BLACK HILLS POWER INC - FORM 10-Q

Attached files

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EXCEL - IDEA: XBRL DOCUMENT - BLACK HILLS POWER INC	Financial_Report.xls
EX-32.1 - EXHIBIT - BLACK HILLS POWER INC	bhpex-321q22014.htm
EX-32.2 - EXHIBIT - BLACK HILLS POWER INC	bhpex-322q22014.htm
EX-31.2 - EXHIBIT - BLACK HILLS POWER INC	bhpex-312q22014.htm
EX-31.1 - EXHIBIT - BLACK HILLS POWER INC	bhpex-311q22014.htm

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, 2014
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, 2014, 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, 2014 and 2013

	Condensed Balance Sheets - unaudited	5
	June 30, 2014 and December 31, 2013

	Condensed Statements of Cash Flows - unaudited	7
	Six Months Ended June 30, 2014 and 2013

	Notes to Condensed Financial Statements - unaudited	8

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

Item 4.	Controls and Procedures	19

PART II.	OTHER INFORMATION	19

Item 1.	Legal Proceedings	19

Item 1A.	Risk Factors	19

Item 6.	Exhibits	20

	Signatures	21

	Exhibit Index	22

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
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
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc. a direct, wholly-owned subsidiary of BHC
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, a 132 MW generating facility, currently being constructed in Cheyenne, Wyoming by Cheyenne Light and Black Hills Power
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
CT	Combustion Turbine
EPA	Environmental Protection Agency
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
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,
(unaudited)	2014			2013			2014			2013
	(in thousands)

Revenue	$	60,741		$	60,832		$	132,007		$	120,649

Operating expenses:
Fuel, purchased power and natural gas	21,278			21,124			48,323			43,222
Operations and maintenance	17,338			17,141			35,448			33,949
Depreciation and amortization	6,972			7,036			13,859			14,022
Taxes - property	1,371			1,238			3,050			2,660
Total operating expenses	46,959			46,539			100,680			93,853

Operating income	13,782			14,293			31,327			26,796

Other income (expense):
Interest expense	(4,984		)	(4,924		)	(9,931		)	(9,771		)
AFUDC - borrowed	57			41			129			99
Interest income	211			36			269			63
AFUDC - equity	117			49			262			183
Other income (expense), net	51			144			95			226
Total other income (expense)	(4,548		)	(4,654		)	(9,176		)	(9,200		)

Income from continuing operations before income taxes	9,234			9,639			22,151			17,596
Income tax expense	(3,004		)	(2,987		)	(7,278		)	(5,362		)
Net income	6,230			6,652			14,873			12,234

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, 2014 and 2013 and $(11) and $(12) for the six months ended June 30, 2014 and 2013, respectively)	11			10			21			20
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(4) and $(6) for the three months ended June 30, 2014 and 2013 and $(8) and $(12) for the six months ended June 30, 2014 and 2013, respectively)	7			11			14			22
Other comprehensive income	18			21			35			42

Comprehensive income	$	6,248		$	6,673		$	14,908		$	12,276

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, 2014			December 31, 2013
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	4,286		$	2,259
Receivables - customers, net	28,917			25,799
Receivables - affiliates	5,009			4,934
Other receivables, net	478			579
Money pool notes receivable, net	3,240			17,292
Materials, supplies and fuel	24,494			23,278
Deferred income tax assets, net, current	413			2,170
Regulatory assets, current	10,250			4,891
Other, current assets	4,396			4,933
Total current assets	81,483			86,135

Investments	4,537			4,431

Property, plant and equipment	1,135,265			1,095,884
Less accumulated depreciation and amortization	(344,724		)	(334,174		)
Total property, plant and equipment, net	790,541			761,710

Other assets:
Regulatory assets, non-current	42,722			40,373
Other, non-current assets	8,114			8,524
Total other assets	50,836			48,897
TOTAL ASSETS	$	927,397		$	901,173

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, 2014			December 31, 2013
	(in thousands, except common stock par value and share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	29,003		$	26,144
Accounts payable - affiliates	20,467			21,082
Accrued liabilities	18,341			14,966
Regulatory liabilities, current	364			161
Total current liabilities	68,175			62,353

