Edgar Filing: BLACK HILLS CORP /SD/

BKH 033113 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 March 31, 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 April 30, 2013

Common stock, $1.00 par value	44,442,886	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 - unaudited
	Three Months Ended March 31, 2013 and 2012	5

	Condensed Consolidated Statements of Comprehensive Income - unaudited
	Three Months Ended March 31, 2013 and 2012	6

	Condensed Consolidated Balance Sheets - unaudited
	March 31, 2013, Dec. 31, 2012 and March 31, 2012	7

	Condensed Consolidated Statements of Cash Flows - unaudited
	Three Months Ended March 31, 2013 and 2012	9

	Notes to Condensed Consolidated Financial Statements - unaudited	10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	60

Item 4.	Controls and Procedures	63

PART II.	OTHER INFORMATION	64

Item 1.	Legal Proceedings	64

Item 1A.	Risk Factors	64

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	64

Item 4.	Mine Safety Disclosures	64

Item 5.	Other Information	64

Item 6.	Exhibits	65

	Signatures	66

	Index to Exhibits	67

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
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 Mineral	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
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.
IFRS	International Financial Reporting Standards
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
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 7 Mcfe
OTC	Over-the-counter
PPA	Power Purchase Agreement
PSCo	Public Service Company of Colorado
Revolving Credit Facility	Our $500 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, 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

(unaudited)



	Three Months Ended March 31,
	2013			2012
	(in thousands, except per share amounts)

Revenue	$	380,671		$	365,851

Operating expenses:
Utilities -
Fuel, purchased power and cost of gas sold	168,173			157,183
Operations and maintenance	65,690			64,760
Non-regulated energy operations and maintenance	21,329			22,595
Depreciation, depletion and amortization	34,781			38,559
Taxes - property, production and severance	10,380			11,510
Other operating expenses	472			1,196
Total operating expenses	300,825			295,803

Operating income	79,846			70,048

Other income (expense):
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts and realized settlements on interest rate swaps)	(23,672		)	(29,914		)
Allowance for funds used during construction - borrowed	74			518
Capitalized interest	266			161
Unrealized gain (loss) on interest rate swaps, net	7,456			12,045
Interest income	285			437
Allowance for funds used during construction - equity	200			277
Other income (expense), net	405			1,472
Total other income (expense)	(14,986		)	(15,004		)

Income (loss) from continuing operations before earnings (loss) of unconsolidated subsidiaries and income taxes	64,860			55,044
Equity in earnings (loss) of unconsolidated subsidiaries	(86		)	(56		)
Income tax benefit (expense)	(21,577		)	(19,717		)
Income (loss) from continuing operations	43,197			35,271
Income (loss) from discontinued operations, net of tax	—			(5,484		)
Net income (loss) available for common stock	$	43,197		$	29,787

Earnings (loss) per share, Basic -
Income (loss) from continuing operations, per share	$	0.98		$	0.81
Income (loss) from discontinued operations, per share	—			(0.13		)
Total income (loss) per share, Basic	$	0.98		$	0.68
Earnings (loss) per share, Diluted -
Income (loss) from continuing operations, per share	$	0.97		$	0.80
Income (loss) from discontinued operations, per share	—			(0.12		)
Total income (loss) per share, Diluted	$	0.97		$	0.68
Weighted average common shares outstanding:
Basic	44,053			43,731
Diluted	44,312			43,969

Dividends paid per share of common stock	$	0.380		$	0.370

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

(unaudited)



	Three Months Ended March 31,
	2013			2012
	(in thousands)

Net income (loss) available for common stock	$	43,197		$	29,787

Other comprehensive income (loss), net of tax:
Fair value adjustment on derivatives designated as cash flow hedges (net of tax (expense) benefit of $1,117 and $55, respectively)	(1,661		)	576
Reclassification adjustments related to defined benefit plan (net of tax of $(175) and $0)	457			—
Reclassification adjustments of cash flow hedges settled and included in net income (loss) (net of tax (expense) benefit of $(236) and $445, respectively)	468			(742		)
Other comprehensive income (loss), net of tax	(736		)	(166		)

