Edgar Filing: BLACK HILLS CORP /SD/

BKH 093012 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 September 30, 2012
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 October 31, 2012

Common stock, $1.00 par value	44,180,030 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 and Nine Months Ended Sept. 30, 2012 and 2011	5

	Condensed Consolidated Statements of Comprehensive Income (Loss) - unaudited
	Three and Nine Months Ended Sept. 30, 2012 and 2011	6

	Condensed Consolidated Balance Sheets - unaudited
	Sept. 30, 2012, Dec. 31, 2011 and Sept. 30, 2011	7

	Condensed Consolidated Statements of Cash Flows - unaudited
	Nine Months Ended Sept. 30, 2012 and 2011	9

	Notes to Condensed Consolidated Financial Statements - unaudited	10

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	34

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	65

Item 4.	Controls and Procedures	69

PART II.	OTHER INFORMATION	70

Item 1.	Legal Proceedings	70

Item 1A.	Risk Factors	70

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	70

Item 4.	Mine Safety Disclosures	70

Item 5.	Other Information	70

Item 6.	Exhibits	71

	Signatures	72

	Exhibit Index	73

GLOSSARY OF TERMS AND ABBREVIATIONS

AND ACCOUNTING STANDARDS

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
AltaGas	AltaGas Renewable Energy Colorado, LLC
AOCI	Accumulated Other Comprehensive Income (Loss)
ARO	Asset Retirement Obligation
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
Bbl	Barrel
Bcf	Billion cubic feet
Bcfe	Billion cubic feet equivalent
BHC	Black Hills Corporation, the "Company"
BHEP	Black Hills Exploration and Production, Inc., representing our Oil and Gas segment, 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 activities of Black Hills Utility Holdings
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of the Company
Black Hills Power	Black Hills Power, Inc., a direct, wholly-owned subsidiary of the Company
Black Hills Service Company	Black Hills Service Company, a direct wholly-owned subsidiary of the Company
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of the Company
Black Hills Wyoming	Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
Btu	British thermal unit
CFTC	Commodity Futures Trading Commission
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of the Company
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, a direct wholly-owned subsidiary of Black Hills Electric Generation
CPCN	Certificate of Public Convenience and Necessity
CPUC	Colorado Public Utilities Commission
CT	Combustion Turbine
CVA	Credit Valuation Adjustment
CWIP	Construction Work-In-Progress
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)
ECA	Energy Cost Adjustment



Enserco	Enserco Energy Inc., representing our Energy Marketing segment, sold Feb. 29, 2012
Equity Forward Instrument	Equity Forward Agreement with J.P. Morgan connected to a public offering of 4,413,519 shares of Black Hills Corporation common stock
FASB	Financial Accounting Standards Board
FDIC	Federal Deposit Insurance Corporation
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles of the United States
Global Settlement	Settlement with the utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders
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	Internal Revenue Service
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	One thousand standard cubic feet
Mcfe	One thousand standard cubic feet equivalent. Natural gas liquid is converted by dividing gallons by 7. Crude oil is converted by multiplying barrels by 6.
MMBtu	One million British thermal units
MSHA	Mine Safety and Health Administration
MW	Megawatt
MWh	Megawatt-hour
Nebraska Gas	Black Hills Nebraska Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
NGL	Natural Gas Liquids
NPSC	Nebraska Public Service Commission
NYMEX	New York Mercantile Exchange
OTC	Over-the-counter
PGA	Purchase Gas Adjustment
PPA	Power Purchase Agreement
REPA	Renewable Energy Purchase Agreement
Revolving Credit Facility	Our $500 million five-year revolving credit facility which commenced on Feb. 1, 2012 and expires on Feb. 1, 2017
S&P	Standard and Poor's
SEC	United States Securities and Exchange Commission
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, representing our Coal Mining segment

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(unaudited)



	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
	2012			2011			2012			2011
	(in thousands, except per share amounts)
Revenue:
Utilities	$	214,716		$	223,714		$	766,317		$	834,463
Non-regulated energy	32,092			25,809			88,705			76,544
Total revenue	246,808			249,523			855,022			911,007

Operating expenses:
Utilities -
Fuel, purchased power and cost of gas sold	62,582			86,127			283,217			400,465
Operations and maintenance	59,398			58,313			183,721			184,411
Non-regulated energy operations and maintenance	22,466			22,813			65,774			69,438
Gain on sale of operating assets	(27,285		)	—			(27,285		)	—
Depreciation, depletion and amortization	41,408			33,278			121,398			97,434
Taxes - property, production and severance	10,213			9,161			31,201			24,598
Impairment of long-lived assets	—			—			26,868			—
Other operating expenses	216			259			1,679			562
Total operating expenses	168,998			209,951			686,573			776,908

Operating income	77,810			39,572			168,449			134,099

Other income (expense):
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums, discounts and realized settlements on interest rate swaps)	(27,475		)	(29,303		)	(85,151		)	(87,099		)
Allowance for funds used during construction - borrowed	1,127			3,520			2,608			9,874
Capitalized interest	175			2,981			467			8,198
Unrealized gain (loss) on interest rate swaps, net	605			(38,246		)	(2,902		)	(40,608		)
Interest income	364			536			1,428			1,547
Allowance for funds used during construction - equity	196			189			668			676
Other income (expense), net	(287		)	528			2,073			1,763
Total other income (expense)	(25,295		)	(59,795		)	(80,809		)	(105,649		)