Long-term debt, net of current maturities	269,950			269,948

Deferred credits and other liabilities:
Deferred income tax liability, net, non-current	173,698			167,309
Regulatory liabilities, non-current	43,235			43,357
Benefit plan liabilities	12,290			12,105
Other, non-current liabilities	3,287			4,247
Total deferred credits and other liabilities	232,510			227,018

Commitments and contingencies (Notes 5, 6 and 9)

Stockholders’ 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	294,933			280,060
Accumulated other comprehensive loss	(1,162		)	(1,197		)
Total stockholders’ equity	356,762			341,854
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	927,397		$	901,173

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)



(unaudited)	Six Months Ended June 30,
	2014			2013
	(in thousands)
Operating activities:
Net income	$	14,873		$	12,234
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization	13,859			14,022
Deferred income tax	7,237			5,138
Employee benefits	647			1,548
AFUDC - equity	(262		)	(183		)
Other adjustments, net	(1,720		)	618
Change in operating assets and liabilities -
Accounts receivable and other current assets	(8,743		)	(869		)
Accounts payable and other current liabilities	7,802			(5,260		)
Other operating activities, net	(2,002		)	1,371
Net cash provided by (used in) operating activities	31,691			28,619

Investing activities:
Property, plant and equipment additions	(43,478		)	(32,100		)
Change in money pool notes receivable, net	14,052			2,186
Other investing activities	(105		)	(27		)
Net cash provided by (used in) investing activities	(29,531		)	(29,941		)

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

Net change in cash and cash equivalents	2,027			(1,322		)

Cash and cash equivalents, beginning of period	2,259			3,805
Cash and cash equivalents, end of period	$	4,286		$	2,483

See Note 8 for supplemental cash flow information.

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

BLACK HILLS POWER, INC.

Notes to Condensed Financial Statements

(unaudited)

(Reference is made to Notes to Financial Statements

included in our 2013 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 2013 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, 2014, December 31, 2013 and June 30, 2013 financial information and are of a normal recurring nature. The results of operations for the three months and six months ended June 30, 2014 and June 30, 2013, and our financial condition as of June 30, 2014 and December 31, 2013 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 all new accounting pronouncements that are in effect and may impact our financial statements and do not believe that there are any other new accounting pronouncements that have been issued that might have a material impact on our financial position, results of operations, or cash flows.

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. ASU 2014-09 is effective for annual and interim reporting periods beginning after December 15, 2016 and early adoption is not permitted. We are currently assessing the impact, 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, 2014			December 31, 2013
Accounts receivable trade	$	20,224		$	16,300
Unbilled revenues	8,886			9,719
Allowance for doubtful accounts	(193		)	(220		)
Receivables - customers, net	$	28,917		$	25,799


(3)	REGULATORY ASSETS AND LIABILITIES

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, 2014		December 31, 2013
Regulatory assets:
Unamortized loss on reacquired debt^(a)	14	$	2,135	$	2,257
AFUDC^(b)	45	8,365		8,327
Employee benefit plans^(c)	13	15,314		15,233
Deferred energy and fuel cost adjustments - current^(a)	1	11,509		7,711
Flow through accounting^(a)	35	10,324		9,723
Other^(a)	2	5,325		2,013
Total regulatory assets		$	52,972	$	45,264



Regulatory liabilities:
Cost of removal for utility plant^(a)	53	$	32,066	$	30,467
Employee benefit plans	13	10,327		10,177
Other	13	1,206		2,874
Total regulatory liabilities		$	43,599	$	43,518

____________________


(a)	Recovery or return 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 of costs, we are allowed a return on a portion of this amount or a reduction in rate base, respectively.


(4)	PROPERTY, PLANT AND EQUIPMENT

On March 21, 2014, we retired our Osage, Ben French and Neil Simpson I electric generating plants primarily due to federal environmental regulations. The total plant to be decommissioned remaining in Property, plant and equipment at June 30, 2014 is as follows (in thousands):



Cost of Plant		Accumulated Depreciation			Net Book Value
$	54,756	$	(50,808	)	$	3,948

We reasonably expect the remaining book value to be recovered through future rates.


(5)	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, 2014		December 31, 2013
Receivables - affiliates	$	5,009	$	4,934
Accounts payable - affiliates	$	20,467	$	21,082

Money Pool Notes Receivable and Notes Payable

We have entered into a Utility Money Pool Agreement (the “Agreement”) with BHC, Cheyenne Light and 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 BHCs’ 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, 2014, the average cost of borrowing under the Utility Money Pool was 1.32%.

