Edgar Filing: BLACK HILLS CORP /SD/

BKH 063013 10Q

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, 2013
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 001-31303



Black Hills Corporation
Incorporated in South Dakota	IRS Identification Number 46-0458824
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 x		Accelerated filer o



	Non-accelerated filer o		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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.



Class	Outstanding at July 31, 2013
Common stock, $1.00 par value	44,518,338	shares



TABLE OF CONTENTS
		Page
	Glossary of Terms and Abbreviations	3

PART I.	FINANCIAL INFORMATION	6

Item 1.	Financial Statements	6

	Condensed Consolidated Statements of Income (Loss) - unaudited
	Three and Six Months Ended June 30, 2013 and 2012	6

	Condensed Consolidated Statements of Comprehensive Income (Loss)- unaudited
	Three and Six Months Ended June 30, 2013 and 2012	7

	Condensed Consolidated Balance Sheets - unaudited
	June 30, 2013, Dec. 31, 2012 and June 30, 2012	8

	Condensed Consolidated Statements of Cash Flows - unaudited
	Six Months Ended June 30, 2013 and 2012	10

	Notes to Condensed Consolidated Financial Statements - unaudited	11

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	49

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	86

Item 4.	Controls and Procedures	88

PART II.	OTHER INFORMATION	89

Item 1.	Legal Proceedings	89

Item 1A.	Risk Factors	89

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	89

Item 4.	Mine Safety Disclosures	90

Item 5.	Other Information	90

Item 6.	Exhibits	90

	Signatures	92

	Index to Exhibits	93

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
AOCI	Accumulated Other Comprehensive Income (Loss)
ASU	Accounting Standards Update
Basin Electric	Basin Electric Power Cooperative
Bbl	Barrel
BHC	Black Hills Corporation; the Company
BHEP	Black Hills Exploration and Production, Inc., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, and Black Hills Gas Resources, Inc. and Black Hills Plateau Production, LLC, direct wholly-owned subsidiaries of Black Hills Exploration and Production, Inc.
Black Hills Electric Generation	Black Hills Electric Generation, LLC, representing our Power Generation segment, a direct wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy	The name used to conduct the business of Black Hills Utility Holdings, Inc., and its subsidiaries
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Power	Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Wyoming	Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation
Cheyenne Prairie	Cheyenne Prairie Generating Station currently being constructed in Cheyenne, Wyo. by Cheyenne Light and Black Hills Power. Construction is expected to be completed for this 132 megawatt facility in 2014.
Colorado Electric	Black Hills Colorado Electric Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Colorado Gas	Black Hills Colorado Gas Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Colorado IPP	Black Hills Colorado IPP, LLC a direct wholly-owned subsidiary of Black Hills Electric Generation
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.
Conflict Minerals	As defined by the Dodd-Frank, conflict minerals are cassiterite, columbite-tantalite, gold and wolframite that are mined in the Democratic Republic of the Congo or surrounding countries
CPCN	Certificate of Public Convenience and Necessity
CPUC	Colorado Public Utilities Commission



CTII	The 40 megawatt Gillette CT, a simple-cycle, gas-fired combustion turbine owned by Black Hills Wyoming
CVA	Credit Valuation Adjustment
De-designated interest rate swaps	The $250 million notional amount interest rate swaps that were originally designated as cash flow hedges under accounting for derivatives and hedges but were subsequently de-designated
Dodd-Frank	Dodd-Frank Wall Street Reform and Consumer Protection Act
Dth	Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
Enserco	Enserco Energy Inc., representing our Energy Marketing segment, sold Feb. 29, 2012
FASB	Financial Accounting Standards Board
FERC	United States Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Accounting principles generally accepted in the United States of America
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.
Iowa Gas	Black Hills Iowa Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
IPP	Independent power producer
IRS	United States Internal Revenue Service
IUB	Iowa Utilities Board
Kansas Gas	Black Hills Kansas Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
LIBOR	London Interbank Offered Rate
LOE	Lease Operating Expense
Mcf	Thousand cubic feet of natural gas
Mcfe	Thousand cubic feet equivalent. Natural gas liquid is converted by dividing gallons by 7. Crude oil is converted by multiplying barrels by 6.
MMBtu	Million British thermal units
Moody’s	Moody’s Investors Service, Inc.
MWh	Megawatt-hour





NGL	Natural Gas Liquids. One gallon equals 1/7 Mcfe
NOL	Net Operating Loss
OTC	Over-the-counter
PPA	Power Purchase Agreement
PSCo	Public Service Company of Colorado
Revolving Credit Facility	Our $500 million credit facility which matures in 2017
SDPUC	South Dakota Public Utilities Commission
SEC	U. S. Securities and Exchange Commission
S&P	Standard and Poor’s, a division of The McGraw-Hill Companies, Inc.
WPSC	Wyoming Public Service Commission

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS)



(unaudited)	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(in thousands, except per share and per share amounts)

Revenue	$	279,826		$	242,363		$	660,497		$	608,214

Operating expenses:
Utilities -
Fuel, purchased power and cost of gas sold	99,172			63,452			267,345			220,635
Operations and maintenance	64,977			59,563			130,667			124,323
Non-regulated energy operations and maintenance	20,890			20,713			42,219			43,308
Depreciation, depletion and amortization	35,152			41,431			69,933			79,990
Taxes - property, production and severance	10,069			9,478			20,449			20,988
Impairment of long-lived assets	—			26,868			—			26,868
Other operating expenses	529			267			1,001			1,463
Total operating expenses	230,789			221,772			531,614			517,575