Income (loss) before equity in earnings (loss) of unconsolidated subsidiaries and income taxes	52,515			(20,223		)	87,640			28,450
Equity in earnings (loss) of unconsolidated subsidiaries	22			43			(12		)	1,076
Income tax benefit (expense)	(17,914		)	9,017			(30,057		)	(7,915		)
Income (loss) from continuing operations	34,623			(11,163		)	57,571			21,611
Income (loss) from discontinued operations, net of tax	(166		)	638			(6,810		)	2,526
Net income (loss) available for common stock	$	34,457		$	(10,525	)	$	50,761		$	24,137

Income (loss) per share, Basic -
Income (loss) from continuing operations, per share	$	0.79		$	(0.29	)	$	1.31		$	0.55
Income (loss) from discontinued operations, per share	—			0.02			(0.16		)	0.07
Total income (loss) per share, Basic	$	0.79		$	(0.27	)	$	1.15		$	0.62
Income (loss) per share, Diluted -
Income (loss) from continuing operations, per share	$	0.78		$	(0.29	)	$	1.31		$	0.54
Income (loss) from discontinued operations, per share	—			0.02			(0.16		)	0.07
Total income (loss) per share, Diluted	$	0.78		$	(0.27	)	$	1.15		$	0.61
Weighted average common shares outstanding:
Basic	43,847			39,145			43,792			39,105
Diluted	44,108			39,145			44,026			39,792

Dividends paid per share of common stock	$	0.370		$	0.365		$	1.110		$	1.095

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 Sept. 30,						Nine Months Ended Sept. 30,
	2012			2011			2012			2011
	(in thousands)

Net income (loss) available for common stock	$	34,457		$	(10,525	)	$	50,761		$	24,137

Other comprehensive income (loss), net of tax:
Fair value adjustment of derivatives designated as cash flow hedges (net of tax of $1,204 and $(1,215) for the three months ended 2012 and 2011 and $1,092 and $653 for the nine months ended 2012 and 2011, respectively)	(3,591		)	1,922			(3,004		)	(991		)
Reclassification adjustments of cash flow hedges settled and included in net income (loss) (net of tax of $13 and $(129) for the three months ended 2012 and 2011 and $890 and $(985) for the nine months ended 2012 and 2011, respectively)	28			285			(1,333		)	1,907
Other comprehensive income (loss), net of tax	(3,563		)	2,207			(4,337		)	916

Comprehensive income (loss)	$	30,894		$	(8,318	)	$	46,424		$	25,053

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)



	Sept. 30, 2012			Dec. 31, 2011			Sept. 30, 2011
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	247,192		$	21,628		$	30,198
Restricted cash and equivalents	7,302			9,254			4,080
Accounts receivable, net	104,482			156,774			102,673
Materials, supplies and fuel	80,900			84,064			84,607
Derivative assets, current	16,063			18,583			12,177
Income tax receivable, net	11,869			9,344			4,728
Deferred income tax assets, net, current	33,681			37,202			37,931
Regulatory assets, current	24,606			59,955			45,713
Other current assets	44,823			21,266			25,269
Assets of discontinued operations	—			340,851			332,503
Total current assets	570,918			758,921			679,879

Investments	16,273			17,261			17,338

Property, plant and equipment	3,950,222			3,724,016			3,656,762
Less accumulated depreciation and depletion	(1,253,808		)	(934,441		)	(931,299		)
Total property, plant and equipment, net	2,696,414			2,789,575			2,725,463

Other assets:
Goodwill	353,396			353,396			353,396
Intangible assets, net	3,675			3,843			3,899
Derivative assets, non-current	1,167			1,971			3,246
Regulatory assets, non-current	191,935			182,175			142,267
Other assets, non-current	19,850			19,941			20,081
Total other assets	570,023			561,326			522,889

TOTAL ASSETS	$	3,853,628		$	4,127,083		$	3,945,569

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)



	Sept. 30, 2012			December 31, 2011			Sept. 30, 2011
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	69,138		$	104,748		$	91,628
Accrued liabilities	179,284			151,319			161,650
Derivative liabilities, current	86,509			84,367			101,312
Regulatory liabilities, current	10,705			16,231			10,568
Notes payable	225,000			345,000			359,000
Current maturities of long-term debt	328,310			2,473			2,893
Liabilities of discontinued operations	—			173,929			171,685
Total current liabilities	898,946			878,067			898,736

Long-term debt, net of current maturities	942,950			1,280,409			1,282,194

Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	338,194			300,988			317,864
Derivative liabilities, non-current	41,410			49,033			22,475
Regulatory liabilities, non-current	120,491			108,217			85,074
Benefit plan liabilities	167,690			177,480			124,214
Other deferred credits and other liabilities	129,630			123,553			127,007
Total deferred credits and other liabilities	797,415			759,271			676,634

Commitments and contingencies (See Notes 6, 7, 9, 11, 12 and 14)

