SM Energy Co - Quarter Report: 2012 September (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2012

Commission File Number 001-31539

SM ENERGY COMPANY

(Exact name of registrant as specified in its charter)



Delaware (State or other jurisdiction of incorporation or organization)		41-0518430 (I.R.S. Employer Identification No.)



1775 Sherman Street, Suite 1200, Denver, Colorado (Address of principal executive offices)		80203 (Zip Code)

(303) 861-8140

(Registrant’s telephone number, including area code)

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 þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ 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. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer þ		Accelerated filer o

Non-accelerated filer o (Do not check if a smaller reporting company)		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 þ

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

As of October 26, 2012, the registrant had 66,077,484 shares of common stock, $0.01 par value, outstanding.

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SM ENERGY COMPANY

INDEX



Part I.	FINANCIAL INFORMATION		PAGE

	Item 1.	Financial Statements (Unaudited)

		Condensed Consolidated Balance Sheets September 30, 2012, and December 31, 2011	3

		Condensed Consolidated Statements of Operations Three and Nine Months Ended September 30, 2012, and 2011	4

		Condensed Consolidated Statements of Comprehensive Income (Loss) Three and Nine Months Ended September 30, 2012, and 2011	5

		Condensed Consolidated Statements of Cash Flows Nine Months Ended September 30, 2012, and 2011	6

		Notes to Condensed Consolidated Financial Statements	8

	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	24

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk (included within the content of Item 2)	46

	Item 4.	Controls and Procedures	46

Part II.	OTHER INFORMATION

	Item 1.	Legal Proceedings	46

	Item 1A.	Risk Factors	47

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	48

	Item 6.	Exhibits	49

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(in thousands, except share amounts)



	September 30, 2012			December 31, 2011
ASSETS
Current assets:
Cash and cash equivalents	$	184		$	119,194
Accounts receivable	235,887			210,368
Refundable income taxes	3,242			5,581
Prepaid expenses and other	39,014			68,026
Derivative asset	41,865			55,813
Deferred income taxes	5,746			4,222
Total current assets	325,938			463,204

Property and equipment (successful efforts method), at cost:
Land	1,845			1,548
Proved oil and gas properties	5,197,761			4,378,987
Less - accumulated depletion, depreciation, and amortization	(2,190,507		)	(1,766,445		)
Unproved oil and gas properties	160,468			120,966
Wells in progress	264,634			273,428
Materials inventory, at lower of cost or market	12,718			16,537
Oil and gas properties held for sale net of accumulated depletion, depreciation and amortization of $15,446 in 2012 and $10,714 in 2011 (note 3)	19,503			246
Other property and equipment, net of accumulated depreciation of $22,075 in 2012 and $23,985 in 2011	135,376			71,369
Total property and equipment, net	3,601,798			3,096,636

Other noncurrent assets:
Derivative asset	22,383			31,062
Restricted cash	93,771			124,703
Other noncurrent assets	80,062			83,375
Total other noncurrent assets	196,216			239,140
Total Assets	$	4,123,952		$	3,798,980

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	474,573		$	456,999
Derivative liability	19,352			42,806
Other current liabilities	6,000			6,000
Total current liabilities	499,925			505,805

Noncurrent liabilities:
Long-term credit facility	228,000			—
3.50% Senior Convertible Notes, net of unamortized discount of $2,431 in 2011	—			285,069
6.625% Senior Notes Due 2019	350,000			350,000
6.50% Senior Notes Due 2021	350,000			350,000
6.50% Senior Notes Due 2023	400,000			—
Asset retirement obligation	90,788			87,167
Asset retirement obligation associated with oil and gas properties held for sale (note 3)	749			1,277
Net Profits Plan liability (note 11)	90,389			107,731
Deferred income taxes	573,577			568,263
Derivative liability	8,802			12,875
Other noncurrent liabilities	57,680			67,853
Total noncurrent liabilities	2,149,985			1,830,235

Commitments and contingencies (note 6)

Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued: 66,121,809 shares in 2012 and 64,145,482 shares in 2011; outstanding, net of treasury shares: 66,071,228 shares in 2012 and 64,064,415 shares in 2011	661			641
Additional paid-in capital	222,812			216,966
Treasury stock, at cost: 50,581 shares in 2012 and 81,067 shares in 2011	(1,221		)	(1,544		)
Retained earnings	1,257,534			1,251,157
Accumulated other comprehensive loss	(5,744		)	(4,280		)
Total stockholders' equity	1,474,042			1,462,940
Total Liabilities and Stockholders’ Equity	$	4,123,952		$	3,798,980

The accompanying notes are an integral part of these condensed consolidated financial statements.