Operating income	49,037			20,591			128,883			90,639

Other income (expense):
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts and realized settlements on interest rate swaps)	(23,369		)	(27,762		)	(47,041		)	(57,676		)
Allowance for funds used during construction - borrowed	410			963			484			1,481
Capitalized interest	272			131			538			292
Unrealized gain (loss) on interest rate swaps, net	18,793			(15,552		)	26,249			(3,507		)
Interest income	475			627			760			1,064
Allowance for funds used during construction - equity	42			195			242			472
Other income (expense), net	474			888			879			2,360
Total other income (expense), net	(2,903		)	(40,510		)	(17,889		)	(55,514		)

Income (loss) from continuing operations before earnings (loss) of unconsolidated subsidiaries and income taxes	46,134			(19,919		)	110,994			35,125
Equity in earnings (loss) of unconsolidated subsidiaries	—			22			(86		)	(34		)
Income tax benefit (expense)	(15,616		)	7,574			(37,193		)	(12,143		)
Income (loss) from continuing operations	30,518			(12,323		)	73,715			22,948
Income (loss) from discontinued operations, net of tax	—			(1,160		)	—			(6,644		)
Net income (loss) available for common stock	$	30,518		$	(13,483	)	$	73,715		$	16,304

Earnings (loss) per share, Basic -
Income (loss) from continuing operations, per share	$	0.69		$	(0.28	)	$	1.67		$	0.52
Income (loss) from discontinued operations, per share	—			(0.03		)	—			(0.15		)
Total income (loss) per share, Basic	$	0.69		$	(0.31	)	$	1.67		$	0.37
Earnings (loss) per share, Diluted -
Income (loss) from continuing operations, per share	$	0.69		$	(0.28	)	$	1.66		$	0.52
Income (loss) from discontinued operations, per share	—			(0.03		)	—			(0.15		)
Total income (loss) per share, Diluted	$	0.69		$	(0.31	)	$	1.66		$	0.37
Weighted average common shares outstanding:
Basic	44,172			43,799			44,113			43,765
Diluted	44,412			43,799			44,363			43,984

Dividends paid per share of common stock	$	0.380		$	0.370		$	0.760		$	0.740

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

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)



(unaudited)	Three Months Ended June 30,					Six Months Ended June 30,
	2013		2012			2013		2012
	(in thousands)

Net income (loss) available for common stock	$	30,518	$	(13,483	)	$	73,715	$	16,304

Other comprehensive income (loss), net of tax:
Fair value adjustment on derivatives designated as cash flow hedges (net of tax (expense) benefit of $(2,174) and $(167) for the three months ended 2013 and 2012 and $(1,057) and $(112) for the six months ended 2013 and 2012, respectively)	3,878		11			2,217		587
Reclassification adjustments related to defined benefit plan (net of tax of $(268) and $0 for the three months ended 2013 and 2012 and $(443) and $0 for the six months ended 2013 and 2012, respectively)	364		—			821		—
Reclassification adjustments of cash flow hedges settled and included in net income (loss) (net of tax (expense) benefit of $(647) and $432 for the three months ended 2013 and 2012 and $(883) and $877 for the six months ended 2013 and 2012, respectively)	1,201		(619		)	1,669		(1,361		)
Other comprehensive income (loss), net of tax	5,443		(608		)	4,707		(774		)

Comprehensive income (loss) available for common stock	$	35,961	$	(14,091	)	$	78,422	$	15,530

See Note 7 for additional disclosures.

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

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS



(unaudited)	As of
	June 30, 2013			Dec. 31, 2012			June 30, 2012
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	30,633		$	15,462		$	40,110
Restricted cash and equivalents	7,279			7,916			4,772
Accounts receivable, net	132,726			163,698			109,157
Materials, supplies and fuel	73,768			77,643			61,455
Derivative assets, current	903			3,236			16,595
Income tax receivable, net	146			—			12,141
Deferred income tax assets, net, current	38,764			77,231			30,401
Regulatory assets, current	26,258			31,125			34,781
Other current assets	27,595			28,795			26,591
Total current assets	338,072			405,106			336,003

Investments	16,566			16,402			16,208

Property, plant and equipment	4,066,502			3,930,772			3,863,380
Less: accumulated depreciation and depletion	(1,234,578		)	(1,188,023		)	(1,006,827		)
Total property, plant and equipment, net	2,831,924			2,742,749			2,856,553

Other assets:
Goodwill	353,396			353,396			353,396
Intangible assets, net	3,508			3,620			3,731
Derivative assets, non-current	—			510			1,770
Regulatory assets, non-current	180,646			188,268			186,886
Other assets, non-current	22,402			19,420			19,733
Total other assets, non-current	559,952			565,214			565,516

TOTAL ASSETS	$	3,746,514		$	3,729,471		$	3,774,280

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

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Continued)



(unaudited)	As of
	June 30, 2013			Dec. 31, 2012			June 30, 2012
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	88,071		$	84,422		$	59,739
Accrued liabilities	135,819			154,389			158,240
Derivative liabilities, current	69,270			96,541			85,675
Accrued income tax, net	—			4,936			—
Regulatory liabilities, current	20,550			13,628			16,785
Notes payable	100,000			277,000			225,000
Current maturities of long-term debt	255,507			103,973			227,590
Total current liabilities	669,217			734,889			773,029