Comprehensive income (loss) available for common stock	$	42,461		$	29,621

See Note 8 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
	March 31, 2013			Dec. 31, 2012			March 31, 2012
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	12,397		$	15,462		$	56,132
Restricted cash and equivalents	6,846			7,916			8,960
Accounts receivable, net	168,783			163,698			143,987
Materials, supplies and fuel	64,189			77,643			63,236
Derivative assets, current	1,630			3,236			17,877
Income tax receivable, net	—			—			10,399
Deferred income tax assets, net, current	38,196			77,231			23,710
Regulatory assets, current	23,422			31,125			56,282
Other current assets	28,260			28,795			26,546
Total current assets	343,723			405,106			407,129

Investments	16,545			16,402			16,451

Property, plant and equipment	3,977,704			3,930,772			3,800,011
Less accumulated depreciation and depletion	(1,210,833		)	(1,188,023		)	(980,944		)
Total property, plant and equipment, net	2,766,871			2,742,749			2,819,067

Other assets:
Goodwill	353,396			353,396			353,396
Intangible assets, net	3,565			3,620			3,787
Derivative assets, non-current	—			510			881
Regulatory assets, non-current	181,119			188,268			186,093
Other assets, non-current	21,367			19,420			21,132
Total other assets, non-current	559,447			565,214			565,289

TOTAL ASSETS	$	3,686,586		$	3,729,471		$	3,807,936

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
	March 31, 2013			Dec. 31, 2012			March 31, 2012
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	82,437		$	84,422		$	59,793
Accrued liabilities	140,230			154,389			151,130
Derivative liabilities, current	89,112			96,541			76,389
Accrued income tax, net	1,157			4,936			—
Regulatory liabilities, current	19,020			13,628			35,414
Notes payable	245,000			277,000			225,000
Current maturities of long-term debt	104,637			103,973			8,977
Total current liabilities	681,593			734,889			556,703

Long-term debt, net of current maturities	936,477			938,877			1,272,016

Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	367,502			385,908			317,369
Derivative liabilities, non-current	15,237			16,941			43,169
Regulatory liabilities, non-current	126,573			127,656			112,516
Benefit plan liabilities	172,353			167,397			157,623
Other deferred credits and other liabilities	125,958			125,294			123,848
Total deferred credits and other liabilities	807,623			823,196			754,525

Commitments and contingencies (See Notes 6, 9, 11 and 14)

Stockholders’ equity:
Common stock equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 44,482,304; 44,278,189; and 44,151,428 shares, respectively	44,482			44,278			44,151
Additional paid-in capital	735,000			733,095			725,512
Retained earnings	519,184			492,869			490,114
Treasury stock, at cost – 41,606; 71,782; and 65,015 shares, respectively	(1,549		)	(2,245		)	(2,041		)
Accumulated other comprehensive income (loss)	(36,224		)	(35,488		)	(33,044		)
Total stockholders’ equity	1,260,893			1,232,509			1,224,692

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,686,586		$	3,729,471		$	3,807,936

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)



	Three Months Ended March 31,
	2013			2012
	(in thousands)
Operating activities:
Net income (loss) available to common stock	$	43,197		$	29,787
(Income) loss from discontinued operations, net of tax	—			5,484
Income (loss) from continuing operations	43,197			35,271
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities:
Depreciation, depletion and amortization	34,781			38,559
Deferred financing cost amortization	1,095			2,719
Derivative fair value adjustments	3,673			1,594
Stock compensation	3,778			1,817
Unrealized mark-to-market (gain) loss on interest rate swaps	(7,456		)	(12,045		)
Deferred income taxes	20,541			18,083
Allowance for funds used during construction - equity	(200		)	(277		)
Employee benefit plans	5,548			5,246
Other adjustments, net	3,614			2,243
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	18,519			20,828
Accounts receivable, unbilled revenues and other current assets	(9,166		)	9,439
Accounts payable and other current liabilities	(13,637		)	(42,368		)
Regulatory assets	9,463			(776		)
Regulatory liabilities	374			18,938
Contributions to defined benefit pension plans	—			(25,000		)
Other operating activities, net	(4,892		)	610
Net cash provided by operating activities of continuing operations	109,232			74,881
Net cash provided by (used in) operating activities of discontinued operations	—			21,184
Net cash provided by operating activities	109,232			96,065

Investing activities:
Property, plant and equipment additions	(63,939		)	(67,652		)
Other investing activities	1,030			1,105
Net cash provided by (used in) investing activities of continuing operations	(62,909		)	(66,547		)
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	(62,909		)	41,466