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SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(in thousands, except per share amounts)



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2012			2011			2012			2011
Operating revenues and other income:
Oil, gas, and NGL production revenue	$	373,928		$	325,231		$	1,049,131		$	935,478
Realized hedge gain (loss) (note 10)	501			(6,843		)	2,338			(14,548		)
Gain (loss) on divestiture activity	(8,532		)	190,728			(31,246		)	245,662
Marketed gas system and other operating revenue	13,054			21,458			40,571			57,184
Total operating revenues and other income	378,951			530,574			1,060,794			1,223,776

Operating expenses:
Oil, gas, and NGL production expense	102,447			77,753			280,713			196,907
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	192,432			123,067			523,610			343,805
Exploration	25,417			11,272			66,031			33,587
Impairment of proved properties	—			48,525			38,523			48,525
Abandonment and impairment of unproved properties	447			—			11,296			4,316
General and administrative	32,171			29,787			91,443			82,958
Change in Net Profits Plan liability	798			(24,930		)	(17,342		)	(24,719		)
Unrealized and realized derivative (gain) loss (note 10)	55,856			(128,425		)	(40,040		)	(83,872		)
Marketed gas system and other operating expense	12,219			20,737			40,780			57,746
Total operating expenses	421,787			157,786			995,014			659,253

Income (loss) from operations	(42,836		)	372,788			65,780			564,523

Nonoperating income (expense):
Interest income	126			27			201			382
Interest expense	(18,362		)	(9,372		)	(45,352		)	(33,636		)

Income (loss) before income taxes	(61,072		)	363,443			20,629			531,269
Income tax benefit (expense)	22,736			(133,346		)	(7,740		)	(195,142		)

Net income (loss)	$	(38,336	)	$	230,097		$	12,889		$	336,127

Basic weighted-average common shares outstanding	65,745			63,904			64,815			63,665

Diluted weighted-average common shares outstanding	65,745			67,386			67,343			67,390

Basic net income (loss) per common share (note 9)	$	(0.58	)	$	3.60		$	0.20		$	5.28

Diluted net income (loss) per common share (note 9)	$	(0.58	)	$	3.41		$	0.19		$	4.99

Dividends per common share	$	0.05		$	0.05		$	0.10		$	0.10

The accompanying notes are an integral part of these condensed consolidated financial statements.

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SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

(in thousands)



	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2012			2011		2012			2011

Net income (loss)	$	(38,336	)	$	230,097	$	12,889		$	336,127

Other comprehensive income (loss), net of tax:
Reclassification to earnings	(315		)	4,271		(1,465		)	9,149
Pension liability adjustment	1			—		1			—
Total other comprehensive income (loss), net of tax	(314		)	4,271		(1,464		)	9,149

Total comprehensive income (loss)	$	(38,650	)	$	234,368	$	11,425		$	345,276

The accompanying notes are an integral part of these condensed consolidated financial statements.

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SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(in thousands)



	For the Nine Months Ended September 30,
	2012			2011
Cash flows from operating activities:
Net income	$	12,889		$	336,127
Adjustments to reconcile net income to net cash provided by operating activities:
(Gain) loss on divestiture activity	31,246			(245,662		)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	523,610			343,805
Exploratory dry hole expense	18,551			49
Impairment of proved properties	38,523			48,525
Abandonment and impairment of unproved properties	11,296			4,316
Stock-based compensation expense	21,731			19,550
Change in Net Profits Plan liability	(17,342		)	(24,719		)
Unrealized derivative gain	(7,237		)	(108,020		)
Amortization of debt discount and deferred financing costs	5,692			14,698
Deferred income taxes	7,305			164,251
Plugging and abandonment	(1,804		)	(2,935		)
Other	906			(5,952		)
Changes in current assets and liabilities:
Accounts receivable	(18,682		)	(20,787		)
Refundable income taxes	2,339			8,482
Prepaid expenses and other	(6,203		)	14,732
Accounts payable and accrued expenses	30,766			(41,558		)
Excess income tax benefit from the exercise of stock awards	—			(15,155		)
Net cash provided by operating activities	653,586			489,747

Cash flows from investing activities:
Net proceeds from sale of oil and gas properties	48,663			325,053
Capital expenditures	(1,126,755		)	(1,081,617		)
Acquisition of oil and gas properties	(5,604		)	—
Other	—			(340		)
Net cash used in investing activities	(1,083,696		)	(756,904		)