Stockholders' equity:
Common stock —
Common stock $1 par value: 100,000,000 shares authorized: issued 44,250,588; 43,957,502 and 39,491,616 shares, respectively	44,251			43,958			39,492
Additional paid-in capital	731,176			722,623			604,945
Retained earnings	478,459			476,603			467,043
Treasury stock at cost – 75,420; 32,766 and 28,041 shares, respectively	(2,354		)	(970		)	(810		)
Accumulated other comprehensive income (loss)	(37,215		)	(32,878		)	(22,665		)
Total stockholders' equity	1,214,317			1,209,336			1,088,005

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	3,853,628		$	4,127,083		$	3,945,569

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



	Nine Months Ended Sept. 30,
	2012			2011
Operating activities:	(unaudited, in thousands)
Net income (loss) available to common stock	$	50,761		$	24,137
(Income) loss from discontinued operations, net of tax	6,810			(2,526		)
Income (loss) from continuing operations	57,571			21,611
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities:
Depreciation, depletion and amortization	121,398			97,434
Deferred financing cost amortization	5,301			5,040
Impairment of long-lived assets	26,868			—
Derivative fair value adjustments	(3,522		)	(2,305		)
Gain on sale of operating assets	(27,285		)	—
Stock compensation	5,974			4,840
Unrealized mark-to-market (gain) loss on interest rate swaps	2,902			40,608
Deferred income taxes	28,718			20,854
Allowance for funds used during construction - equity	(668		)	(676		)
Employee benefit plans	15,737			10,930
Other adjustments, net	3,505			3,177
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	3,085			(21,692		)
Accounts receivable, unbilled revenues and other current assets	43,447			50,649
Accounts payable and other current liabilities	(22,042		)	(51,846		)
Regulatory assets	15,544			22,357
Regulatory liabilities	(1,983		)	5,041
Contributions to defined benefit pension plans	(25,000		)	(11,050		)
Other operating activities, net	(1,067		)	(1,755		)
Net cash provided by operating activities of continuing operations	248,483			193,217
Net cash provided by (used in) operating activities of discontinued operations	21,184			13,309
Net cash provided by operating activities	269,667			206,526

Investing activities:
Property, plant and equipment additions	(261,414		)	(326,543		)
Proceeds from sale of assets	268,482			583
Investment in notes receivable	(21,832		)	—
Other investing activities	5,057			1,051
Net cash provided by (used in) investing activities of continuing operations	(9,707		)	(324,909		)
Proceeds from sale of discontinued business operations	108,837			—
Net cash provided by (used in) investing activities of discontinued operations	(824		)	(1,953		)
Net cash provided by (used in) investing activities	98,306			(326,862		)

Financing activities:
Dividends paid on common stock	(48,904		)	(43,169		)
Common stock issued	3,835			2,199
Short-term borrowings - issuances	62,453			770,000
Short-term borrowings - repayments	(182,453		)	(560,000		)
Long-term debt - repayments	(11,647		)	(6,169		)
Other financing activities	(2,833		)	(28		)
Net cash provided by (used in) financing activities of continuing operations	(179,549		)	162,833
Net cash provided by (used in) financing activities of discontinued operations	—			(157		)
Net cash provided by (used in) financing activities	(179,549		)	162,676
Net change in cash and cash equivalents	188,424			42,340
Cash and cash equivalents, beginning of period*	58,768			32,438
Cash and cash equivalents, end of period*	$	247,192		$	74,778

_______________________


*	Includes cash of discontinued operations of $37.1 million, $44.6 million and $16.0 million at Dec. 31, 2011, Sept. 30, 2011 and Dec. 31, 2010, respectively.

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 2011 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 2011 Annual Report on Form 10-K filed with the SEC.

Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying Condensed Consolidated Financial Statements reflects all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the Sept. 30, 2012, December 31, 2011 and Sept. 30, 2011 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 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 and nine months ended Sept. 30, 2012 and Sept. 30, 2011, and our financial condition as of Sept. 30, 2012, December 31, 2011, and Sept. 30, 2011 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. For comparative purposes, all prior periods presented have been restated to reflect the classification of this segment as discontinued operations. For further information see Note 17.

Certain prior year data presented in the financial statements has been reclassified to conform to the current year presentation. Specifically, the Company has reclassified deferred financing cost amortization into a separate line on the Condensed Consolidated Statements of Cash Flows. This reclassification had no effect on total assets, net income, cash flows or earnings per share.

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

Recently Adopted Accounting Standards and Legislation

Other Comprehensive Income: Presentation of Comprehensive Income, ASU 2011-05 and ASU 2011-12

FASB issued an accounting standards update amending accounting guidance for Comprehensive Income to improve the comparability, consistency and transparency of reporting of comprehensive income. The update amends existing guidance by allowing only two options for presenting the components of net income and other comprehensive income: (1) in a single continuous financial statement, statement of comprehensive income or (2) in two separate but consecutive financial statements, consisting of an income statement followed by a separate statement of other comprehensive income. Also, items that are reclassified from other comprehensive income to net income must be presented on the face of the financial statements. ASU 2011-05 requires retrospective application, and is effective for the fiscal years, and interim periods within those years beginning after Dec. 15, 2011. In December 2011, FASB issued ASU 2011-12, which indefinitely deferred the provisions of ASU 2011-05 requiring the presentation of reclassification adjustments on the face of the financial statements for items reclassified from other comprehensive income to net income.