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



	June 30, 2014		December 31, 2013
Money pool notes receivable, net	$	3,240	$	17,292

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Net interest income (expense)	$	27	$	138	$	84	$	288

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Revenue:
Energy sold to Cheyenne Light	$	397	$	217	$	1,076	$	357
Rent from electric properties	$	1,051	$	986	$	2,074	$	1,974

Fuel and purchased power:
Purchases of coal from WRDC	$	4,018	$	4,741	$	9,032	$	9,265
Purchase of excess energy from Cheyenne Light	$	584	$	969	$	1,213	$	1,915
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	465	$	415	$	1,129	$	1,065
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	750	$	711	$	1,844	$	1,796

Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	6,703	$	7,328	$	14,190	$	15,054


(6)	EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

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,
	2014			2013			2014			2013
Service cost	$	176		$	213		$	352		$	426
Interest cost	748			742			1,496			1,484
Expected return on plan assets	(925		)	(941		)	(1,851		)	(1,882		)
Prior service cost	10			11			21			22
Net loss (gain)	235			652			470			1,304
Net periodic benefit cost	$	244		$	677		$	488		$	1,354

Non-pension Defined Benefit Postretirement Healthcare Plan

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Service cost	$	56		$	54		$	112		$	108
Interest cost	60			60			120			120
Prior service cost (benefit)	(84		)	(69		)	(168		)	(138		)
Net loss (gain)	—			2			—			4
Net periodic benefit cost	$	32		$	47		$	64		$	94

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,
	2014		2013		2014		2013
Interest cost	$	36	$	33	$	73	$	66
Net loss (gain)	11		17		22		34
Net periodic benefit cost	$	47	$	50	$	95	$	100

Contributions

We anticipate we will make contributions to the benefit plans during 2014 and 2015. Contributions to the Defined 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, 2014		Remaining Anticipated Contributions for 2014		Anticipated Contributions for 2015
Defined Benefit Pension Plan	$	—	$	—	$	20
Non-Pension Defined Benefit Postretirement Healthcare Plan	$	277	$	277	$	595
Supplemental Non-qualified Defined Benefit Plans	$	109	$	109	$	215


(7)	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 2013 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, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents ^(a)	$	4,286	$	4,286	$	2,259	$	2,259
Long-term debt, including current maturities^(b)	$	269,950	$	342,926	$	269,948	$	317,531

_________________


(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.


(8)	SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION



Six months ended June 30,	2014			2013
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	9,824		$	7,240

Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(9,678	)	$	(9,498	)
Income taxes, net	$	—		$	—


(9)	COMMITMENTS AND CONTINGENCIES

Other than the items discussed below, 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 2013 Annual Report on Form 10-K.

Bond Purchase Agreement

On June 30, 2014, we entered into a Bond Purchase Agreement to issue $85 million of 4.43% coupon first mortgage bonds due October 20, 2044 to finance Cheyenne Prairie. Closing on the delayed-draw private placement first mortgage bonds is anticipated to be October 1, 2014, subject to satisfaction of customary closing conditions.

Cheyenne Prairie

Construction is continuing on Cheyenne Prairie, a natural gas-fired electric generating facility, jointly owned by us and Cheyenne Light. We own 55 MW and Cheyenne Light owns 40 MW of the facility’s combined-cycle unit. We expect to incur approximately $96 million for our share of the combined-cycle unit. Project-to-date expenditures for our share of the combined-cycle unit are approximately $84 million. Expenditures for construction costs for our share of the combined cycle unit for the three and six month periods ended June 30, 2014, are approximately $6.0 million and $18 million, respectively. Construction is expected to be completed by September 30, 2014. As of June 30, 2014, committed contracts for equipment purchases and for construction were 100% and 98% complete, respectively.

