Edgar Filing: BLACK HILLS CORP /SD/

BKH 10Q Q2 2014

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 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, 2014
Common stock, $1.00 par value	44,641,421	shares



TABLE OF CONTENTS
		Page
	Glossary of Terms and Abbreviations	3

PART I.	FINANCIAL INFORMATION	5

Item 1.	Financial Statements	5

	Condensed Consolidated Statements of Income (Loss) - unaudited
	Three and Six Months Ended June 30, 2014 and 2013	5

	Condensed Consolidated Statements of Comprehensive Income (Loss) - unaudited
	Three and Six Months Ended June 30, 2014 and 2013	6

	Condensed Consolidated Balance Sheets - unaudited
	June 30, 2014, December 31, 2013 and June 30, 2013	7

	Condensed Consolidated Statements of Cash Flows - unaudited
	Six Months Ended June 30, 2014 and 2013	9

	Notes to Condensed Consolidated Financial Statements - unaudited	10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	60

Item 4.	Controls and Procedures	61

PART II.	OTHER INFORMATION	62

Item 1.	Legal Proceedings	62

Item 1A.	Risk Factors	62

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	63

Item 4.	Mine Safety Disclosures	63

Item 5.	Other Information	63

Item 6.	Exhibits	63

	Signatures	65

	Index to Exhibits	66

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 issued by the FASB
Bbl	Barrel
BHC	Black Hills Corporation; the Company
Black Hills Electric Generation	Black Hills Electric Generation, LLC, 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
Btu	British thermal unit
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, Wyoming 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 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 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
CT	Combustion turbine
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 subsequently de-designated in December 2008. These swaps were settled in November 2013.
Dth	Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
EPA	United States Environmental Protection Agency
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
GCA	Gas Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of gas and certain services through to customers.



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.
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
KCC	Kansas Corporation Commission
kV	Kilovolt
LIBOR	London Interbank Offered Rate
LOE	Lease Operating Expense
Mcf	Thousand cubic feet
Mcfe	Thousand cubic feet equivalent.
MMBtu	Million British thermal units
Moody’s	Moody’s Investors Service, Inc.
MW	Megawatts
MWh	Megawatt-hours
NGL	Natural Gas Liquids (7 Gallons equals 1 Mcfe)
NOAA	National Oceanic and Atmospheric Administration
NOAA Climate Normals	This dataset is produced once every 10 years. This dataset contains daily and monthly normals of temperature, precipitation, snowfall, heating and cooling degree days, frost/freeze dates, and growing degree days calculated from observations at approximately 9,800 stations operated by NOAA’s National Weather Service.
NOL	Net Operating Loss
OTC	Over-the-counter
PPA	Power Purchase Agreement
Revolving Credit Facility	Our $500 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which matures in 2019.
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
WRDC	Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS)



(unaudited)	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(in thousands, except per share amounts)

Revenue	$	283,237		$	279,826		$	743,406		$	660,497

Operating expenses:
Utilities -
Fuel, purchased power and cost of natural gas sold	101,331			99,172			331,799			267,345
Operations and maintenance	66,074			64,977			137,301			130,667
Non-regulated energy operations and maintenance	21,350			20,890			43,682			42,219
Depreciation, depletion and amortization	36,712			35,152			72,795			69,933
Taxes - property, production and severance	11,044			10,069			21,380			20,449
Other operating expenses	149			529			274			1,001
Total operating expenses	236,660			230,789			607,231			531,614

Operating income	46,577			49,037			136,175			128,883

Other income (expense):
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts and realized settlements on interest rate swaps)	(17,886		)	(23,369		)	(35,746		)	(47,041		)
Allowance for funds used during construction - borrowed	256			411			526			484
Capitalized interest	246			272			503			538
Unrealized gain (loss) on interest rate swaps, net	—			18,793			—			26,249
Interest income	576			475			966			760
Allowance for funds used during construction - equity	293			42			531			242
Other income (expense), net	409			473			1,000			879
Total other income (expense), net	(16,106		)	(2,903		)	(32,220		)	(17,889		)

Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	30,471			46,134			103,955			110,994
Equity in earnings (loss) of unconsolidated subsidiaries	—			—			—			(86		)
Income tax benefit (expense)	(10,651		)	(15,616		)	(36,017		)	(37,193		)
Net income (loss) available for common stock	$	19,820		$	30,518		$	67,938		$	73,715