At Dec. 31, 2011, we elected to early adopt the provisions of ASU 2011-05 as amended by ASU 2011-12. The adoption changed our presentation of certain financial statements, but did not have any other impact on our financial statements.

Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements, ASU 2011-04

In May 2011, FASB issued an accounting standards update amending accounting guidance for Fair Value Measurements and Disclosures to achieve common fair value measurement and disclosure requirements between GAAP and IFRS. Additional disclosure requirements in the update include: (1) for Level 3 fair value measurements - quantitative information about unobservable inputs used, a description of the valuation processes used by the entity, and a qualitative discussion about the sensitivity of the measurements to changes in the unobservable inputs; (2) for an entity's use of a non-financial asset that is different from the asset's highest and best use - the reason for the difference; (3) for financial instruments not measured at fair value but for which disclosure of fair value is required - the fair value hierarchy level in which the fair value measurements were determined; and (4) the disclosure of all transfers between Level 1 and Level 2 of the fair value hierarchy. ASU 2011-04 is effective for fiscal years, and interim periods within those years, beginning after Dec. 31, 2011. The amendment required additional details in notes to financial statements, but did not have any other impact on our financial statements. Additional disclosures are included in Notes 12 and 13.

Intangibles - Goodwill and Other: Testing Goodwill for Impairment, ASU 2011-08

In September 2011, the FASB issued an amendment to accounting guidance to Intangibles - Goodwill and Other to provide an option to perform a qualitative assessment to determine whether further impairment testing of goodwill is necessary. Specifically, an entity has the option to first assess qualitative factors to determine whether it is necessary to perform the current two-step test. If an entity believes, as a result of its qualitative assessment, that it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount, the quantitative impairment test is required. Otherwise, no further testing is required. This standard is effective for annual and interim goodwill impairment testing performed for fiscal years beginning after Dec. 15, 2011. We perform our annual impairment testing in November of each year. The adoption of this standard will not have an impact on our financial statements.

Recently Issued Accounting Standards and Legislation

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

In December 2011, the FASB issued revised accounting guidance to amend accounting guidance for Balance Sheet related to the existing 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 will not have an impact on our financial position, results of operations or cash flows.

Intangible - Goodwill and Other: Testing Indefinite Lived Intangible Assets for Impairment, ASU 2012-02

In July 2012, the FASB issued an amendment to accounting guidance for Intangibles - Goodwill and Other to provide an option to perform a qualitative assessment to determine whether further impairment testing of indefinite lived intangible assets is necessary. This ASU aligns the impairment testing for intangible assets with that of goodwill as amended by ASU 2011-08. This guidance is effective for interim and annual periods beginning after Sept. 15, 2012, with early adoption permitted. The adoption of this standard will not have an impact on our financial statements.

Dodd-Frank Wall Street Reform and Consumer Protection Act, SEC Final Rule No. 34-67717 and No. 33-9338

In August 2012, the SEC approved a final rule implementing Section 1504 of Dodd-Frank. The rule requires issuers engaged in the commercial development of oil, natural gas or minerals to disclose cash payments made to a foreign government or the United States government. We are in the process of evaluating our reporting requirements. The adoption of this rule will not have an impact on our financial statements.

Additionally, in July 2012, the CFTC and SEC published final rules that define “swap,” “security-based swap” and other key terms and concepts that are critical to the implementation of the derivatives reforms required by Dodd-Frank. We are in the process of evaluating our reporting requirements. The adoption of this rule will not have an impact on our financial position, results of operations or cash flows.

(3) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION



	Nine Months Ended
	Sept. 30, 2012			Sept. 30, 2011
	(in thousands)
Non-cash investing activities from continuing operations—
Property, plant and equipment acquired with accounts payable and accrued liabilities	$	39,303		$	49,566
Capitalized assets associated with retirement obligations	$	3,806		$	—
Cash (paid) refunded during the period for continuing operations—
Interest (net of amounts capitalized)	$	(69,901	)	$	(60,934	)
Income taxes, net	$	425		$	11,939

(4) MATERIALS, SUPPLIES AND FUEL

The amounts of materials, supplies and fuel included in the accompanying Condensed Consolidated Balance Sheets, by major classification, were as follows (in thousands) as of:



	Sept. 30, 2012		Dec. 31, 2011		Sept. 30, 2011
Materials and supplies	$	43,847	$	40,838	$	37,327
Fuel - Electric Utilities	8,289		8,201		8,639
Natural gas in storage held for distribution	28,764		35,025		38,641
Total materials, supplies and fuel	$	80,900	$	84,064	$	84,607

(5) ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

Accounts receivable consists primarily of customer trade accounts. The Gas Utilities' accounts receivable balance fluctuates primarily due to seasonality. We maintain an allowance for doubtful accounts that reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowances by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect our ability to collect.