Cash flows from financing activities:
Proceeds from credit facility	1,234,500			115,500
Repayment of credit facility	(1,006,500		)	(163,500		)
Debt issuance costs related to credit facility	—			(8,719		)
Net proceeds from 6.625% Senior Notes Due 2019	—			341,122
Net proceeds from 6.50% Senior Notes Due 2023	392,223			—
Repayment of 3.50% Senior Convertible Notes	(287,500		)	—
Proceeds from sale of common stock	3,421			5,593
Dividends paid	(3,208		)	(3,181		)
Net share settlement from issuance of stock awards	(21,605		)	(9,967		)
Excess income tax benefit from the exercise of stock awards	—			15,155
Other	(231		)	—
Net cash provided by financing activities	311,100			292,003

Net change in cash and cash equivalents	(119,010		)	24,846
Cash and cash equivalents at beginning of period	119,194			5,077
Cash and cash equivalents at end of period	$	184		$	29,923

The accompanying notes are an integral part of these condensed consolidated financial statements.

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SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (Continued)

Supplemental schedule of additional cash flow information and non-cash investing and financing activities:



	For the Nine Months Ended September 30,
	2012			2011
	(in thousands)

Cash paid for interest	$	(41,413	)	$	(24,095	)

Net cash refunded for income taxes	$	1,583		$	2,346

Dividends of approximately $3.3 million have been declared by the Company's Board of Directors, but not paid, as of September 30, 2012. Dividends of approximately $3.2 million were declared by the Company's Board of Directors, but not paid, as of September 30, 2011.

As of September 30, 2012, and 2011, $213.6 million, and $271.5 million, respectively, are included as additions to oil and gas properties and accounts payable and accrued expenses. These oil and gas property additions are reflected in cash used in investing activities in the periods during which the payables are settled.

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SM ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 1 - The Company and Business

SM Energy Company (“SM Energy” or the “Company”) is an independent energy company engaged in the acquisition, exploration, development, and production of crude oil, natural gas, and natural gas liquids (also respectively referred to as “oil”, “gas”, and “NGLs” throughout this report) in onshore North America, with a current focus on oil and NGL-rich resource plays.

Note 2 - Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements of SM Energy have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and the instructions to Form 10-Q and Regulation S-X. They do not include all information and notes required by GAAP for complete financial statements. However, except as disclosed herein, there has been no material change in the information disclosed in the notes to consolidated financial statements included in SM Energy’s Annual Report on Form 10-K for the year ended December 31, 2011 (the “2011 Form 10-K”). In the opinion of management, all adjustments, consisting of normal recurring accruals that are considered necessary for a fair presentation of interim financial information, have been included. Operating results for the periods presented are not necessarily indicative of expected results for the full year. In connection with the preparation of its unaudited condensed consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of September 30, 2012, through the filing date of this report.

Other Significant Accounting Policies

The accounting policies followed by the Company are set forth in Note 1 to the Company’s consolidated financial statements in the 2011 Form 10-K, and are supplemented throughout the notes to the unaudited condensed consolidated financial statements in this report. It is suggested that these unaudited condensed consolidated financial statements be read in conjunction with the consolidated financial statements and notes included in the 2011 Form 10-K.

Recently Issued and Adopted Accounting Standards

On January 1, 2012, the Company adopted new fair value measurement authoritative accounting guidance issued by the Financial Accounting Standards Board (the “FASB”), that clarifies the application of fair value measurement and disclosure requirements and changing particular principles and requirements for measuring fair value. For each class of assets and liabilities not measured at fair value in the Company's financial statements but for which fair value is disclosed, this guidance requires the Company to disclose the nature, characteristics, and risks of the asset or liability and the level of the fair value hierarchy within which the fair value measurement is categorized. Please refer to Note 11 - Fair Value Measurements in which the changes to the Company's financial statements resulting from the new authoritative guidance are presented.

On January 1, 2012, the Company adopted new authoritative accounting guidance issued by the FASB stating an entity that reports items of other comprehensive income has the option to present the components of comprehensive income in either one continuous financial statement or two consecutive financial statements, including reclassification adjustments. Subsequent to the issuance of this authoritative guidance, the FASB issued additional authoritative accounting guidance that effectively deferred the requirement to present the reclassification adjustments on the face of the financial statements, as well as the requirement to present the individual components of other comprehensive income for interim periods. The adoption of this statement did not have a material impact on the Company. The Company has elected to present a separate statement of comprehensive income, including the individual components, titled condensed consolidated statements of comprehensive income (loss), as part of Item 1 to this report.

On September 30, 2012, the Company elected to early adopt new authoritative accounting guidance issued by the FASB, which provided that an entity that tests indefinite-lived intangible assets for impairment has the option to assess qualitative factors to determine whether it is more likely than not that an asset is impaired as a basis for determining whether a quantitative test is necessary. The adoption of this statement did not have a material impact on the Company's financial statements.