Earnings (loss) per share of common stock:
Earnings (loss) per share, Basic -
Total income (loss) per share, Basic	$	0.45		$	0.69		$	1.53		$	1.67
Earnings (loss) per share, Diluted -
Total income (loss) per share, Diluted	$	0.44		$	0.69		$	1.52		$	1.66
Weighted average common shares outstanding:
Basic	44,399			44,172			44,365			44,113
Diluted	44,588			44,412			44,571			44,363

Dividends paid per share of common stock	$	0.39		$	0.38		$	0.78		$	0.76

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,
	2014			2013		2014			2013
	(in thousands)

Net income (loss) available for common stock	$	19,820		$	30,518	$	67,938		$	73,715

Other comprehensive income (loss), net of tax:
Fair value adjustments on derivatives designated as cash flow hedges (net of tax (expense) benefit of $1,115 and $(2,174) for the three months ended 2014 and 2013 and $2,422 and $(1,057) for the six months ended 2014 and 2013, respectively)	(1,959		)	3,878		(4,216		)	2,217
Reclassification adjustments for cash flow hedges settled and included in net income (loss) (net of tax (expense) benefit of $(774) and $(647) for the three months ended 2014 and 2013 and $(1,199) and $(883) for the six months ended 2014 and 2013, respectively)	1,403			1,201		2,183			1,669
Benefit plan liability adjustments - net gain (loss) (net of tax of $0 and $0 for the three months ended 2014 and 2013 and $2 and $0 for the six months ended 2014 and 2013, respectively)	—			—		(2		)	—
Benefit plan liability tax adjustments - net gain (loss)	(394		)	—		(394		)	—
Benefit plan liability adjustments - prior service cost (net of tax of $0 and $0 for the three months ended 2014 and 2013 and $(90) and $0 for the six months ended 2014 and 2013, respectively)	—			—		164			—
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $39 and $(268) for the three months ended 2014 and 2013 and $43 and $(251) for the six months ended 2014 and 2013, respectively)	(70		)	364		(79		)	318
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax of $(91) and $0 for the three months ended 2014 and 2013 and $(176) and $(192) for the six months ended 2014 and 2013, respectively)	168			—		325			503
Other comprehensive income (loss), net of tax	(852		)	5,443		(2,019		)	4,707

Comprehensive income (loss) available for common stock	$	18,968		$	35,961	$	65,919		$	78,422

See Note 11 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, 2014			December 31, 2013			June 30, 2013
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	14,697		$	7,841		$	30,633
Restricted cash and equivalents	2			2			7,279
Accounts receivable, net	135,145			177,573			132,726
Materials, supplies and fuel	81,164			88,478			73,768
Derivative assets, current	1,737			717			903
Income tax receivable, net	1,043			1,460			146
Deferred income tax assets, net, current	23,872			18,889			38,764
Regulatory assets, current	64,735			24,451			26,258
Other current assets	21,660			25,877			27,595
Total current assets	344,055			345,288			338,072

Investments	17,096			16,697			16,566

Property, plant and equipment	4,408,291			4,259,445			4,066,502
Less: accumulated depreciation and depletion	(1,325,660		)	(1,269,148		)	(1,234,578		)
Total property, plant and equipment, net	3,082,631			2,990,297			2,831,924

Other assets:
Goodwill	353,396			353,396			353,396
Intangible assets, net	3,286			3,397			3,508
Regulatory assets, non-current	138,226			138,197			180,646
Other assets, non-current	31,808			27,906			22,402
Total other assets, non-current	526,716			522,896			559,952

TOTAL ASSETS	$	3,970,498		$	3,875,178		$	3,746,514

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, 2014			December 31, 2013			June 30, 2013
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	100,098		$	130,416		$	88,071
Accrued liabilities	141,177			151,277			135,819
Derivative liabilities, current	3,480			3,474			69,270
Regulatory liabilities, current	828			10,727			20,550
Notes payable	132,700			82,500			100,000
Current maturities of long-term debt	275,000			—			255,507
Total current liabilities	653,283			378,394			669,217

Long-term debt, net of current maturities	1,121,950			1,396,948			958,559

Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	476,059			432,287			387,674
Derivative liabilities, non-current	4,251			5,614			12,384
Regulatory liabilities, non-current	119,462			109,429			129,013
Benefit plan liabilities	116,403			111,479			177,216
Other deferred credits and other liabilities	137,765			133,279			129,763
Total deferred credits and other liabilities	853,940			792,088			836,050

Commitments and contingencies (See Notes 7, 8, 13, 14 and 15)