Long-term debt, net of current maturities	958,559			938,877			1,044,891

Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	387,674			385,908			316,393
Derivative liabilities, non-current	12,384			16,941			42,077
Regulatory liabilities, non-current	129,013			127,656			114,593
Benefit plan liabilities	177,216			167,397			162,530
Other deferred credits and other liabilities	129,763			125,294			124,482
Total deferred credits and other liabilities	836,050			823,196			760,075

Commitments and contingencies (See Notes 5, 8, 10 and 13)

Stockholders’ equity:
Common stock equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 44,516,472; 44,278,189; and 44,176,520 shares, respectively	44,517			44,278			44,177
Additional paid-in capital	737,729			733,095			727,613
Retained earnings	532,810			492,869			460,324
Treasury stock, at cost – 42,480; 71,782; and 69,657 shares, respectively	(1,587		)	(2,245		)	(2,177		)
Accumulated other comprehensive income (loss)	(30,781		)	(35,488		)	(33,652		)
Total stockholders’ equity	1,282,688			1,232,509			1,196,285

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,746,514		$	3,729,471		$	3,774,280

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

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



(unaudited)	Six Months Ended June 30,
	2013			2012
Operating activities:	(in thousands)
Net income (loss) available to common stock	$	73,715		$	16,304
(Income) loss from discontinued operations, net of tax	—			6,644
Income (loss) from continuing operations	73,715			22,948
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities:
Depreciation, depletion and amortization	69,933			79,990
Deferred financing cost amortization	2,188			4,050
Impairment of long-lived assets	—			26,868
Derivative fair value adjustments	4,248			(4,895		)
Stock compensation	6,896			3,269
Unrealized (gain) loss on interest rate swaps, net	(26,249		)	3,507
Deferred income taxes	36,607			11,200
Employee benefit plans	11,096			10,492
Other adjustments, net	8,967			3,820
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	8,940			22,609
Accounts receivable, unbilled revenues and other operating assets	28,377			64,028
Accounts payable and other current liabilities	(26,739		)	(60,233		)
Contributions to defined benefit pension plans	—			(25,000		)
Other operating activities, net	(594		)	(7,138		)
Net cash provided by operating activities of continuing operations	197,385			155,515
Net cash provided by (used in) operating activities of discontinued operations	—			21,184
Net cash provided by operating activities	197,385			176,699

Investing activities:
Property, plant and equipment additions	(147,230		)	(148,807		)
Other investing activities	2,006			4,095
Net cash provided by (used in) investing activities of continuing operations	(145,224		)	(144,712		)
Proceeds from sale of discontinued business operations	—			108,837
Net cash provided by (used in) investing activities of discontinued operations	—			(824		)
Net cash provided by (used in) investing activities	(145,224		)	(36,699		)

Financing activities:
Dividends paid on common stock	(33,774		)	(32,583		)
Common stock issued	2,570			1,510
Short-term borrowings - issuances	133,300			56,453
Short-term borrowings - repayments	(310,300		)	(176,453		)
Long-term debt - issuances	275,000			—
Long-term debt - repayments	(103,786		)	(10,418		)
Other financing activities	—			2,833
Net cash provided by (used in) financing activities of continuing operations	(36,990		)	(158,658		)
Net cash provided by (used in) financing activities of discontinued operations	—			—
Net cash provided by (used in) financing activities	(36,990		)	(158,658		)
Net change in cash and cash equivalents	15,171			(18,658		)
Cash and cash equivalents, beginning of period	15,462			58,768			*
Cash and cash equivalents, end of period	$	30,633		$	40,110

_______________


*	Includes cash of discontinued operations of $37.1 million at Dec. 31, 2011.

See Note 2 for supplemental disclosure of cash flow information.

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

BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s 2012 Annual Report on Form 10-K)

(1) MANAGEMENT’S STATEMENT

The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company,” “us,” “we,” 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 Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2012 Annual Report on Form 10-K filed with the SEC.

We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation, Coal Mining and Oil and Gas. Our reportable segments are based on our method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. All of our operations and assets are located within the United States.

Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying Condensed Consolidated Financial Statements reflects all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the June 30, 2013, Dec. 31, 2012, and June 30, 2012 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market price. In particular, the normal peak usage season for electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and six months ended June 30, 2013 and June 30, 2012, and our financial condition as of June 30, 2013, Dec. 31, 2012, and June 30, 2012 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

On Feb. 29, 2012, we sold our Energy Marketing segment, which resulted in this segment being classified as discontinued operations.

Recently Adopted Accounting Standards

Reporting of Amounts Reclassified out of Accumulated Other Comprehensive Income, ASU 2013-02

In February 2013, the FASB issued ASU 2013-02 which requires new disclosures for items reclassified out of AOCI. ASU 2013-02 requires disclosure of (1) changes in components of other comprehensive income, (2) items reclassified out of AOCI and into net income in their entirety, the effect of the reclassification on each affected net income line item and (3) cross references to other disclosures that provide additional detail for components of other comprehensive income that are not reclassified in their entirety to net income. Disclosures are required either on the face of the statements of income or as a separate disclosure in the notes to the financial statements. The new disclosure requirements are effective for interim and annual periods beginning after Dec. 15, 2012. The adoption of this standard did not have an impact on our financial position, results of operations or cash flows. See additional disclosures in Note 7.