Oil Creek Fire

On June 29, 2012, a forest and grassland fire occurred in the western Black Hills of Wyoming. A state fire investigator 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 lawsuit was filed in the United States District Court for the District of Wyoming, which forty-seven plaintiffs and the State of Wyoming have now joined, asserting 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 these compensatory damages, the lawsuit seeks recovery of punitive damages. Our investigation of the cause and origin of the fire is ongoing. We have denied and will vigorously defend all claims arising out of the fire, pending the completion of our investigation. We cannot predict the outcome of our 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. The deductible applicable to some types of claims arising out of this fire is $1.0 million. We expect this coverage to limit our exposure, and we will pursue recoveries to the maximum extent available under the policies. Based upon information currently available, we believe that a loss associated with settlement of pending claims is probable. Accordingly, as of June 30, 2014, 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. However, we cannot reasonably estimate the amount of such possible loss because our investigation and review of damage claims documentation is ongoing, and there are significant factual and legal issues to be resolved. Further claims may be presented by these and other parties. While 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, currently totaling $50 million, we are not yet able, for the reasons described above, 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

Cheyenne Prairie

Construction continued on Cheyenne Prairie, a jointly owned natural gas-fired electric generating facility, to serve our customers and the customers of Cheyenne Light. We own 55 MW and Cheyenne Light owns 40 MW of a combined-cycle unit that is part of the facility. We expect to incur approximately $96 million for our share of the combined-cycle unit. Project-to-date expenditures for our share of the combined-cycle unit are approximately $84 million. The project is on schedule to be placed into service in October of 2014.

On September 17, 2013, the SDPUC approved the use of a construction financing rider for the South Dakota portion of costs for Cheyenne Prairie, effective April 1, 2013. We recorded additional gross margins of approximately $1.5 million and $3.1 million for the three and six months ended June 30, 2014, respectively, relating to this rider. The WPSC approved a similar construction financing rider for our Wyoming customers during 2012.

Bond Purchase Agreement

Regulatory Matters

On July 22, 2014, Black Hills Power filed a CPCN with the WPSC to construct a $54 million, 230-kV, 144 mile-long transmission line that would connect the Teckla Substation in northeast Wyoming, to the Lange Substation near Rapid City, South Dakota, for the Wyoming portion of this line. On June 30, 2014, Black Hills Power filed an application with the SDPUC, for a permit to construct the South Dakota portion of this line. Approval by the WPSC and SDPUC is anticipated in the fourth quarter of 2014.

On March 31, 2014, we filed a rate request with the SDPUC for an annual revenue increase of $14.6 million to recover operating expenses and infrastructure investments, primarily for Cheyenne Prairie. The filing seeks a return on equity of 10.25%, and a capital structure of approximately 53.3% equity and 46.7% debt. This filing also includes recovery of deferred costs for both Winter Storm Atlas and the retirement of certain plants. Osage, Ben French, and Neil Simpson I were retired on March 21, 2014 primarily due to federal environmental regulations.

On January 17, 2014, we filed a request with the WPSC for an annual revenue increase of $2.8 million, to recover investments made in electric infrastructure, primarily for Cheyenne Prairie. The filing seeks a return on equity of 10.25% and a capital structure of approximately 53.3% equity and 46.7% debt.

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, purchased power and natural gas. 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,
	2014			2013			Variance			2014			2013			Variance
	(in thousands)
Revenue	$	60,741		$	60,832		$	(91	)	$	132,007		$	120,649		$	11,358
Fuel and purchased power	21,278			21,124			154			48,323			43,222			5,101
Gross margin	39,463			39,708			(245		)	83,684			77,427			6,257

Operating expenses	25,681			25,415			266			52,357			50,631			1,726
Operating income	13,782			14,293			(511		)	31,327			26,796			4,531

Interest income (expense), net	(4,716		)	(4,847		)	131			(9,533		)	(9,609		)	76
Other income (expense), net	168			193			(25		)	357			409			(52		)
Income tax expense	(3,004		)	(2,987		)	(17		)	(7,278		)	(5,362		)	(1,916		)
Net income	$	6,230		$	6,652		$	(422	)	$	14,873		$	12,234		$	2,639



	Electric Revenue by Customer Type
	Three Months Ended June 30,					Six Months Ended June 30,
	(in thousands)
	2014		Percentage Change	2013		2014		Percentage Change	2013
Residential	$	14,332	6%	$	13,535	$	34,392	15%	$	29,977
Commercial	21,200		12%	18,913		42,728		17%	36,397
Industrial	7,534		4%	7,210		14,869		12%	13,220
Municipal	846		—%	847		1,638		5%	1,561
Total retail revenue	43,912		8%	40,505		93,627		15%	81,155
Contract wholesale	4,473		(9)%	4,926		10,071		(6)%	10,693
Off-system wholesale	5,411		(31)%	7,849		14,486		3%	14,099
Other revenue	6,945		(8)%	7,552		13,823		(6)%	14,702
Total revenue	$	60,741	—%	$	60,832	$	132,007	9%	$	120,649