Stockholders’ equity:
Common stock equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 44,682,885; 44,550,239; and 44,516,472 shares, respectively	44,683			44,550			44,517
Additional paid-in capital	744,505			742,344			737,729
Retained earnings	573,379			540,244			532,810
Treasury stock, at cost – 40,951; 50,877; and 42,480 shares, respectively	(1,801		)	(1,968		)	(1,587		)
Accumulated other comprehensive income (loss)	(19,441		)	(17,422		)	(30,781		)
Total stockholders’ equity	1,341,325			1,307,748			1,282,688

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,970,498		$	3,875,178		$	3,746,514

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,
	2014			2013
Operating activities:	(in thousands)
Net income (loss) available for common stock	$	67,938		$	73,715
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	72,795			69,933
Deferred financing cost amortization	1,107			2,188
Derivative fair value adjustments	(1,660		)	4,248
Stock compensation	6,908			6,896
Unrealized (gain) loss on interest rate swaps, net	—			(26,249		)
Deferred income taxes	35,514			36,607
Employee benefit plans	7,409			11,096
Other adjustments, net	1,481			8,967
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	7,314			8,940
Accounts receivable, unbilled revenues and other operating assets	(5,851		)	28,377
Accounts payable and other operating liabilities	(24,978		)	(26,739		)
Other operating activities, net	5,858			(594		)
Net cash provided by (used in) operating activities	173,835			197,385

Investing activities:
Property, plant and equipment additions	(177,302		)	(147,230		)
Other investing activities	(2,994		)	2,006
Net cash provided by (used in) investing activities	(180,296		)	(145,224		)

Financing activities:
Dividends paid on common stock	(34,803		)	(33,774		)
Common stock issued	1,693			2,570
Short-term borrowings - issuances	214,100			133,300
Short-term borrowings - repayments	(163,900		)	(310,300		)
Long-term debt - issuances	—			275,000
Long-term debt - repayments	—			(103,786		)
Other financing activities	(3,773		)	—
Net cash provided by (used in) financing activities	13,317			(36,990		)
Net change in cash and cash equivalents	6,856			15,171
Cash and cash equivalents, beginning of period	7,841			15,462
Cash and cash equivalents, end of period	$	14,697		$	30,633

See Note 12 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 2013 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 2013 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, 2014, December 31, 2013, and June 30, 2013 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, 2014 and June 30, 2013, and our financial condition as of June 30, 2014, December 31, 2013, and June 30, 2013, 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.

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) BUSINESS SEGMENT INFORMATION

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, 2014	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss)
Utilities:
Electric	$	158,740	$	3,144		$	11,427
Gas	102,499		—			1,994
Non-regulated Energy:
Power Generation	1,267		20,713			7,194
Coal Mining	5,583		9,068			2,016
Oil and Gas	15,148		—			(1,660		)
Corporate activities	—		—			(1,151		)
Inter-company eliminations	—		(32,925		)	—
Total	$	283,237	$	—		$	19,820



Three Months Ended June 30, 2013	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss)
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
Inter-company eliminations	—		(30,299		)	(3		)
Total	$	279,826	$	—		$	30,518



Six Months Ended June 30, 2014	External Operating Revenues		Intercompany Operating Revenues			Net Income (Loss)
Utilities:
Electric	$	336,835	$	7,151		$	26,002
Gas	361,836		—			26,692
Non-regulated Energy:
Power Generation	2,536		41,792			15,267
Coal Mining	12,201		17,948			4,480
Oil and Gas	29,998		—			(3,682		)
Corporate activities	—		—			(821		)
Inter-company eliminations	—		(66,891		)	—
Total	$	743,406	$	—		$	67,938



Six Months Ended June 30, 2013	External Operating Revenues		Intercompany Operating Revenues			Net Income (Loss)
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 activities ^(a)	—		—			17,378
Inter-company eliminations	—		(61,357		)	—
Total	$	660,497	$	—		$	73,715

__________


(a)	Corporate activities include a $12 million and a $17 million after-tax non-cash mark-to-market gain for the three and six months ended June 30, 2013, respectively on certain interest rate swaps.

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, 2014		December 31, 2013		June 30, 2013
Utilities:
Electric ^(a)	$	2,603,900	$	2,525,947	$	2,417,952
Gas	799,365		805,617		734,337
Non-regulated Energy:
Power Generation^(a)	85,269		95,692		108,515
Coal Mining	73,701		78,825		82,553
Oil and Gas	307,837		288,366		256,855
Corporate activities	100,426		80,731		146,302
Total assets	$	3,970,498	$	3,875,178	$	3,746,514

__________


(a)	The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation Station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.