Balance Sheet: Disclosure about Offsetting Assets and Liabilities, ASU 2011-11

In December 2011, the FASB issued revised accounting guidance to amend disclosure requirements for offsetting financial assets and liabilities to enhance current disclosures. The revised disclosure guidance affects all companies that have financial instruments and derivative instruments that are either offset in the balance sheet (i.e., presented on a net basis) or subject to an enforceable master netting and/or similar arrangement. In addition, the revised guidance requires that certain enhanced quantitative and qualitative disclosures are made with respect to a company’s netting arrangements and/or rights of offset associated with its financial instruments and/or derivative instruments. The revised disclosure guidance is effective on a retrospective basis for interim and annual periods beginning Jan. 1, 2013. The adoption of this standard did not have an impact on our financial position, results of operations or cash flows. See additional disclosures in Note 11.

Recently Issued Accounting Pronouncements and Legislation

Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists

In July 2013, the FASB issued an amendment to accounting for income taxes which provides guidance on financial statement presentation of an unrecognized tax benefit when an NOL carryforward, a similar tax loss, or a tax credit carryforward exists. The objective in issuing this amendment is to eliminate diversity in practice resulting from a lack of guidance on this topic in current GAAP. Under the amendment, an entity must present an unrecognized tax benefit, or a portion of an unrecognized tax benefit, in the financial statements as a reduction to a deferred tax asset for an NOL carryforward, a similar tax loss, or a tax credit carryforward except under certain conditions. The amendment is effective for fiscal years beginning after Dec. 15, 2013, and interim periods within those years and should be applied to all unrecognized tax benefits that exist as of the effective date. The adoption of this standard is not expected to have an impact on our financial position, results of operations or cash flows.

Inclusion of the Fed Funds Effective Swap Rate as a Benchmark Interest Rate for Hedge Accounting Purposes, ASU 2013-10

In July 2013, the FASB issued an amendment to accounting for derivatives and hedges to permit the Fed Funds Effective Swap Rate to be used as a U.S. benchmark interest rate for hedge accounting purposes effective for new or re-designated hedging relationships entered into on or after July 17, 2013. The amendment also removed the restriction on using different benchmark rates for similar hedges. We will evaluate the impact of this amendment upon re-designating or entering into a new hedging relationship.

Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date, ASU 2013-04

In March 2013, the FASB issued new disclosure requirements for recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements including disclosure of the nature and amount of the obligations. The new disclosure requirements are effective for interim and annual periods beginning after Dec. 15, 2013. The amendment requires additional details in the notes to financial statements, but will not have any other impact on our financial statements.

Dodd-Frank Wall Street Reform and Consumer Protection Act, SEC Final Rule No. 34-67716

In August 2012, under Dodd-Frank, the SEC adopted new requirements for companies that manufacture or contract to manufacture products that contain certain minerals and metals, known as conflict minerals. The final rule requires all issuers that file reports with the SEC, and use conflict minerals, to report supply chain and sourcing information on an annual basis. These new requirements will require due diligence efforts in 2013, with initial disclosure requirements beginning in May 2014. Based on our preliminary analysis, we do not believe that our products contain conflict minerals as defined by the rule; however, our assessment process to determine whether conflict minerals are necessary to the functionality or production of any of our products is not complete.

(2) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION



	Six Months Ended
	June 30, 2013			June 30, 2012
	(in thousands)
Non-cash investing and financing activities from continuing operations—
Property, plant and equipment acquired with accrued liabilities	$	45,000		$	52,204
Increase (decrease) in capitalized assets associated with asset retirement obligations	$	—		$	3,406

Cash (paid) refunded during the period for continuing operations—
Interest (net of amounts capitalized)	$	(44,191	)	$	(55,364	)
Income taxes, net	$	(5,406	)	$	(383	)

(3) MATERIALS, SUPPLIES AND FUEL

The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:



	June 30, 2013		Dec. 31, 2012		June 30, 2012
Materials and supplies	$	51,334	$	43,397	$	41,963
Fuel - Electric Utilities	6,817		8,589		8,089
Natural gas in storage held for distribution	15,617		25,657		11,403
Total materials, supplies and fuel	$	73,768	$	77,643	$	61,455

(4) ACCOUNTS RECEIVABLE

Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:



	Accounts		Unbilled		Less Allowance for			Accounts
June 30, 2013	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	45,250	$	24,290	$	(630	)	$	68,910
Gas Utilities	38,749		13,192		(1,074		)	50,867
Power Generation	157		—		—			157
Coal Mining	2,503		—		—			2,503
Oil and Gas	8,373		—		(19		)	8,354
Corporate	1,935		—		—			1,935
Total	$	96,967	$	37,482	$	(1,723	)	$	132,726



	Accounts		Unbilled		Less Allowance for			Accounts
Dec. 31, 2012	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	54,482	$	23,843	$	(527	)	$	77,798
Gas Utilities	31,495		39,962		(222		)	71,235
Power Generation	16		—		—			16
Coal Mining	2,247		—		—			2,247
Oil and Gas	11,622		—		(19		)	11,603
Corporate	799		—		—			799
Total	$	100,661	$	63,805	$	(768	)	$	163,698



	Accounts		Unbilled		Less Allowance for			Accounts
June 30, 2012	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	36,336	$	25,726	$	(620	)	$	61,442
Gas Utilities	20,627		11,085		(950		)	30,762
Power Generation	197		—		—			197
Coal Mining	1,982		—		—			1,982
Oil and Gas	13,749		—		(105		)	13,644
Corporate	1,130		—		—			1,130
Total	$	74,021	$	36,811	$	(1,675	)	$	109,157

(5) NOTES PAYABLE AND LONG-TERM DEBT

We had the following short-term debt outstanding in the Condensed Consolidated Balance Sheets (in thousands) as of:



	June 30, 2013				Dec. 31, 2012				June 30, 2012
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	100,000	$	43,157	$	127,000	$	36,300	$	75,000	$	36,256
Term Loan due June 2013	—		—		150,000		—		150,000		—
Total	$	100,000	$	43,157	$	277,000	$	36,300	$	225,000	$	36,256

Our Revolving Credit Facility and debt securities contain certain restrictive financial covenants. As of June 30, 2013, we were in compliance with all of these covenants.