	Megawatt Hours Sold by Customer Type
	Three Months Ended June 30,			Six Months Ended June 30,
	2014	Percentage Change	2013	2014	Percentage Change	2013
Residential	107,394	(5)%	113,525	278,704	2%	274,495
Commercial	176,541	1%	174,763	360,989	3%	350,380
Industrial	104,914	(1)%	105,856	205,765	4%	197,488
Municipal	7,709	(5)%	8,147	15,394	(3)%	15,930
Total retail quantity sold	396,558	(1)%	402,291	860,852	3%	838,293
Contract wholesale	71,999	(7)%	77,653	167,227	(8)%	181,437
Wholesale off-system	169,498	(39)%	277,840	424,294	(18)%	516,287
Total quantity sold	638,055	(16)%	757,784	1,452,373	(5)%	1,536,017
Losses and company use	66,915	45%	46,054	102,954	19%	86,155
Total energy	704,970	(12)%	803,838	1,555,327	(4)%	1,622,172



	Megawatt Hours Generated and Purchased
	Three Months Ended June 30,				Six Months Ended June 30,
Generated -	2014		Percentage Change	2013	2014		Percentage Change	2013
Coal-fired	336,842	^(a)(b)	(25)%	450,097	754,090	^(a)(b)	(14)%	877,112
Gas-fired	2,665	^(c)	(42)%	4,558	4,972	^(c)	(35)%	7,678
Total generated	339,507		(25)%	454,655	759,062		(14)%	884,790

Total purchased	365,463		5%	349,183	796,265		8%	737,382
Total generated and purchased	704,970		(12)%	803,838	1,555,327		(4)%	1,622,172

__________________

(a) Decrease reflects the retirement of Neil Simpson I on March 21, 2014.


(b)	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.


(c)	The three months and six months ended June 30, 2014 include a planned outage at Ben French CT's #1 and #2 for a controls upgrade.



	Power Plant Availability
	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Coal-fired plants ^(a)	78.9	%	97.8	%	86.4	%	96.9	%
Other plants ^(b)	81.6	%	97.8	%	90.7	%	97.8	%
Total availability	80.1	%	97.8	%	88.4	%	97.2	%

____________________


(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 a planned outage at Ben French CT's #1 and #2 for a controls upgrade.



	Degree Days						Degree Days
	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	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	1,025	2	%	1,227	43	%	4,435	5	%	4,437	9	%
Cooling degree days	99	(7	)%	78	(27	)%	99	(7	)%	78	(27	)%

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013. Net income was $6.2 million compared to $6.7 million for the same period in the prior year primarily due to the following:

Gross margin was comparable to the prior year, reflecting increased rider margins by $0.6 million due to a return on additional investment in our generating facilities. This increase was partially offset by a decrease in contract wholesale of $0.6 million, resulting primarily from plant outages, and lower retail megawatt sold of $0.4 million driven primarily by a decrease in heating degree days compared to the same period in the prior year.

Operations and maintenance increased primarily due to increased maintenance, regulatory and transmission planning costs, partially offset by lower employee costs.

Interest expense, net was comparable to the same period in the prior year, reflecting lower interest expense in the current year, partially offset by lower current year interest income driven by a decrease in Utility money pool lending.

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

Income tax expense: The effective tax rate is higher in 2014 when compared to 2013 due primarily to the research and development tax credit not being extended to 2014.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013. Net income was $15 million compared to $12 million for the same period in the prior year primarily due to the following:

Gross margin increased primarily due a $1.5 million increase resulting from higher retail volumes sold, and a return on additional investments which increased base electric margins by $4.0 million, and increased rider margins by $2.3 million. These increases are partially offset by a $1.0 million decrease in contract wholesale margins primarily due to plant outages.

Operations and maintenance increased primarily due to increased maintenance, regulatory, and transmission and engineering costs, partially offset by lower vegetation management and employee costs.