(3) 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, 2014	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	48,333	$	21,716	$	(622	)	$	69,427
Gas Utilities	43,104		9,265		(1,027		)	51,342
Power Generation	1,388		—		—			1,388
Coal Mining	1,866		—		—			1,866
Oil and Gas	9,123		—		(13		)	9,110
Corporate	2,012		—		—			2,012
Total	$	105,826	$	30,981	$	(1,662	)	$	135,145



	Accounts		Unbilled		Less Allowance for			Accounts
December 31, 2013	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	52,437	$	23,823	$	(666	)	$	75,594
Gas Utilities	49,162		41,195		(558		)	89,799
Power Generation	1,722		—		—			1,722
Coal Mining	1,711		—		—			1,711
Oil and Gas	8,156		—		(13		)	8,143
Corporate	604		—		—			604
Total	$	113,792	$	65,018	$	(1,237	)	$	177,573



	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

(4) REGULATORY ACCOUNTING

We had the following regulatory assets and liabilities (in thousands):



	Maximum	As of		As of		As of
	Amortization (in years)	June 30, 2014		December 31, 2013		June 30, 2013
Regulatory assets
Deferred energy and fuel cost adjustments - current^(a)(d)	1	$	29,605	$	16,775	$	15,951
Deferred gas cost adjustments and natural gas price derivatives^(a)(d)	7	39,040		12,366		13,090
AFUDC^(b)	45	12,468		12,315		12,456
Employee benefit plans ^(c)	13	65,874		67,059		115,379
Environmental^(a)	subject to approval	1,314		1,800		1,798
Asset retirement obligations^(a)	44	3,278		3,266		3,257
Bond issue cost^(a)	24	3,347		3,419		3,489
Renewable energy standard adjustment ^(a)	5	14,501		14,186		14,694
Flow through accounting^(c)	35	22,754		20,916		17,995
Other regulatory assets^(a)	15	10,780		10,546		8,795
		$	202,961	$	162,648	$	206,904

Regulatory liabilities
Deferred energy and gas costs^(a)	1	$	6,490	$	11,708	$	22,340
Employee benefit plans^(c)	13	34,356		34,431		60,214
Cost of removal^(a)	44	70,841		64,970		59,461
Other regulatory liabilities^(c)	25	8,603		9,047		7,548
		$	120,290	$	120,156	$	149,563

__________


(a)	Recovery of costs, but we are not allowed a rate of return.


(b)	In addition to recovery of costs, we are allowed a rate of return.


(c)	In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base, respectively.

(d)

Our deferred energy, fuel cost, and gas cost adjustments represent the cost of electricity and gas delivered to our electric and gas utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. Increases in the current year balances as of June 30, 2014 are primarily due to higher natural gas prices driven by demand and market conditions during our peak winter heating season. Our electric and gas utilities file periodic quarterly, semi-annual, and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions.

(5) 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, 2014		December 31, 2013		June 30, 2013
Materials and supplies	$	51,925	$	50,196	$	51,334
Fuel - Electric Utilities	7,679		6,213		6,817
Natural gas in storage held for distribution	21,560		32,069		15,617
Total materials, supplies and fuel	$	81,164	$	88,478	$	73,768

(6) EARNINGS PER SHARE

A reconciliation of share amounts used to compute Earnings (loss) per share in the accompanying Condensed Consolidated Statements of Income (loss) is as follows (in thousands):



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013

Net income (loss) available for common stock	$	19,820	$	30,518	$	67,938	$	73,715

Weighted average shares - basic	44,399		44,172		44,365		44,113
Dilutive effect of:
Equity compensation	189		240		206		250
Weighted average shares - diluted	44,588		44,412		44,571		44,363

The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive (in thousands):



	Three Months Ended June 30,		Six Months Ended June 30,
	2014	2013	2014	2013

Equity compensation	81	28	63	34
Anti-dilutive shares	81	28	63	34

(7) NOTES PAYABLE AND CURRENT MATURITIES OF LONG-TERM DEBT

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



	June 30, 2014				December 31, 2013				June 30, 2013
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	132,700	$	20,272	$	82,500	$	22,100	$	100,000	$	43,157

Revolving Credit Facility

On May 29, 2014, we amended our $500 million corporate Revolving Credit Facility agreement to extend the term through May 29, 2019. This facility is substantially similar to the former agreement, which includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents, to increase the capacity of the facility to $750 million. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our most favorable Corporate credit rating from S&P and Moody’s for our unsecured debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings and letters of credit were 0.125%, 1.125% and 1.125%, respectively, from May 29, 2014 through June 30, 2014; a reduction of 0.25% for each method of borrowing as compared to the previous arrangement. Borrowings under the facility are primarily Eurodollar based. A commitment fee is charged on the unused amount of the Revolving Credit Facility and was 0.175% based on our credit rating, a reduction of 0.025% compared to the prior arrangement.