Financing activities:
Dividends paid on common stock	(16,882		)	(16,276		)
Common stock issued	1,231			764
Short-term borrowings - issuances	78,500			56,453
Short-term borrowings - repayments	(110,500		)	(176,453		)
Long-term debt - repayments	(1,737		)	(1,897		)
Other financing activities	—			(2,758		)
Net cash provided by (used in) financing activities of continuing operations	(49,388		)	(140,167		)
Net cash provided by (used in) financing activities of discontinued operations	—			—
Net cash provided by (used in) financing activities	(49,388		)	(140,167		)
Net change in cash and cash equivalents	(3,065		)	(2,636		)
Cash and cash equivalents, beginning of period*	15,462			58,768
Cash and cash equivalents, end of period	$	12,397		$	56,132

_______________________


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

See Note 3 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 March 31, 2013, Dec. 31, 2012 and March 31, 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 and 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 months ended March 31, 2013 and March 31, 2012, and our financial condition as of March 31, 2013, Dec. 31, 2012, and March 31, 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.

(2) RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS AND LEGISLATION

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) for 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 8.

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, as well as to improve comparability of balance sheets prepared under GAAP and IFRS. 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 12.

Recently Issued Accounting Pronouncements and Legislation

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 Aug. 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 rules requires all issuers that file reports with the SEC to report supply chain and sourcing information for companies that use conflict minerals on an annual basis. These new requirements will require due diligence efforts in fiscal 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.

(3) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION



	Three Months Ended
	March 31, 2013			March 31, 2012
	(in thousands)
Non-cash investing and financing activities from continuing operations—
Property, plant and equipment acquired with accrued liabilities	$	31,780		$	31,644
Increase (decrease) in capitalized assets associated with asset retirement obligations	$	—		$	2,826

Cash (paid) refunded during the period for continuing operations—
Interest (net of amounts capitalized)	$	(12,768	)	$	(16,799	)
Income taxes, net	$	(4,656	)	$	(1,838	)

(4) 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:



	March 31, 2013		Dec. 31, 2012		March 31, 2012
Materials and supplies	$	50,401	$	43,397	$	44,361
Fuel - Electric Utilities	8,445		8,589		7,812
Natural gas in storage held for distribution	5,343		25,657		11,063
Total materials, supplies and fuel	$	64,189	$	77,643	$	63,236

(5) ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

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
March 31, 2013	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	47,896	$	21,591	$	(623	)	$	68,864
Gas Utilities	59,024		28,439		(751		)	86,712
Power Generation	3		—		—			3
Coal Mining	1,857		—		—			1,857
Oil and Gas	10,340		—		(19		)	10,321
Corporate	1,026		—		—			1,026
Total	$	120,146	$	50,030	$	(1,393	)	$	168,783



	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
March 31, 2012	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	44,356	$	19,381	$	(585	)	$	63,152
Gas Utilities	44,287		18,502		(936		)	61,853
Power Generation	265		—		—			265
Coal Mining	2,578		—		—			2,578
Oil and Gas	15,014		—		(105		)	14,909
Corporate	1,230		—		—			1,230
Total	$	107,730	$	37,883	$	(1,626	)	$	143,987

(6) NOTES PAYABLE

Our Revolving Credit Facility and debt securities contain certain restrictive financial covenants. As of March 31, 2013, we were in compliance with all of these covenants.

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



	March 31, 2013				Dec. 31, 2012				March 31, 2012
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	95,000	$	36,500	$	127,000	$	36,300	$	75,000	$	41,200
Term Loan due June 2013	150,000		—		150,000		—		150,000		—
Total	$	245,000	$	36,500	$	277,000	$	36,300	$	225,000	$	41,200

Debt Covenants

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



	As of
	March 31, 2013			Covenant Requirement
Consolidated Net Worth	$	1,260,893		Greater than	$	946,493
Recourse Leverage Ratio	52.2		%	Less than	65.0		%

(7) EARNINGS PER SHARE

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



	Three Months Ended March 31,
	2013		2012

Income (loss) from continuing operations	$	43,197	$	35,271

Weighted average shares - basic	44,053		43,731
Dilutive effect of:
Restricted stock	155		147
Stock options	13		18
Other dilutive effects	91		73
Weighted average shares - diluted	44,312		43,969

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 March 31,
	2013	2012
Stock options	6	127
Restricted stock	34	31
Other stock	—	16
Anti-dilutive shares	40	174