Replacement of Notes Payable and Long-term Term Loan

On June 21, 2013, we entered into a new $275 million term loan expiring on June 19, 2015. This new term loan replaced the $150 million term loan due on June 24, 2013, the $100 million corporate term loan due on Sept. 30, 2013, and $25 million in short-term borrowing under our Revolving Credit Facility. At June 30, 2013, the cost of borrowing under this new term loan was 1.375 percent based on LIBOR plus a margin of 1.125 percent. The covenants of the new term loan are substantially the same as the Revolving Credit Facility.

Debt Covenants

Certain debt obligations require compliance with the following covenants at the end of each quarter (dollars in thousands):



	As of
	June 30, 2013			Covenant Requirement
Consolidated Net Worth	$	1,282,688		Greater than	$	961,752
Recourse Leverage Ratio	51.5		%	Less than	65.0		%

(6) EARNINGS PER SHARE

A reconciliation of share amounts used to compute Earnings (loss) per share is as follows (in thousands):



	Three Months Ended June 30,					Six Months Ended June 30,
	2013		2012			2013		2012

Income (loss) from continuing operations	$	30,518	$	(12,323	)	$	73,715	$	22,948

Weighted average shares - basic	44,172		43,799			44,113		43,765
Dilutive effect of:
Restricted stock	125		—			140		150
Stock options	12		—			13		15
Other dilutive effects	103		—			97		54
Weighted average shares - diluted	44,412		43,799			44,363		43,984

Below is a discussion of our potentially dilutive shares that were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive.

Due to our net loss for the quarter ended June 30, 2012, potentially dilutive securities, consisting of outstanding stock options, restricted common stock, restricted stock units, non-vested performance-based share awards and warrants, were excluded from the diluted loss per share calculation due to their anti-dilutive effect. In computing diluted net loss per share, 13,081 options to purchase shares of common stock, 152,318 vested and non-vested restricted stock shares, 34,248 warrants and other performance shares were excluded from the computations for the three months ended June 30, 2012.

In addition to these dilutive shares excluded due to our net loss for the quarter ended June 30, 2012, the following outstanding securities were not included in the computation of diluted earnings (loss) per share as their effect would have been anti-dilutive (in thousands):



	Three Months Ended June 30,		Six Months Ended June 30,
	2013	2012	2013	2012
Stock options	10	99	8	113
Restricted stock	18	66	26	48
Other stock	—	42	—	29
Anti-dilutive shares	28	207	34	190


(7)	OTHER COMPREHENSIVE INCOME (LOSS)

The components of the reclassification adjustments for the period, net of tax, included in Other Comprehensive Income (Loss) were as follows (in thousands):



	Location on the Condensed Consolidated Statements of Income (Loss)	Amount Reclassified from AOCI
		Three Months Ended						Six Months Ended
		June 30, 2013			June 30, 2012			June 30, 2013			June 30, 2012
Gains (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	1,820		$	1,843		$	3,616		$	3,665
Commodity contracts	Revenue	28			(2,894		)	(1,064		)	(5,903		)
		1,848			(1,051		)	2,552			(2,238		)
Income tax	Income tax benefit (expense)	(647		)	432			(883		)	877
Reclassification adjustments related to cash flow hedges, net of tax		$	1,201		$	(619	)	$	1,669		$	(1,361	)

Amortization of defined benefit plans:
Prior service cost	Utilities - Operations and maintenance	$	(31	)	$	—		$	(62	)	$	—
	Non-regulated energy operations and maintenance	(32		)	—			(64		)	—

Actuarial gain (loss)	Utilities - Operations and maintenance	421			—			842			—
	Non-regulated energy operations and maintenance	274			—			548			—
		632			—			1,264			—
Income tax	Income tax benefit (expense)	(268		)	—			(443		)	—
Reclassification adjustments related to defined benefit plans, net of tax		$	364		$	—		$	821		$	—

Balances by classification included within Accumulated other comprehensive income (loss) on the accompanying Condensed Consolidated Balance Sheets are as follows (in thousands):



	Derivatives Designated as Cash Flow Hedges			Employee Benefit Plans			Total
Balance as of Dec. 31, 2011	$	(13,802	)	$	(19,076	)	$	(32,878	)
Other comprehensive income (loss), net of tax	(166		)	—			(166		)
Balance as of March 31, 2012	(13,968		)	(19,076		)	(33,044		)
Other comprehensive income (loss), net of tax	(608		)	—			(608		)
Ending Balance June 30, 2012	$	(14,576	)	$	(19,076	)	$	(33,652	)