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

Income tax expense: The effective tax rate is higher in 2014 when compared to 2013 due primarily to the research and development tax credit not being extended to 2014. The prior year reflected the entire year of the 2012 research and development tax credit due to retroactive reinstatement of the credit in January 2013 by U.S. Congress.

Future Financing Plans

We anticipate closing on the delayed-draw private placement bonds executed on June 30, 2014, to finance Cheyenne Prairie. It’s anticipated we will execute the draw of $85 million on October 1, 2014.

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. As of June 30, 2014, our credit ratings for our Senior Secured Debt, as assessed by the three major credit rating agencies, were as follows:



Rating Agency	Rating
S&P	A-
Moody’s^(*)	A1
Fitch ^(**)	A

______________________


*	On January 30, 2014, Moody’s upgraded the BHP credit rating with a stable outlook.

** On June 13, 2014, Fitch upgraded the BHP credit rating to A with a Stable outlook.

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.

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 2013 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, 2013.

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, 2014. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2014, that 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 2013 Annual Report on Form 10-K and Note 9 of our Notes to Condensed Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 9 is incorporated by reference into this item.


Item 1A.	Risk Factors

Except as noted below, 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, 2013.

Federal and state laws concerning greenhouse gas regulations and air emissions may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain.

We own and operate regulated fossil-fuel generating plants in South Dakota and Wyoming. Recent developments under federal and state laws and regulations governing air emissions from fossil-fuel generating plants will likely result in more stringent emission limitations, which could have a material impact on our costs of operations. In addition to the environmental matters identified in Item 1A of our Annual Report on Form 10-K, the following recently proposed regulations could negatively impact our operations.

On June 2, 2014, the EPA proposed the Clean Power Plan to cut carbon emissions from existing electric generating units. The design of the Clean Power Plan is to decrease existing coal-fired generation, and increase the utilization of existing gas generation, increase renewable energy, and demand side management. This rule could have a significant impact on our coal, natural gas and oil generating fleet. The rule calls for states to develop plans to meet their assigned emission rate targets by 2030. The rule also allows states to formulate a regional approach whereby they would join with other states and be assigned a new single target for the group. We are currently evaluating this proposal, but cannot predict the impact on operations as this rule is expected to be final in June 2015, and state plans are expected to be due at the earliest in June 2016, with extensions possible to 2017 and 2018. We expect any impact to us to be mitigated through the recent Osage, Ben French and Neil Simpson I plant closures.

New or more stringent regulations or other energy efficiency requirements could require us to incur significant additional costs relating to, among other things, the installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, and the closure of certain generating facilities. To the extent our regulated fossil-fuel generating plants are included in rate base we will attempt to recover costs associated with complying with emission standards or other requirements. We will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel generating plants from utility and other purchasers of the power generated by those non-regulated power plants. Any unrecovered costs could have a material impact on our results of operations and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain.


Item 6.	Exhibits


Exhibit 3.1*	Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant’s Form 8-K dated June 7, 1994 (No. 1-7978)).


Exhibit 3.2*	Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant’s Form 10-K for 2000).


Exhibit 3.3*	Bylaws of the Registrant (filed as an exhibit to the Registrant’s Registration Statement on Form S-8 dated July 13, 1999).

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)).

Exhibit 10*

Bond Purchase Agreement dated as of June 30, 2014 by and among Black Hills Power, Inc., New York Life Insurance Company, New York Life Insurance and Annuity Corporation, Teachers Insurance and Annuity Association of America, John Hancock Life Insurance Company (U.S.A.), John Hancock Life & Health Insurance Company, John Hancock Life Insurance Company of New York and United of Omaha Life Insurance Company (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on July 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/ ANTHONY S. CLEBERG

Anthony S. Cleberg, Executive Vice President

and Chief Financial Officer

Dated: August 8, 2014

EXHIBIT INDEX


Exhibit Number	Description


Exhibit 3.1*	Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant’s Form 8-K dated June 7, 1994 (No. 1-7978)).


Exhibit 3.2*	Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant’s Form 10-K for 2000).


Exhibit 3.3*	Bylaws of the Registrant (filed as an exhibit to the Registrant’s Registration Statement on Form S-8 dated July 13, 1999).

Exhibit 4.1*

Exhibit 10*


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.

Attached files

BLACK HILLS POWER INC Reports

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