(8)	OTHER COMPREHENSIVE INCOME

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



	Location on the Condensed Consolidated Statements of Income	Amount Reclassified from AOCI
	Location on the Condensed Consolidated Statements of Income	Three Months Ended March 31, 2013			Three Months Ended March 31, 2012
Gains and losses on cash flow hedges:
Interest rate swaps	Interest expense	$	1,796		$	1,822
Commodity contracts	Revenue	(1,092		)	(3,009		)
		704			(1,187		)
Income tax	Income tax benefit (expense)	(236		)	445
Total reclassification adjustments related to cash flow hedges, net of tax		$	468		$	(742	)

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

Actuarial gain (loss)	Utilities - Operations and maintenance	421			—
	Non-regulated energy operations and maintenance	274			—
		632			—
Income tax	Income tax benefit (expense)	(175		)	—
Total reclassification adjustments related to defined benefit plans, net of tax		$	457		$	—

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 December 31, 2011	$	(13,802	)	$	(19,076	)	$	(32,878	)
Other comprehensive income (loss), net of tax	(166		)	—			(166		)
Ending Balance March 31, 2012	$	(13,968	)	$	(19,076	)	$	(33,044	)

Balance as of December 31, 2012	$	(15,713	)	$	(19,775	)	$	(35,488	)
Other comprehensive income (loss), net of tax	(1,193		)	457			(736		)
Ending Balance March 31, 2013	$	(16,906	)	$	(19,318	)	$	(36,224	)

(9) 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 March 31,
	2013			2012
Service cost	$	1,608		$	1,430
Interest cost	3,825			3,687
Expected return on plan assets	(4,654		)	(4,084		)
Prior service cost	16			22
Net loss (gain)	3,062			2,408
Net periodic benefit cost	$	3,857		$	3,463

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 March 31,
	2013			2012
Service cost	$	419		$	402
Interest cost	417			523
Expected return on plan assets	(20		)	(19		)
Prior service cost (benefit)	(125		)	(125		)
Net loss (gain)	121			222
Net periodic benefit cost	$	812		$	1,003

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 March 31,
	2013		2012
Service cost	$	348	$	246
Interest cost	332		331
Prior service cost	1		1
Net loss (gain)	198		202
Net periodic benefit cost	$	879	$	780

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		Additional
	Three Months Ended March 31, 2013		Contributions Anticipated for 2013		Contributions Anticipated for 2014
Defined Benefit Pension Plans	$	—	$	8,787	$	19,922
Non-pension Defined Benefit Postretirement Healthcare Plans	$	784	$	2,352	$	3,350
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans	$	322	$	965	$	1,463

(10) BUSINESS SEGMENT INFORMATION

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

On Feb. 29, 2012, we sold our Energy Marketing segment, Enserco, which resulted in this segment being classified as discontinued operations. Indirect corporate costs and inter-segment interest expense related to Enserco that have not been classified as discontinued operations have been reclassified to Corporate activity.

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



Three Months Ended March 31, 2013	External Operating Revenue		Intercompany Operating Revenue			Income (Loss) from Continuing Operations
Utilities:
Electric	$	158,483	$	4,147		$	12,356
Gas	199,812		—			18,483
Non-regulated Energy:
Power Generation	1,022		19,338			5,644
Coal Mining	6,010		7,573			1,065
Oil and Gas	15,344		—			(53		)
Corporate activities ^(a)	—		—			5,699
Intercompany eliminations	—		(31,058		)	3
Total	$	380,671	$	—		$	43,197



Three Months Ended March 31, 2012	External Operating Revenue		Intercompany Operating Revenue			Income (Loss) from Continuing Operations
Utilities:
Electric	$	156,133	$	3,036		$	8,746
Gas	180,522		—			15,207
Non-regulated Energy:
Power Generation	1,178		18,449			6,914
Coal Mining	6,373		8,616			1,000
Oil and Gas	21,645		—			13
Corporate activities ^(a)(b)	—		—			3,391
Intercompany eliminations	—		(30,101		)	—
Total	$	365,851	$	—		$	35,271

_____________


(a)	Income (loss) from continuing operations includes a $4.8 million and a $7.8 million net after-tax non-cash mark-to-market gain for the three months ended March 31, 2013 and 2012, respectively.