There are no new significant accounting standards applicable to the Company that have been issued but not yet adopted by the Company as of September 30, 2012.

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Note 3 - Assets Held for Sale

Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed and any excess carrying value over the fair value less costs to sell of the assets held for sale is expensed. Subsequent changes to the estimated fair value less the costs to sell will impact the measurement of assets held for sale for which fair value less costs to sell is determined to be less than the carrying value of the assets.

As of September 30, 2012, the accompanying condensed consolidated balance sheets (“accompanying balance sheets”) present $19.5 million of assets held for sale, net of accumulated depletion, depreciation, and amortization expense. A corresponding asset retirement obligation liability of $749,000 is separately presented. The assets held for sale include the Company’s Marcellus shale assets located in Pennsylvania and certain assets located in the Company’s Mid-Continent region, all of which were written down to their respective estimated fair values less costs to sell. This write down is reflected in the gain (loss) on divestiture activity line item in the accompanying condensed consolidated statements of operations (“accompanying statements of operations”). During the third quarter of 2012, the Company divested of assets that were located in its Rocky Mountain region that were classified as held for sale at June 30, 2012. The Company determined that neither these planned nor executed asset sales qualify for discontinued operations accounting under financial statement presentation authoritative guidance.

During the first nine months of 2012, the Company reclassified a portion of the assets previously held for sale to assets held and used, as the assets were no longer being actively marketed. The assets were measured at the lower of the carrying value of the assets before being classified as held for sale, adjusted for any depletion, depreciation, and amortization expense (“DD&A”) that would have been recognized had the assets been continuously held and used, or the fair value of the assets at the date they no longer met the criteria as held for sale. As a result of this measurement, the Company recognized $1.7 million of DD&A expense and a $33.2 million loss on unsuccessful sale of properties, which is included in the gain (loss) on divestiture activity line item in the accompanying statements of operations.

Note 4 - Income Taxes

Income tax expense for the three and nine months ended September 30, 2012, and 2011, differs from the amounts that would be provided by applying the statutory U.S. federal income tax rate to income (loss) before income taxes as a result of the estimated effect of percentage depletion, the effect of state income taxes, uncertain tax positions, valuation allowances, and other permanent differences. The quarterly rate can also be impacted by the proportion of income earned in the reported periods.

The provision for income taxes consists of the following:



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2012			2011			2012			2011
	(in thousands)
Current portion of income tax benefit (expense):
Federal	$	—		$	(20,699	)	$	—		$	(29,855	)
State	(174		)	(637		)	(435		)	(1,036		)
Deferred portion of income tax benefit (expense)	22,910			(112,010		)	(7,305		)	(164,251		)
Total income tax benefit (expense)	$	22,736		$	(133,346	)	$	(7,740	)	$	(195,142	)
Effective tax rate	37.2		%	36.7		%	37.5		%	36.7		%

On a year-to-date basis, a change in the Company’s effective tax rate between reported periods will generally reflect differences in its estimated highest marginal state tax rate due to changes in the composition of income from Company activities among state tax jurisdictions. Cumulative effects of state rate changes are reflected in the period legislation is enacted.

The Company and its subsidiaries file federal income tax returns and various state income tax returns. With certain exceptions, the Company is no longer subject to U.S. federal or state income tax examinations by these tax authorities for years before 2007. In the first quarter of 2011, the Company received a $5.5 million refund from its 2006 tax year as a result of a net operating loss carryback claim from the 2008 tax year. The Internal Revenue Service continues to review documentation provided by the Company for the 2007 and 2010 tax years as part of an audit initiated in the first quarter of 2012.

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In the third quarter of 2011, the Company completed a multi-year research and development tax credit study and recorded a cumulative discrete tax benefit. The Company’s 2011 research and development credit was calculated and recorded as a discrete tax benefit in the third quarter of 2012. As of the filing date of this report, federal tax law allowing for the calculation of credits from research and development activities has not been extended past December 31, 2011.

Note 5 - Long-Term Debt

The Company satisfied its obligations to exchange its outstanding $350.0 million 6.50% Senior Notes due 2021 (the “2021 Notes”) and its outstanding $350.0 million 6.625% Senior Notes due 2019 (the “2019 Notes”) for notes registered under the Securities Act of 1933, as amended (the “Securities Act”), on March 7, 2012, and on January 12, 2012, respectively. There are no subsidiary guarantors of these notes.

3.50% Senior Convertible Notes Due 2027

On April 2, 2012, the Company called for redemption all of its outstanding 3.50% Senior Convertible Notes due 2027 (the “3.50% Senior Convertible Notes”). The call for redemption resulted in holders of $281.3 million aggregate principal amount electing to convert their notes. The Company settled the principal amount of all converted 3.50% