litigated.

Given the uncertainty of litigation, however, a loss related to the fire, the litigation and related claims in excess of the loss we have determined to be probable is reasonably possible. We cannot reasonably estimate the amount of such possible loss because expert investigations and our review of damage claim documentation are ongoing, and there are significant factual and legal issues to be resolved. Further claims may be presented by these claimants and other parties. We have received claims seeking recovery for fire suppression, reclamation and rehabilitation costs, damage to fencing and other personal property, alleged injury to timber, grass or hay, livestock and related operations, and diminished value of real estate. Based on the legal standard for measuring damages that we believe applies to this matter, we estimate the current total claims to be approximately $55 million; however the actual amount of allowed claims and any loss will depend on the resolution of certain factual and legal issues. We are not yet able to reasonably estimate the amount of any reasonable possible losses in excess of the amount we have accrued. Based upon information currently available, however, management does not expect the outcome of the claims to have a material adverse effect upon our consolidated financial condition, results of operations or cash flows.

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

~~On July 23, 2015,~~During the first quarter of 2016, we ~~received approval from~~commenced construction of the ~~WPSC for a CPCN originally filed on July 22, 2014 to construct the Wyoming portion of a~~ $54 million, 230-kV, 144 mile-long transmission line that ~~would~~will connect the Teckla Substation in northeast Wyoming, to the Lange Substation near Rapid City, South Dakota. ~~We received approval on November 6, 2014 from the SDPUC for a permit to construct the South Dakota portion~~The first segment of this ~~line. We plan~~project connecting Teckla to ~~commence construction~~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 ~~third quarter~~first half of ~~2015.~~2017.

~~On March 2, 2015, the SDPUC issued an order approving a rate stipulation and agreement authorizing an annual electric revenue increase for us of $6.9 million.~~ The agreement was a Global Settlement and did not stipulate return on equity and capital structure. The SDPUC’s decision provides us a return on our investment in Cheyenne Prairie and associated infrastructure, and provides recovery of our share of operating expenses for this natural gas fired facility. We implemented interim rates on October 1, 2014, coinciding with Cheyenne Prairie’s commercial operation date. Final rates were approved on April 1, 2015, effective October 1, 2014.

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 and natural gas.~~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,									Three Months Ended June 30,									Six Months Ended June 30,
	2015			2014			Variance			2015			2014			Variance			2016			2015			Variance			2016			2015			Variance
	(in thousands)																		(in thousands)
Revenue	$	68,038		$	60,741		$	7,297		$	138,321		$	132,007		$	6,314		$	62,019		$	68,038		$	(6,019	)	$	130,661		$	138,321		$	(7,660	)
Fuel and purchased power	19,353			21,278			(1,925		)	41,457			48,323			(6,866		)	16,224			19,353			(3,129		)	36,954			41,457			(4,503		)
Gross margin	48,685			39,463			9,222			96,864			83,684			13,180			45,795			48,685			(2,890		)	93,707			96,864			(3,157		)

Operating expenses	27,542			25,681			1,861			54,231			52,357			1,874			26,859			27,542			(683		)	53,991			54,231			(240		)
Operating income	21,143			13,782			7,361			42,633			31,327			11,306			18,936			21,143			(2,207		)	39,716			42,633			(2,917		)

Interest income (expense), net	(5,575		)	(4,716		)	(859		)	(11,124		)	(9,533		)	(1,591		)	(4,824		)	(5,575		)	751			(9,853		)	(11,124		)	1,271
Other income (expense), net	143			168			(25		)	248			357			(109		)	519			143			376			1,016			248			768
Income tax expense	(5,164		)	(3,004		)	(2,160		)	(10,807		)	(7,278		)	(3,529		)	(4,825		)	(5,164		)	339			(9,887		)	(10,807		)	920
Net income	$	10,547		$	6,230		$	4,317		$	20,950		$	14,873		$	6,077		$	9,806		$	10,547		$	(741	)	$	20,992		$	20,950		$	42

Electric Revenue by Customer Type
Three Months Ended June 30, Six Months Ended June 30,
(in thousands)
2015 Percentage Change 2014 2015 Percentage Change 2014
Residential $ 15,470
8% $ 14,332
$ 35,610
4% $ 34,392
Commercial 24,433
15% 21,200
49,174
15% 42,728
Industrial 8,459
12% 7,534
16,758
13% 14,869
Municipal 859
2% 846
1,717
5% 1,638
Total retail revenue 49,221
12% 43,912
103,259
10% 93,627
Contract wholesale 3,979
(11)% 4,473
9,399
(7)% 10,071
Wholesale off-system 6,666
23% 5,411
13,301
(8)% 14,486
Other revenue 8,172
18% 6,945
12,362
(11)% 13,823
Total revenue $ 68,038
12% $ 60,741
$ 138,321
5% $ 132,007


							Electric Revenue by Customer Type
	Megawatt Hours Sold by Customer Type						Three Months Ended June 30,					Six Months Ended June 30,
	Three Months Ended June 30,			Six Months Ended June 30,			(in thousands)
	2015	Percentage Change	2014	2015	Percentage Change	2014	2016		Percentage Change	2015		2016		Percentage Change	2015
Residential	110,017	2%	107,394	256,980	(8)%	278,704	$	16,241	5%	$	15,470	$	35,556	—%	$	35,610
Commercial	189,889	8%	176,541	384,967	7%	360,989	23,723		(3)%	24,433		47,312		(4)%	49,174
Industrial	102,494	(2)%	104,914	214,353	4%	205,765	7,764		(8)%	8,459		16,265		(3)%	16,758
Municipal	7,036	(9)%	7,709	14,736	(4)%	15,394	960		12%	859		1,791		4%	1,717
Total retail quantity sold	409,436	3%	396,558	871,036	1%	860,852
Total retail revenue							48,688		(1)%	49,221		100,924		(2)%	103,259
Contract wholesale	64,896	(10)%	71,999	149,167	(11)%	167,227	3,947		(1)%	3,979		8,121		(14)%	9,399
Wholesale off-system	246,213	45%	169,498	491,851	16%	424,294	2,734		(59)%	6,666		7,320		(45)%	13,301
Total quantity sold	720,545	13%	638,055	1,512,054	4%	1,452,373
Losses and company use	46,993	(30)%	66,915	73,639	(28)%	102,954
Total energy	767,538	9%	704,970	1,585,693	2%	1,555,327
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 Generated and Purchased
Three Months Ended June 30, Six Months Ended June 30,
Generated - 2015 Percentage Change 2014 2015 Percentage Change 2014
Coal-fired 399,763
19% 336,842
^(a)
776,597
3% 754,090
^(a)
Gas-fired 16,883
534% 2,665
^(b)
19,761
297% 4,972
^(b)
Total generated 416,646
23% 339,507
796,358
5% 759,062

Total purchased 350,892
(4)% 365,463
789,335
(1)% 796,265

Total generated and purchased 767,538
9% 704,970
1,585,693
2% 1,555,327



	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)	~~Increase was~~Decrease is due to a planned ~~annual~~ outage ~~at Neil Simpson II and an unplanned outage for a catalyst replacement~~ at Wygen III

~~during the three and and six months ended June 30, 2014.~~


~~(b)~~	~~Cheyenne Prairie was placed into commercial operations on October 1, 2014.~~ and an extended planned outage at Wyodak.


	Power Plant Availability								Power Plant Availability
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014		2016		2015		2016		2015
Coal-fired plants ^(a)	95.1	%	78.9	%	91.4	%	86.4	%	64.5	%	95.1	%	78.4	%	91.4	%
Other plants ^(b)	96.9	%	81.6	%	96.0	%	90.7	%	99.2	%	96.9	%	98.7	%	96.0	%
Total availability	96.1	%	80.1	%	94.0	%	88.4	%	84.2	%	96.1	%	90.0	%	94.0	%

~~__________________~~____________________


(a)	~~The three months and six months ended June 30, 2014 reflects a planned annual outage at Neil Simpson II and an unplanned outage for a catalyst repair at Wygen III.~~


~~(b)~~	~~The three months and six months ended June 30, 2014 include~~Decrease is due to a planned outage at ~~Bench French CTs #1~~Wygen III and ~~#2 for a controls upgrade.~~an extended planned outage at Wyodak.


	Degree Days												Degree Days						Degree Days
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014			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		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 and cooling degree days:
Heating degree days:
Heating degree days	1,005	—	%	1,025	2	%	3,878	(8	)%	4,435	5	%	877	(13	)%	1,005	—	%	3,683	(13	)%	3,878	(8	)%
Cooling degree days	96	(10	)%	99	(7	)%	96	(10	)%	99	(7	)%	186	74	%	96	(10	)%	186	74	%	96	(10	)%

Three Months Ended June 30, ~~2015~~2016 Compared to Three Months Ended June 30, ~~2014.~~2015. Net income was $1110 million compared to $~~6.2~~11 million for the same period in the prior year primarily due to the following:

Gross margin ~~increased~~decreased primarily due to a prior year increase in return on invested capital ~~investment in Cheyenne Prairie which increased gross margin by$5.1 million. Higher Commercial~~of $1.2 million from a rate case and ~~Industrial MWh sold increased $0.7~~a $1.8 million ~~wholesale margins~~decrease due to third party billing true-ups related to the current and ~~power marketing margins increased $0.4 million, primarily resulting from increased MWh sold, and other one-time items increased $1.8 million. Partially offsetting these increases is a $0.5 million~~prior years, partially offset by the weather impact from ~~weather.~~the increase in cooling degree days compared to the same period in the prior year.

Operations and maintenance ~~increased reflecting an increase in depreciation expense~~decreased primarily due to ~~a higher asset base~~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 ~~addition of Cheyenne Prairie and increased employee costs.~~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 ~~increased~~decreased primarily due to ~~interest costs from~~higher AFUDC income in the ~~$85 million of permanent financing put~~current year driven by higher construction work-in-process balances compared to the same period in ~~place during~~ the ~~fourth quarter of 2014 for Cheyenne Prairie.~~prior year.

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

Income tax expense: The effective tax rate is ~~higher in 2015 primarily due~~comparable to the ~~reduced impact of an estimated flow-through adjustment.~~prior year.

Six Months Ended June 30, ~~2015~~2016 Compared to Six Months Ended June 30, ~~2014.~~2015. Net income was $21 million compared to ~~$15~~$21 million for the same period in the prior year primarily due to the following:

Gross margin ~~increased~~decreased primarily due to a prior year increase in return on invested capital ~~investment in Cheyenne Prairie which increased gross margin by $7.8 million. Wholesale margins increased by $0.9~~of $1.2 million ~~driven by reliability improvements on generation~~from a rate case and a $1.8 million decrease due to third party billing true-ups related to ~~unit contingent contracts. Retail margins increased primarily due to Commercial~~the current and ~~Industrial load increases of $2.0 million from higher MWh sold, and other one-time items increased $2.3 million. These increases are~~prior years, partially offset by ~~$2.2 million~~the weather impact from ~~lower residential MWh sold driven by a 13% decrease~~the increase in cooling degree days compared to the same period in the prior year.

Operations and maintenance ~~increased, reflecting an increase in depreciation expense~~decreased primarily due to ~~a higher asset base~~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 ~~addition of Cheyenne Prairie~~acquired SourceGas utilities. These decreases are partially offsetting by higher depreciation expense driven by additional plant in service and ~~increased plant maintenance.~~higher maintenance expenses driven by current year outages.

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

Income tax expense: The effective tax rate ~~is higher in 2015~~decreased due primarily ~~due~~ to ~~the increase in liability with respect to~~a favorable re-measurement of an uncertain tax ~~positions related to~~position liability involving research and development ~~credits.~~credits and deductions, as a result of an agreement reached during the first quarter of 2016 with the IRS.

~~Financing Plans and Activity~~

~~On October 1, 2014, in a private placement to provide permanent financing for Cheyenne Prairie, we issued $85 million of 4.43% coupon first mortgage bonds due October 20, 2044.~~

~~On September 30, 2014, we repaid in full $12 million in principal on the 5.35% Pollution Control Revenue Bonds originally due to mature on October 1, 2024.~~

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 ~~on July 13, 2015:~~

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 ~~2014~~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.


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, ~~2014~~.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, ~~2015~~.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 ~~effective.~~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

~~There were~~During the quarter ended June 30, 2016, there have been no changes in our internal control over financial reporting ~~during the quarter ended~~ ~~June 30, 2015~~, that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

BLACK HILLS POWER, INC.

Part II - Other Information


Item 1.	Legal Proceedings

For information regarding legal proceedings, see Note 11 of Notes to Financial Statements in Item 8 of our ~~2014~~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, ~~2014.~~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).

~~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).

~~Form 10-Q for the quarterly period ended March 31, 2015).~~

Exhibit 4.1*

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


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


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


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


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


Exhibit 101	Financial Statements for XBRL Format

_________________________


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

BLACK HILLS POWER, INC.

Signatures

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

BLACK HILLS POWER, INC.

/S/ DAVID R. EMERY

David R. Emery, Chairman

and Chief Executive Officer

/S/ RICHARD W. KINZLEY

Richard W. Kinzley, Senior Vice President

and Chief Financial Officer

Dated: August ~~11, 2015~~10, 2016

EXHIBIT INDEX


Exhibit Number	Description


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


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

Exhibit 4.1*


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


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


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


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


Exhibit 101	Financial Statements for XBRL Format

_________________________


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

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