(b)	Certain indirect corporate costs and inter-segment interest expense after-tax totaling $1.6 million for the three months ended March 31, 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 was as follows (in thousands):



Total Assets (net of inter-company eliminations) as of:	March 31, 2013		Dec. 31, 2012		March 31, 2012
Utilities:
Electric ^(a)	$	2,367,014	$	2,387,458	$	2,268,524
Gas	752,468		765,165		717,185
Non-regulated Energy:
Power Generation^(a)	115,708		119,170		128,225
Coal Mining	82,839		83,810		87,139
Oil and Gas	255,786		258,460		430,851
Corporate activities	112,771		115,408		176,012
Total assets	$	3,686,586	$	3,729,471	$	3,807,936

___________


(a)	The PPA under which the Pueblo Airport Generation site owned by Colorado IPP 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.

(11) 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 with crude oil and natural gas reserves and production and fuel procurement for certain of our gas-fired generation assets; and


•	Interest rate risk associated with our variable rate credit facility, 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 March 31, 2013, our credit exposure included a $2.3 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 and Condensed Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 12.

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.

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



	March 31, 2013					Dec. 31, 2012				March 31, 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)	522,000		10,633,000			528,000		8,215,500		522,000			5,001,750
Maximum terms in years ^(b)	0.75		0.5			1		0.75		1.25			1.5
Derivative assets, current	$	821	$	287		$	1,405	$	1,831	$	406		$	8,256
Derivative assets, non-current	$	—	$	—		$	297	$	170	$	46		$	808
Derivative liabilities, current	$	250	$	1,188		$	847	$	507	$	2,904		$	—
Derivative liabilities, non-current	$	—	$	—		$	—	$	—	$	1,084		$	—
Pre-tax accumulated other comprehensive income (loss)	$	10	$	(2,781	)	$	206	$	873	$	(3,566	)	$	9,064
Cash collateral receivable (payable) included in derivatives	$	730	$	1,880		$	786	$	620	$	—		$	—
Cash collateral included in Other current assets	$	723	$	2,102		$	1,078	$	709	$	—		$	—

____________


(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 March 31, 2013 market prices, a $0.2 million loss 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. 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 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 Gas Utilities were as follows, as of:



	March 31, 2013		Dec. 31, 2012		March 31, 2012
	Notional (MMBtus)	Maximum Term (months)	Notional (MMBtus)	Maximum Term (months)	Notional (MMBtus)	Maximum Term (months)
Natural gas futures purchased	13,180,000	80	15,350,000	83	11,550,000	81
Natural gas options purchased	440,000	5	2,430,000	2	670,000	12
Natural gas basis swaps purchased	11,350,000	69	12,020,000	72	7,640,000	81

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



	March 31, 2013		Dec. 31, 2012		March 31, 2012
Derivative assets, current	$	522	$	—	$	9,215
Derivative assets, non-current	$	—	$	43	$	27
Derivative liabilities, non-current	$	—	$	—	$	6,407
Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities	$	4,315	$	9,596	$	15,223

Cash collateral receivable (payable) included in derivatives	$	4,487	$	8,576	$	17,651
Cash collateral included in Other current assets	$	3,295	$	4,354	$	—
Option premiums and commissions included in derivatives	$	350	$	1,063	$	407

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:



	March 31, 2013						Dec. 31, 2012						March 31, 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	3.75			0.75			4.00			1.00			4.75			1.75
Derivative liabilities, current	$	6,982		$	80,692		$	7,039		$	88,148		$	6,777		$	66,708
Derivative liabilities, non-current	$	15,237		$	—		$	16,941		$	—		$	18,441		$	17,237
Pre-tax accumulated other comprehensive income (loss)	$	(22,219	)	$	—		$	(23,980	)	$	—		$	(25,218	)	$	—
Pre-tax gain (loss)	$	—		$	7,456		$	—		$	1,882		$	—		$	12,045
Cash collateral receivable (payable) included in derivatives	$	—		$	5,960		$	—		$	5,960		$	—		$	—

_____________

(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 6 years and de-designated swaps totaling $150.0 million notional terminate in 16 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 March 31, 2013.

Based on March 31, 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.

(12) FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

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 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 Segment:

•

The commodity contracts for our Utilities, 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 since 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 assets and liabilities that were accounted for at fair value on a recurring basis (in thousands):



	As of March 31, 2013
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
Assets:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	71	$	—	$	(11	)	$	60
Basis Swaps -- Oil	—		836		—		(75		)	761
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		435		—		(148		)	287
Commodity derivatives — Utilities	—		1,897		—		(1,375		)	522
Cash equivalents ^(a)	12,397		—		—		—			12,397
Total	$	12,397	$	3,239	$	—	$	(1,609	)	$	14,027

Liabilities:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	396	$	—	$	(204	)	$	192
Basis Swaps -- Oil	—		670		—		(612		)	58
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		3,216		—		(2,028		)	1,188
Commodity derivatives — Utilities	—		5,862		—		(5,862		)	—
Interest rate swaps	—		108,871		—		(5,960		)	102,911
Total	$	—	$	119,015	$	—	$	(14,666	)	$	104,349

______________


(a)	Level 1 assets and liabilities are described in Note 13.