Current Maturities Of Long-Term Debt

As of June 30, 2014, our Corporate term loan due June 19, 2015, for $275 million has been re-classified to Current maturities of long-term debt from Long-term debt, net of current maturities.

Debt Covenants

Our Revolving Credit Facility and our Term Loan require compliance with the following financial covenant at the end of each quarter:



	As of June 30, 2014	Covenant Requirement
Recourse Leverage Ratio	54%	Less than	65%

As of June 30, 2014, we were in compliance with this covenant.

(8) 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 2013 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.

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, 2014, our credit exposure included a $0.5 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 rated companies, cooperative utilities and federal agencies. Our derivative and hedging activities recorded 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 in Note 9.

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 OTC 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 in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Revenue in the accompanying Condensed Consolidated Statements of Income (Loss).

The contract or notional amounts, terms of our commodity derivatives, and the derivative balances for our Oil and Gas segment reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of:



	June 30, 2014				December 31, 2013				June 30, 2013
	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)	424,500		9,265,000		412,500		7,082,500		520,500		10,712,500
Maximum terms in months ^(b)	1		1		3		1		6		1
Derivative assets, current	$	—	$	—	$	55	$	—	$	610	$	293
Derivative assets, non-current	$	—	$	—	$	—	$	—	$	—	$	—
Derivative liabilities, current	$	—	$	—	$	—	$	—	$	130	$	276
Derivative liabilities, non-current	$	—	$	—	$	—	$	—	$	—	$	—

__________


(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.

A $3.4 million loss is included in AOCI at June 30, 2014, and would be realized over the next 12 months if market prices remained equal to June 30, 2014 prices. Future realized gains or losses fluctuate with market prices.

Utilities

The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used for Electric Utility generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), 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 the accompanying Condensed Consolidated Balance Sheets in accordance with state commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Condensed Consolidated Statements of Income (Loss).

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, 2014		December 31, 2013		June 30, 2013
	Notional (MMBtus)	Maximum Term (months)	Notional (MMBtus)	Maximum Term (months)	Notional (MMBtus)	Maximum Term (months)
Natural gas futures purchased	16,240,000	78	17,930,000	84	13,330,000	77
Natural gas options purchased	3,980,000	9	3,890,000	8	2,850,000	5
Natural gas basis swaps purchased	13,415,000	66	14,785,000	60	10,650,000	66

We had the following derivative balances related to the hedges in our Utilities reflected in our Condensed Consolidated Balance Sheets as of (in thousands):



	June 30, 2014		December 31, 2013		June 30, 2013
Derivative assets, current	$	1,737	$	662	$	—
Derivative assets, non-current	$	—	$	—	$	—
Derivative liabilities, non-current	$	—	$	—	$	—
Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities	$	3,561	$	7,567	$	8,450

Financing Activities

We entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations. The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of:



	June 30, 2014			December 31, 2013			June 30, 2013
	Interest Rate Swaps^(a)			Interest Rate Swaps^(a)			Interest Rate Swaps^(b)			De-designated Interest Rate Swaps^(c)
Notional	$	75,000		$	75,000		$	150,000		$	250,000
Weighted average fixed interest rate	4.97		%	4.97		%	5.04		%	5.67		%
Maximum terms in years	2.5			3.0			3.5			0.5
Derivative liabilities, current	$	3,480		$	3,474		$	6,965		$	61,899
Derivative liabilities, non-current	$	4,251		$	5,614		$	12,384		$	—

__________


(a)	These swaps are designated to borrowings on our Revolving Credit Facility, and are priced using three-month LIBOR, matching the floating portion of the related debt.

(b)

At June 30, 2013, $75 million of these interest rate swaps were designated to borrowings on our Revolving Credit Facility and $75 million were designated to borrowings on our project financing debt at Black Hills Wyoming. These swaps are priced using three-month LIBOR, matching the floating portion of the related debt. The portion of the swaps that were designated to Black Hills Wyoming were settled during the fourth quarter of 2013 upon repayment of the Black Hills Wyoming project financing.


(c)	These swaps were settled during the fourth quarter of 2013.