Following is a summary of receivables (in thousands) as of:



	Accounts		Unbilled		Less Allowance for			Accounts
Sept. 30, 2012	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	46,802	$	18,441	$	(603	)	$	64,640
Gas Utilities	18,198		9,480		(204		)	27,474
Oil and Gas	10,272		—		(105		)	10,167
Coal Mining	1,540		—		—			1,540
Power Generation	4		—		—			4
Corporate	657		—		—			657
Total	$	77,473	$	27,921	$	(912	)	$	104,482



	Accounts		Unbilled		Less Allowance for			Accounts
Dec. 31, 2011	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	42,773	$	21,151	$	(545	)	$	63,379
Gas Utilities	39,353		38,992		(1,011		)	77,334
Oil and Gas	11,282		—		(105		)	11,177
Coal Mining	4,056		—		—			4,056
Power Generation	282		—		—			282
Corporate	546		—		—			546
Total	$	98,292	$	60,143	$	(1,661	)	$	156,774



	Accounts		Unbilled		Less Allowance for			Accounts
Sept. 30, 2011	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	41,889	$	16,401	$	(590	)	$	57,700
Gas Utilities	21,168		12,518		(789		)	32,897
Oil and Gas	8,820		—		(161		)	8,659
Coal Mining	1,845		—		—			1,845
Power Generation	119		—		—			119
Corporate	1,453		—		—			1,453
Total	$	75,294	$	28,919	$	(1,540	)	$	102,673

(6) NOTES PAYABLE

Our credit facility and debt securities contain certain restrictive financial covenants. We were in compliance with all of these covenants at Sept. 30, 2012.

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



	Sept. 30, 2012				Dec. 31, 2011				Sept. 30, 2011
	Notes Payable		Letters of Credit		Notes Payable		Letters of Credit		Notes Payable		Letters of Credit
Revolving Credit Facility	$	75,000	$	36,300	$	195,000	$	43,700	$	209,000	$	42,355
Term Loan due June 2013 ^(a)	150,000		—		150,000		—		150,000		—
Total	$	225,000	$	36,300	$	345,000	$	43,700	$	359,000	$	42,355

______________

(a) In June 2012, this short-term loan was extended for one year. See discussion below.

Revolving Credit Facility

On Feb. 1, 2012, we entered into a new $500 million Revolving Credit Facility expiring Feb. 1, 2017. The facility contains an accordion feature allowing us, with the consent of the administrative agent, to increase the capacity of the facility to $750 million. The Revolving Credit Facility can be used for the issuance of letters of credit, to fund working capital needs and for other corporate purposes. Borrowings are available under a base rate option or a Eurodollar option. The cost of borrowings or letters of credit is determined based upon our credit ratings. At current credit ratings, the margins for base rate borrowings, Eurodollar borrowings and letters of credit were 0.50 percent, 1.50 percent and 1.50 percent, respectively, at Sept. 30, 2012. The facility contains a commitment fee that is charged on the unused amount of the Revolving Credit Facility. Based upon current credit ratings, the fee is 0.25 percent.

Deferred financing costs on the Revolving Credit Facility of $2.8 million are being amortized over the estimated useful life of the Revolving Credit Facility and are included in Interest expense on the accompanying Condensed Consolidated Statements of Income. Upon entering into the Revolving Credit Facility, $1.5 million of deferred financing costs relating to the previous credit facility were written off through Interest expense.

Term Loans

On June 24, 2012, we extended the term of the $150 million term loan to June 24, 2013. The cost of borrowing is based on 1.10 percent over LIBOR.

Debt Covenants

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



	As of
	Sept. 30, 2012			Covenant Requirement
Consolidated Net Worth	$	1,214,317		Greater than	$	909,511
Recourse Leverage Ratio	56.3		%	Less than	65.0		%

(7) LONG TERM DEBT

On May 15, 2012, Black Hills Power repaid its 4.8 percent Pollution Control Revenue Bonds in full for $6.5 million principal and interest. These bonds were originally due to mature on Oct. 1, 2014.

(8) EARNINGS PER SHARE

Basic Income (loss) per share from continuing operations is computed by dividing Income (loss) from continuing operations by the weighted-average number of common shares outstanding during the period. Diluted Income (loss) per share is computed by including all dilutive common shares potentially outstanding during a period.

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



	Three Months Ended Sept. 30,					Nine Months Ended Sept. 30,
	2012		2011			2012		2011

Income (loss) from continuing operations	$	34,623	$	(11,163	)	$	57,571	$	21,611

Weighted average shares - basic	43,847		39,145			43,792		39,105
Dilutive effect of:
Restricted stock	175		—			159		147
Stock options	12		—			14		16
Equity forward instruments	—		—			—		473
Other dilutive effects	74		—			61		51
Weighted average shares - diluted	44,108		39,145			44,026		39,792

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

Due to our net loss for the quarter ended Sept. 30, 2011, potentially dilutive securities, consisting of outstanding stock options, restricted common stock, restricted stock units, non-vested performance-based share awards and warrants, were excluded from the diluted loss per share calculation due to their anti-dilutive effect. In computing diluted net loss per share, 11,880 options to purchase shares of common stock, 159,873 vested and non-vested restricted stock shares, 31,408 warrants and other performance shares and 424,715 forward equity instruments were excluded from the computations for the three months ended Sept. 30, 2011.

In addition to these potentially dilutive shares excluded due to our net loss for third quarter of 2011, the following outstanding securities also were excluded in the computation of diluted Income (loss) per share from continuing operations as their inclusion would have been anti-dilutive (in thousands):



	Three Months Ended Sept. 30,		Nine Months Ended Sept. 30,
	2012	2011	2012	2011
Stock options	77	176	101	119
Restricted stock	61	20	53	17
Other stock	—	27	19	19
Anti-dilutive shares	138	223	173	155

(9) EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

We have three non-contributory defined benefit pension plans (Pension Plans). One covers certain eligible employees of Black Hills Service Company, Black Hills Power, WRDC and BHEP, one covers certain eligible employees of Cheyenne Light, and one covers certain eligible employees of Black Hills Energy. As of Jan. 1, 2012, all Pension Plans have been frozen to new employees and certain eligible employees who did not meet age and service based criteria at the time the Pension Plans were frozen. Additionally, effective Oct. 1, 2012, the Cheyenne Light Pension Plan was merged into the Black Hills Corporation Pension Plan. The Pension Plan benefits are based on years of service and compensation levels.

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



	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
	2012			2011			2012			2011
Service cost	$	1,431		$	1,355		$	4,291		$	4,066
Interest cost	3,688			3,732			11,062			11,196
Expected return on plan assets	(4,084		)	(4,239		)	(12,252		)	(12,717		)
Prior service cost	22			25			66			75
Net loss (gain)	2,408			1,135			7,224			3,405
Net periodic benefit cost	$	3,465		$	2,008		$	10,391		$	6,025

Non-pension Defined Benefit Postretirement Healthcare Plans

We sponsor the following retiree healthcare plans (Healthcare Plans): the Black Hills Corporation Postretirement Healthcare Plan, the Healthcare Plan for Retirees of Cheyenne Light, and the Black Hills Energy Postretirement Healthcare Plan. Employees who participate in the Healthcare Plans and who retire on or after meeting certain eligibility requirements are entitled to postretirement healthcare benefits.

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



	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
	2012			2011			2012			2011
Service cost	$	402		$	375		$	1,206		$	1,125
Interest cost	523			542			1,569			1,626
Expected return on plan assets	(19		)	(41		)	(57		)	(123		)
Prior service cost (benefit)	(125		)	(120		)	(375		)	(360		)
Net loss (gain)	222			169			666			507
Net periodic benefit cost	$	1,003		$	925		$	3,009		$	2,775

Supplemental Non-qualified Defined Benefit Plans

We have various supplemental retirement plans for key executives (Supplemental Plans). The Supplemental Plans are non-qualified defined benefit plans.

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



	Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
	2012		2011		2012		2011
Service cost	$	243	$	257	$	735	$	771
Interest cost	331		324		993		973
Prior service cost	1		1		3		3
Net loss (gain)	202		128		606		383
Net periodic benefit cost	$	777	$	710	$	2,337	$	2,130

Contributions

We anticipate that we will make contributions to the benefit plans during 2012 and 2013. Contributions to the Pension Plans will be made in cash, and contributions to the Healthcare Plans and the Supplemental Plans are expected to be made in the form of benefit payments. Contributions and anticipated contributions are as follows (in thousands):



	Contributions Made		Contributions Made		Additional
	Three Months Ended Sept. 30, 2012		Nine Months Ended Sept. 30, 2012		Contributions Anticipated for 2012		Contributions Anticipated for 2013
Defined Benefit Pension Plans	$	—	$	25,000	$	—	$	4,500
Non-pension Defined Benefit Postretirement Healthcare Plans	$	1,063	$	3,189	$	1,063	$	4,380
Supplemental Non-qualified Defined Benefit Plans	$	278	$	834	$	278	$	1,090

(10) BUSINESS SEGMENT INFORMATION

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.

On Feb. 29, 2012, we sold our Energy Marketing segment, Enserco, which resulted in this segment being classified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the classification of this segment 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 our Corporate segment. For further information see Note 17.

We conduct our operations through the following five reportable segments:

Utilities Group —


•	Electric Utilities, which supplies electric utility service to areas in South Dakota, Wyoming, Colorado and Montana and natural gas utility service to Cheyenne, Wyo. and vicinity; and


•	Gas Utilities, which supplies natural gas utility service to areas in Colorado, Iowa, Kansas and Nebraska.

Non-regulated Energy Group —


•	Oil and Gas, which acquires, explores for, develops and produces crude oil and natural gas interests located in the Rocky Mountain region and other states;


•	Power Generation, which produces and sells power and capacity to wholesale customers from power plants located in Wyoming and Colorado; and


•	Coal Mining, which engages in the mining and sale of coal from our mine near Gillette, Wyo.

Segment information follows the accounting policies described in Note 1 of the Notes to Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

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



Three Months Ended Sept. 30, 2012	External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	151,281	$	3,736		$	14,573
Gas	63,435		—			3
Non-regulated Energy:
Oil and Gas ^(a)	24,728		—			17,389
Power Generation	1,256		19,695			5,128
Coal Mining	6,108		8,567			1,690
Corporate ^(b)	—		—			(4,160		)
Intercompany eliminations	—		(31,998		)	—
Total	$	246,808	$	—		$	34,623



Three Months Ended Sept. 30, 2011	External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	151,063	$	2,653		$	15,790
Gas	72,651		—			572
Non-regulated Energy:
Oil and Gas	19,163		—			241
Power Generation	1,011		7,089			337
Coal Mining	9,184		8,651			555
Corporate ^(b)(c)	—		—			(28,307		)
Intercompany eliminations	—		(21,942		)	(351		)
Total	$	253,072	$	(3,549	)	$	(11,163	)



Nine Months Ended Sept. 30, 2012	External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	451,974	$	11,946		$	37,478
Gas	314,343		—			16,369
Non-regulated Energy:
Oil and Gas ^(a)(d)	66,994		—			(2,219		)
Power Generation	3,193		56,119			15,968
Coal Mining	18,518		24,273			3,924
Corporate ^(b)	—		—			(13,949		)
Intercompany eliminations	—		(92,338		)	—
Total	$	855,022	$	—		$	57,571



Nine Months Ended Sept. 30, 2011	External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	431,624	$	9,902		$	34,653
Gas	402,839		—			24,275
Non-regulated Energy:
Oil and Gas	55,907		—			(553		)
Power Generation	2,589		20,911			2,071
Coal Mining	23,064		25,806			(1,124		)
Corporate ^(b)(c)	—		—			(37,299		)
Intercompany eliminations	—		(61,635		)	(412		)
Total	$	916,023	$	(5,016	)	$	21,611

____________

Income Statement Notes:


(a)	Income (loss) from continuing operations includes a $17.7 million after-tax gain on the sale of the Williston Basin assets. See Note 15.

(b)

Income (loss) from continuing operations includes $0.4 million net after-tax non-cash mark-to-market gain and $1.9 million net after-tax non-cash mark-to-market loss on interest rate swaps for the three and nine months ended Sept. 30, 2012, respectively, and a $24.9 million and $26.4 million net after-tax non-cash mark-to-market loss on interest rate swaps for the three and nine months ended Sept. 30, 2011, respectively.


(c)	Certain indirect corporate costs and inter-segment interest expenses after-tax totaling $0.5 million for the three months ended Sept. 30, 2011 and $1.6 million and $1.5 million for the nine months ended Sept. 30, 2012 and 2011 were included in the Corporate segment in continuing operations and were not reclassified as discontinued operations. See Note 17 for further information.


(d)	Income (loss) from continuing operations includes a $17.3 million non-cash after-tax ceiling test impairment expense. See Note 16 for further information.



Total Assets (net of inter-company eliminations) as of:	Sept. 30, 2012		Dec. 31, 2011			Sept. 30, 2011
Utilities:
Electric^(a)	$	2,302,951	$	2,254,914		$	1,917,184
Gas	710,099		746,444			683,163
Non-regulated Energy:
Oil and Gas ^(b)	263,088		425,970			405,513
Power Generation^(a)	119,489		129,121			372,313
Coal Mining	90,444		88,704			94,908
Corporate	367,557		141,079		^(c)	139,985		^(c)
Discontinued operations	—		340,851		^(d)	332,503		^(d)
Total assets	$	3,853,628	$	4,127,083		$	3,945,569

____________


(a)	Upon commercial operation on Dec. 31, 2011 of the new generating facility constructed by Colorado IPP at our Pueblo Airport Generation site, the PPA under which energy and capacity is sold to Colorado Electric is accounted for as a capital lease. Therefore, commencing Dec. 31, 2011, assets previously recorded at Power Generation are now accounted for at Colorado Electric as a capital lease.


(b)	2012 includes a ceiling test impairment and the sale of the Williston Basin assets by our Oil and Gas segment. See Notes 15 and 16.


(c)	Assets of the Corporate segment were reclassified due to deferred taxes that were not classified as discontinued operations.


(d)	See Note 17 for further information relating to discontinued operations.

(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 2011 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, fuel procurement for certain of our gas-fired generation assets and variability in revenue due to changes in gas usage at our regulated and non-regulated segments; and


•	Interest rate risk associated with our variable rate credit facility, project financing floating rate debt and our derivative instruments.

Our exposure to these market risks is affected by a number of factors including the size, duration, and composition of our energy portfolio, the absolute and relative levels of interest rates and commodity prices, the volatility of these prices and rates, and the liquidity of the related interest rate and commodity markets.

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 investment grade rated companies, 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 Sept. 30, 2012, our credit exposure (exclusive of retail customers of the regulated utilities) was concentrated primarily among investment grade rated companies, cooperative utilities and federal agencies.

We actively manage our exposure to certain market and credit risks as described in Note 3 of the Notes to the Consolidated Financial Statements in our 2011 Annual Report on Form 10-K. Our derivative and hedging activities included in the accompanying Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Income are detailed below and in Note 12.

Oil and Gas Exploration and Production

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.

We hold a portfolio of swaps and options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on those OTC swaps and options. 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 are marked to fair value and are 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 Accumulated other comprehensive income (loss) and the ineffective portion, if any, is reported in Revenue.

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



	Sept. 30, 2012					Dec. 31, 2011					Sept. 30, 2011
	Crude Oil Swaps/ Options		Natural Gas Swaps			Crude Oil Swaps/ Options			Natural Gas Swaps		Crude Oil Swaps/ Options		Natural Gas Swaps
Notional ^(a)	537,000		7,455,250			528,000			5,406,250		414,000		4,957,250
Maximum terms in years ^(b)	1.00		1.00			1.25			1.75		1.00		0.25
Derivative assets, current	$	1,651	$	2,032		$	729		$	8,010	$	1,885	$	6,937
Derivative assets, non-current	$	494	$	39		$	771		$	1,148	$	2,529	$	717
Derivative liabilities, current	$	527	$	1,040		$	2,559		$	—	$	—	$	—
Derivative liabilities, non-current	$	414	$	141		$	811		$	7	$	—	$	7
Pre-tax accumulated other comprehensive income (loss)	$	428	$	(344	)	$	(1,928	)	$	9,152	$	4,257	$	7,647
Cash collateral included in Derivative liabilities	$	—	$	—		$	—		$	—	$	—	$	—
Cash collateral included in Other current assets	$	1,126	$	1,288		$	—		$	—	$	—	$	—
Expense included in Revenue ^(c)	$	350	$	54		$	58		$	—	$	157	$	—

____________


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


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


(c)	Represents the amortization of put premiums.