	As of Dec. 31, 2012
	Level 1		Level 2		Level 3			Cash Collateral and Counterparty Netting			Total
Assets:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	378	$	—		$	—		$	378
Basis Swaps -- Oil	—		1,325		—			—			1,325
Options -- Gas	—		—		—			—			—
Basis Swaps -- Gas	—		2,000		—			—			2,000
Commodity derivatives —Utilities	—		—		43		^(b)	—			43
Cash equivalents ^(a)	15,462		—		—			—			15,462
Total	$	15,462	$	3,703	$	43		$	—		$	19,208

Liabilities:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	1,131	$	—		$	(336	)	$	795
Basis Swaps -- Oil	—		502		—			(450		)	52
Options -- Gas	—		—		—			—			—
Basis Swaps -- Gas	—		1,127		—			(620		)	507
Commodity derivatives — Utilities	—		10,162		—			(10,162		)	—
Interest rate swaps	—		118,088		—			(5,960		)	112,128
Total	$	—	$	131,010	$	—		$	(17,528	)	$	113,482

______________


(a)	Level 1 assets and liabilities are described in Note 13.

(b)

The significant unobservable inputs used in the fair value measurement of the long-term OTC contracts are based on the average of price quotes from an independent third party market participant and the OTC contract broker. The unobservable inputs are long-term natural gas prices. Significant changes to these inputs along with the contract term would impact the derivative asset/liability and regulatory asset/liability, but will not impact the results of operations until the contract is settled under the original terms of the contract. The contracts will be classified as Level 2 once settlement is within 60 months of maturity and quoted market prices from a market exchange are available.



	As of March 31, 2012
	Level 1		Level 2			Level 3			Cash Collateral and Counterparty Netting		Total
Assets:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	404		$	—		$	—	$	404
Basis Swaps -- Oil	—		48			—			—		48
Options -- Gas	—		—			—			—		—
Basis Swaps -- Gas	—		9,064			—			—		9,064
Commodity derivatives — Utilities	—		(8,412		)	3		^(b)	17,651		9,242
Cash equivalents ^(a)	55,919		—			—			—		55,919
Total	$	55,919	$	1,104		$	3		$	17,651	$	74,677

Liabilities:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	1,347		$	—		$	—	$	1,347
Basis Swaps -- Oil	—		2,641			—			—		2,641
Options -- Gas	—		—			—			—		—
Basis Swaps -- Gas	—		—			—			—		—
Commodity derivatives — Utilities	—		6,359			48		^(b)	—		6,407
Interest rate swaps	—		109,163			—			—		109,163
Total	$	—	$	119,510		$	48		$	—	$	119,558

______________


(a)	Level 1 assets and liabilities are described in Note 13.

(b)

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 and reflect 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 amounts do not include net cash collateral on deposit in margin accounts at March 31, 2013, Dec. 31, 2012, and March 31, 2012, 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 11.

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



As of March 31, 2013
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	832	$	—
Commodity derivatives	Derivative assets — non-current	206		—
Commodity derivatives	Derivative liabilities — current	—		3,110
Commodity derivatives	Derivative liabilities — non-current	—		1,114
Interest rate swaps	Derivative liabilities — current	—		6,982
Interest rate swaps	Derivative liabilities — non-current	—		15,237
Total derivatives designated as hedges		$	1,038	$	26,443

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	2,201	$	—
Commodity derivatives	Derivative assets — non-current	—		—
Commodity derivatives	Derivative liabilities — current	—		58
Commodity derivatives	Derivative liabilities — non-current	—		5,862
Interest rate swaps	Derivative liabilities — current	—		86,652
Interest rate swaps	Derivative liabilities — non-current	—		—
Total derivatives not designated as hedges		$	2,201	$	92,572



As of Dec. 31, 2012
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	2,874	$	—
Commodity derivatives	Derivative assets — non-current	510		—
Commodity derivatives	Derivative liabilities — current	—		1,993
Commodity derivatives	Derivative liabilities — non-current	—