Balance as of Dec. 31, 2012	$	(15,713	)	$	(19,775	)	$	(35,488	)
Other comprehensive income (loss), net of tax	(1,193		)	457			(736		)
Balance as of March 31, 2013	(16,906		)	(19,318		)	(36,224		)
Other comprehensive income (loss), net of tax	5,079			364			5,443
Ending Balance June 30, 2013	$	(11,827	)	$	(18,954	)	$	(30,781	)

(8) EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Service cost	$	1,608		$	1,430		$	3,216		$	2,860
Interest cost	3,825			3,687			7,650			7,374
Expected return on plan assets	(4,654		)	(4,084		)	(9,308		)	(8,168		)
Prior service cost	16			22			32			44
Net loss (gain)	3,062			2,408			6,124			4,816
Net periodic benefit cost	$	3,857		$	3,463		$	7,714		$	6,926

Non-pension Defined Benefit Postretirement Healthcare Plans

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Service cost	$	419		$	402		$	838		$	804
Interest cost	417			523			834			1,046
Expected return on plan assets	(20		)	(19		)	(40		)	(38		)
Prior service cost (benefit)	(125		)	(125		)	(250		)	(250		)
Net loss (gain)	121			222			242			444
Net periodic benefit cost	$	812		$	1,003		$	1,624		$	2,006

Supplemental Non-qualified Defined Benefit and Defined Contribution Plans

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Service cost	$	348	$	246	$	696	$	492
Interest cost	332		331		664		662
Prior service cost	1		1		2		2
Net loss (gain)	198		202		396		404
Net periodic benefit cost	$	879	$	780	$	1,758	$	1,560

Contributions

We anticipate that we will make contributions to the benefit plans during 2013 and 2014. Contributions to the Pension Plans are cash contributions made directly to the Pension Plan Trust accounts. Healthcare and Supplemental Plan contributions are made in the form of benefit payments. Contributions and anticipated contributions are as follows (in thousands):



	Contributions Made		Contributions Made		Additional
	Three Months Ended June 30, 2013		Six Months Ended June 30, 2013		Contributions Anticipated for 2013		Contributions Anticipated for 2014
Defined Benefit Pension Plans	$	—	$	—	$	12,500	$	12,500
Non-pension Defined Benefit Postretirement Healthcare Plans	$	784	$	1,568	$	1,568	$	3,350
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans	$	322	$	644	$	643	$	1,463

(9) BUSINESS SEGMENT INFORMATION

Segment information and Corporate activities included in the accompanying Condensed Consolidated Statements of Income (Loss) and Condensed Consolidated Balance Sheets are below.

Segment information and Corporate activities included in the accompanying Condensed Consolidated Statements of Income (Loss) were as follows (in thousands):



Three Months Ended June 30, 2013	External Operating Revenue		Intercompany Operating Revenue			Income (Loss) from Continuing Operations
Utilities:
Electric	$	154,338	$	3,694		$	10,610
Gas	105,836		—			3,192
Non-regulated Energy:
Power Generation	1,031		19,094			5,031
Coal Mining	6,807		7,511			1,973
Oil and Gas	11,814		—			(1,964		)
Corporate activities ^(a)	—		—			11,679
Intercompany eliminations	—		(30,299		)	(3		)
Total	$	279,826	$	—		$	30,518



Three Months Ended June 30, 2012	External Operating Revenue		Intercompany Operating Revenue			Income (Loss) from Continuing Operations
Utilities:
Electric	$	144,560	$	5,174		$	14,159
Gas	70,386		—			1,159
Non-regulated Energy:
Power Generation	759		17,975			3,926
Coal Mining	6,037		7,090			1,234
Oil and Gas ^(b)	20,621		—			(19,621		)
Corporate activities ^(a)	—		—			(13,180		)
Intercompany eliminations	—		(30,239		)	—
Total	$	242,363	$	—		$	(12,323	)



Six Months Ended June 30, 2013	External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	312,821	$	7,841		$	22,966
Gas	305,648		—			21,675
Non-regulated Energy:
Power Generation	2,053		38,432			10,675
Coal Mining	12,817		15,084			3,038
Oil and Gas	27,158		—			(2,017		)
Corporate ^(a)	—		—			17,378
Intercompany eliminations	—		(61,357		)	—
Total	$	660,497	$	—		$	73,715



Six Months Ended June 30, 2012	External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	300,693	$	8,210		$	22,905
Gas	250,908		—			16,366
Non-regulated Energy:
Power Generation	1,937		36,424			10,840
Coal Mining	12,410		15,706			2,234
Oil and Gas^(b)	42,266		—			(19,608		)
Corporate ^(a)(c)	—		—			(9,789		)
Intercompany eliminations	—		(60,340		)	—
Total	$	608,214	$	—		$	22,948

__________

(a)

Income (loss) from continuing operations includes a $12.2 million and a $17.1 million net after-tax non-cash mark-to-market gain on certain interest rate swaps for the three and six months ended June 30, 2013, respectively, and a $10.1 million and a $2.3 million net after-tax non-cash mark-to-market loss for the three and six months ended June 30, 2012, respectively, for those same interest rate swaps.


(b)	Income (loss) from continuing operations includes a $17.3 million non-cash after-tax ceiling test impairment charge. See Note 14 for further information.


(c)	Certain indirect corporate costs and inter-segment interest expense after-tax totaling $1.6 million for the six months ended June 30, 2012, were included in the Corporate activities in continuing operations and were not reclassified as discontinued operations.

Segment information and Corporate balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):



Total Assets (net of inter-company eliminations) as of:	June 30, 2013		Dec. 31, 2012		June 30, 2012
Utilities:
Electric ^(a)	$	2,417,952	$	2,387,458	$	2,300,948
Gas	734,337		765,165		684,545
Non-regulated Energy:
Power Generation^(a)	108,515		119,170		122,856
Coal Mining	82,553		83,810		90,021
Oil and Gas	256,855		258,460		416,617
Corporate activities	146,302		115,408		159,293
Total assets	$	3,746,514	$	3,729,471	$	3,774,280

__________


(a)	The PPA pertaining to the portion of the Pueblo Airport Generation Station owned by Colorado IPP that supports Colorado customers is accounted for as a capital lease. Therefore, assets owned by the Power Generation segment are included in Total assets of Electric Utilities Segment under this accounting for a capital lease.

(10) RISK MANAGEMENT ACTIVITIES

Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operation of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures as discussed in our 2012 Annual Report on Form 10-K.

Market Risk

Market risk is the potential loss that might occur as a result of an adverse change in market price or rate. We are exposed to the following market risks including, but not limited to:


•	Commodity price risk associated with our natural long position in crude oil and natural gas reserves and production and our fuel procurement for certain of our gas-fired generation assets; and


•	Interest rate risk associated with our variable rate debt including our project financing floating rate debt and our other long-term debt instruments.

Credit Risk

Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.

For production and generation activities, we attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit, and other security agreements.

We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience and any specific customer collection issue that is identified.

As of June 30, 2013, our credit exposure included a $0.6 million exposure to a non-investment grade energy marketing company. The remainder of our credit exposure was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies. Our derivative and hedging activities included in the accompanying Condensed Consolidated Balance Sheets, Condensed Consolidated Statements of Income (Loss) and Condensed Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 11.

Oil and Gas

We produce natural gas and crude oil through our exploration and production activities. Our natural long positions, or unhedged open positions, result in commodity price risk and variability to our cash flows.

To mitigate commodity price risk and preserve cash flows, we primarily use over-the-counter swaps, exchange traded futures and related options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on these instruments. These transactions were designated at inception as cash flow hedges, documented under accounting standards for derivatives and hedging, and initially met prospective effectiveness testing. Effectiveness of our hedging position is evaluated at least quarterly.

The derivatives were marked to fair value and were recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets. The effective portion of the gain or loss on these derivatives for which we have elected cash flow hedge accounting is reported in AOCI on the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Revenue on the accompanying Condensed Consolidated Statements of Income (Loss).

We had the following derivatives and related balances for our Oil and Gas segment (dollars in thousands) as of:



	June 30, 2013						Dec. 31, 2012				June 30, 2012
	Crude oil futures, swaps and options			Natural gas futures and swaps			Crude oil futures, swaps and options		Natural gas futures and swaps		Crude oil futures, swaps and options		Natural gas futures and swaps
Notional ^(a)	520,500			10,712,500			528,000		8,215,500		672,000		9,020,500
Maximum terms in years ^(b)	0.50			0.08			1.00		0.75		1.50		1.25
Derivative assets, current	$	610		$	293		$	1,405	$	1,831	$	2,483	$	4,386
Derivative assets, non-current	$	—		$	—		$	297	$	170	$	1,316	$	255
Derivative liabilities, current	$	130		$	276		$	847	$	507	$	456	$	452
Derivative liabilities, non-current	$	—		$	—		$	—	$	—	$	981	$	331
Pre-tax accumulated other comprehensive income (loss)	$	827		$	1,415		$	206	$	873	$	1,727	$	3,305
Cash collateral receivable (payable) included in derivatives	$	(142	)	$	(1,419	)	$	786	$	620	$	613	$	553
Cash collateral included in other assets or other liabilities	$	(149	)	$	(1,007	)	$	1,078	$	709	$	267	$	51

__________


(a)	Crude oil in Bbls, natural gas in MMBtus.


(b)	Refers to the term of the derivative instrument. Assets and liabilities are classified as current/non-current based on the term of the hedged transaction and the corresponding settlement of the derivative instrument.

Based on market prices at June 30, 2013, a $0.7 million gain would be reclassified from AOCI during the next 12 months. Estimated and actual realized gains or losses will change during future periods as market prices fluctuate.

Utilities

The operations of our utilities, including tolling arrangements, expose our utility customers to volatility in natural gas prices; therefore, as allowed or required by state utility commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, options and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP. Unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in accordance with state commission guidelines. Accordingly, the hedging activity is recognized in the Condensed Consolidated Statements of Income (Loss) or the Condensed Consolidated Statements of Comprehensive Income (Loss) when the related costs are recovered through our rates.

The contract or notional amounts and terms of the natural gas derivative commodity instruments held at our Utilities were as follows, as of:



	June 30, 2013		Dec. 31, 2012		June 30, 2012
	Notional (MMBtus)	Maximum Term (months)	Notional (MMBtus)	Maximum Term (months)	Notional (MMBtus)	Maximum Term (months)
Natural gas futures purchased	13,330,000	77	15,350,000	83	12,440,000	78
Natural gas options purchased	2,850,000	5	2,430,000	2	2,840,000	9
Natural gas basis swaps purchased	10,650,000	66	12,020,000	72	7,270,000	78

We had the following derivative balances related to the hedges in our Utilities (in thousands) as of:



	June 30, 2013		Dec. 31, 2012		June 30, 2012
Derivative assets, current	$	—	$	—	$	9,726
Derivative assets, non-current	$	—	$	43	$	199
Derivative liabilities, non-current	$	—	$	—	$	6,453
Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities	$	8,450	$	9,596	$	13,691

Cash collateral receivable (payable) included in derivatives	$	7,203	$	8,576	$	15,925
Cash collateral included in Other current assets or liabilities	$	2,938	$	4,354	$	—
Option premiums and commissions included in derivatives	$	1,247	$	1,063	$	1,238

Financing Activities

We have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations. Our interest rate swaps and related balances were as follows (dollars in thousands) as of:



	June 30, 2013						Dec. 31, 2012						June 30, 2012
	Designated Interest Rate Swaps^(a)			De-designated Interest Rate Swaps^(b)			Designated Interest Rate Swaps^(a)			De-designated Interest Rate Swaps^(b)			Designated Interest Rate Swaps^(a)			De-designated Interest Rate Swaps^(b)
Notional	$	150,000		$	250,000		$	150,000		$	250,000		$	150,000		$	250,000
Weighted average fixed interest rate	5.04		%	5.67		%	5.04		%	5.67		%	5.04		%	5.67		%
Maximum terms in years	3.50			0.50			4.00			1.00			4.50			1.50
Derivative liabilities, current	$	6,965		$	61,899		$	7,039		$	88,148		$	6,766		$	78,001
Derivative liabilities, non-current	$	12,384		$	—		$	16,941		$	—		$	18,976		$	15,336
Pre-tax accumulated other comprehensive income (loss)	$	(19,349	)	$	—		$	(23,980	)	$	—		$	(25,742	)	$	—
Pre-tax gain (loss)	$	—		$	26,249		$	—		$	1,882		$	—		$	(3,507	)
Cash collateral receivable (payable) included in derivatives	$	—		$	5,960		$	—		$	5,960		$	—		$	6,160

__________

(a)

These swaps have been designated to $75.0 million of borrowings on our Revolving Credit Facility and $75.0 million of borrowings on our project financing debt at Black Hills Wyoming. The swaps transferred to Black Hills Wyoming such that BHC and Black Hills Wyoming are both jointly and severally liable for the amount of those obligations. These swaps are priced using three-month LIBOR, matching the floating portion of the related swaps.


(b)	Maximum terms in years reflect the amended early termination dates. If the early termination dates are not extended, the swaps will require cash settlement based on the swap value on the termination date. If extended, de-designated swaps totaling $100.0 million notional terminate in 5.5 years and de-designated swaps totaling $150.0 million notional terminate in 15.5 years.

Collateral requirements based on our corporate credit rating apply to $50.0 million of our de-designated swaps. At our current credit ratings, we are required to post collateral for any amount by which the swaps’ negative mark-to-market fair value exceeds $20.0 million. If our senior unsecured credit rating drops to BB+ or below by S&P, or to Ba1 or below by Moody’s, we would be required to post collateral for the entire amount of the swaps’ negative mark-to-market fair value. We had $6.0 million cash collateral posted at June 30, 2013.

Based on June 30, 2013 market interest rates and balances related to our designated interest rate swaps, a loss of approximately $7.0 million would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. Estimated and actual realized gains or losses will change during future periods as market interest rates change.

(11) FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

The accounting guidance for fair value measurements requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. For additional information see Notes 1, 3 and 4 included in our 2012 Annual Report on Form 10-K filed with the SEC.

Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

Valuation Methodologies for Derivatives

Oil and Gas Segment:


•	The commodity option contracts for our Oil and Gas segment are valued under the market approach and can include calls and puts. Fair value was derived using quoted prices from third party brokers for similar instruments as to quantity and timing. The prices are then validated through third party sources and therefore support Level 2 disclosure.


•	The commodity basis swaps for our Oil and Gas segment are valued under the market approach using the instrument’s current forward price strip hedged for the same quantity and date and discounted based on the three-month LIBOR. We utilize observable inputs which support Level 2 disclosure.

Utilities Segments:

•

The commodity contracts for our Utilities Segments, valued using the market approach, include exchange-traded futures, options and basis swaps (Level 2) and OTC basis swaps (Level 3) for natural gas contracts. For Level 2 assets and liabilities, fair value was derived using broker quotes validated by the Chicago Mercantile Exchange pricing for similar instruments. For Level 3 assets and liabilities, fair value was derived using average price quotes from the OTC contract broker and an independent third party market participant because these instruments are not traded on an exchange.

Corporate Activities:

•

The interest rate swaps are valued using the market approach. We establish fair value by obtaining price quotes directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty is then validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for the interest rate swap derivatives includes a CVA component. The CVA considers the fair value of the interest rate swap and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings.

Recurring Fair Value Measurements

There have been no significant transfers between Level 1 and Level 2 derivative balances. The following tables set forth by level within the fair value hierarchy our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis (in thousands):



	As of June 30, 2013
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
Assets:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	45	$	—	$	(6	)	$	39
Basis Swaps -- Oil	—		1,109		—		(538		)	571
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		1,882		—		(1,589		)	293
Commodity derivatives — Utilities	—		1,378		—		(1,378		)	—
Cash equivalents ^(a)	30,633		—		—		—			30,633
Total	$	30,633	$	4,414	$	—	$	(3,511	)	$	31,536

Liabilities:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	181	$	—	$	(98	)	$	83
Basis Swaps -- Oil	—		350		—		(303		)	47
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		445		—		(169		)	276
Commodity derivatives — Utilities	—</