Based on Sept. 30, 2012 market prices, a $1.2 million gain would be reclassified from AOCI during the next 12 months. Estimated and actual realized gains or losses will change during future periods as market prices fluctuate.

Utilities

Our utility customers are exposed to the effect of volatile natural gas prices; therefore, as allowed or required by state utility commissions, we have entered into certain 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. Gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in accordance with accounting standards for regulated utility operations. Accordingly, the hedging activity is recognized in the Condensed Consolidated Statements of Income when the related costs are recovered through our rates or adjustment mechanisms.

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



	Sept. 30, 2012		Dec. 31, 2011		Sept. 30, 2011
	Notional (MMBtus)	Maximum Term (months)	Notional (MMBtus)	Maximum Term (months)	Notional (MMBtus)	Maximum Term (months)
Natural gas futures purchased	14,690,000	75	14,310,000	84	9,890,000	18
Natural gas options purchased	5,560,000	6	1,720,000	3	3,880,000	6
Natural gas basis swaps purchased	8,800,000	75	7,160,000	60	—	—

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



	Sept. 30, 2012		Dec. 31, 2011		Sept. 30, 2011
Derivative assets, current	$	12,380	$	9,844	$	3,355
Derivative assets, non-current	$	634	$	52	$	—
Derivative liabilities, non-current	$	4,527	$	7,156	$	1,360
Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities	$	9,318	$	17,556	$	11,813
Included in Derivatives:
Cash collateral receivable (payable)	$	15,740	$	19,416	$	12,058
Option premiums and commissions	$	2,065	$	880	$	1,750

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:



	Sept. 30, 2012						Dec. 31, 2011						Sept. 30, 2011
	Designated Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*
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	4.25			1.25			5.00			2.00			5.25			0.25
Derivative liabilities, current	$	7,028		$	77,914		$	6,513		$	75,295		$	6,724		$	94,588
Derivative liabilities, non-current	$	18,660		$	17,668		$	20,363		$	20,696		$	21,108		$	—
Pre-tax accumulated other comprehensive income (loss)	$	(25,688	)	$	—		$	(26,876	)	$	—		$	(27,832	)	$	—
Year-to Date pre-tax gain (loss)	$	—		$	(2,902	)	$	—		$	(42,010	)	$	—		$	(40,608	)
Cash collateral receivable (payable) included in derivative	$	—		$	3,310		$	—		$	—		$	—		$	—

_____________


*	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 million notional terminate in 6.25 years and de-designated swaps totaling $150 million notional terminate in 16.25 years.

Collateral requirements based on our corporate credit rating apply to $50 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 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.

Based on Sept. 30, 2012 market interest rates and balances related to our designated interest rate swaps, a loss of approximately $7.0 million would be 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

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The ASC on Fair Value Measurements and Disclosure Requirements establishes a hierarchy for grouping assets and liabilities, based on significance of inputs. For additional information see Notes 3 and 4 included in our 2011 Annual Report on Form 10-K filed with the SEC. 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.

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

Oil and Gas Segment:


•	The commodity option contracts for the 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 multiple third party sources and therefore support Level 2 disclosure.


•	The commodity basis swaps for the 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 the 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.

Corporate Segment:

•

The interest rate swaps are valued using the market valuation 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 Sept. 30, 2012
	Level 1		Level 2			Level 3			Counterparty Netting		Cash Collateral			Total
Assets:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	619		$	—		$	—	$	—		$	619
Basis Swaps -- Oil	—		1,526			—			—		—			1,526
Options -- Gas	—		—			—			—		—			—
Basis Swaps -- Gas	—		2,071			—			—		—			2,071
Commodity derivatives — Utilities	—		(2,760		)	34		^(b)	—		15,740			13,014
Cash and cash equivalents ^(a)	247,192		—			—			—		—			247,192
Total	$	247,192	$	1,456		$	34		$	—	$	15,740		$	264,422

Liabilities:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	885		$	—		$	—	$	—		$	885
Basis Swaps -- Oil	—		56			—			—		—			56
Options -- Gas	—		—			—			—		—			—
Basis Swaps -- Gas	—		1,181			—			—		—			1,181
Commodity derivatives — Utilities	—		4,527			—			—		—			4,527
Interest rate swaps	—		124,580			—			—		(3,310		)	121,270
Total	$	—	$	131,229		$	—		$	—	$	(3,310	)	$	127,919

______________


(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 Dec. 31, 2011
	Level 1		Level 2		Level 3			Counterparty Netting		Cash Collateral		Total
Assets:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	—	$	768	^(a)	$	5	$	—	$	773
Basis Swaps -- Oil	—		727		—