Based on June 30, 2014, market interest rates and balances related to our interest rate swaps, a loss of approximately $3.5 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.

Cash Flow Hedges

The impacts of cash flow hedges on our Condensed Consolidated Statements of Income (Loss) were as follows (in thousands):



Three Months Ended June 30, 2014
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)
Interest rate swaps	$	(337	)	Interest expense	$	(926	)		$	—
Commodity derivatives	(2,737		)	Revenue	(1,251		)		—
Total	$	(3,074	)		$	(2,177	)		$	—



Three Months Ended June 30, 2013
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)		Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)
Interest rate swaps	$	1,067	Interest expense	$	(1,820	)		$	—
Commodity derivatives	4,985		Revenue	(28		)		—
Total	$	6,052		$	(1,848	)		$	—



Six Months Ended June 30, 2014
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)
Interest rate swaps	$	(429	)	Interest expense	$	(1,820	)		$	—
Commodity derivatives	(6,209		)	Revenue	(1,562		)		—
Total	$	(6,638	)		$	(3,382	)		$	—



Six Months Ended June 30, 2013
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)		Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)
Interest rate swaps	$	1,048	Interest expense	$	(3,616	)		$	—
Commodity derivatives	2,226		Revenue	1,064				—
Total	$	3,274		$	(2,552	)		$	—

(9) FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

The accounting guidance for fair value measurements requires certain disclosures about assets and liabilities measured at fair value. This guidance establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. 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, 8 and 10 to the Consolidated Financial Statements included in our 2013 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 when 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 using 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 using the market approach with 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 a 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 a 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. Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties.

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 for derivative instruments. A discussion of fair value of financial instruments is included in Note 10:



	As of June 30, 2014
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)
Assets:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	—	$	—	$	—		$	—
Basis Swaps -- Oil	—		—		—		—			—
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		600		—		(600		)	—
Commodity derivatives — Utilities	—		4,342		—		(2,605		)	1,737
Total	$	—	$	4,942	$	—	$	(3,205	)	$	1,737

Liabilities:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	—	$	—	$	—		$	—
Basis Swaps -- Oil	—		4,020		—		(4,020		)	—
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		2,030		—		(2,030		)	—
Commodity derivatives — Utilities	—		5,989		—		(5,989		)	—
Interest rate swaps	—		7,731		—		—			7,731
Total	$	—	$	19,770	$	—	$	(12,039	)	$	7,731



	As of December 31, 2013
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)
Assets:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	—	$	—	$	—		$	—
Basis Swaps -- Oil	—		130		—		(75		)	55
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		815		—		(815		)	—
Commodity derivatives —Utilities	—		3,030		—		(2,368		)	662
Total	$	—	$	3,975	$	—	$	(3,258	)	$	717

Liabilities:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	—	$	—	$	—		$	—
Basis Swaps -- Oil	—		1,229		—		(1,229		)	—
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		531		—		(531		)	—
Commodity derivatives — Utilities	—		9,100		—		(9,100		)	—
Interest rate swaps	—		9,088		—		—			9,088
Total	$	—	$	19,948	$	—	$	(10,860	)	$	9,088



	As of June 30, 2013
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)
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		)	—
Total	$	—	$	4,414	$	—	$	(3,511	)	$	903

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	—		8,581		—		(8,581		)	—
Interest rate swaps	—		87,208		—		(5,960		)	81,248
Total	$	—	$	96,765	$	—	$	(15,111	)	$	81,654

Fair Value Measures by Balance Sheet Classification

As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis reflecting the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements and the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions; however, the amounts do not include net cash collateral on deposit in margin accounts at June 30, 2014, December 31, 2013, and June 30, 2013, to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will not agree with the amounts presented on our Condensed Consolidated Balance Sheets, nor will they correspond to the fair value measurements presented in Note 8.

The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands):



As of June 30, 2014
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	262	$	—
Commodity derivatives	Derivative assets — non-current	338		—
Commodity derivatives	Derivative liabilities — current	—		3,702
Commodity derivatives	Derivative liabilities — non-current	—		2,348
Interest rate swaps	Derivative liabilities — current	—		3,480
Interest rate swaps	Derivative liabilities — non-current	—		4,251
Total derivatives designated as hedges		$	600	$	13,781

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	1,737	$	—
Commodity derivatives	Derivative assets — non-current	—		—
Commodity derivatives	Derivative liabilities — current	—		—
Commodity derivatives	Derivative liabilities — non-current	—		3,384
Total derivatives not designated as hedges		$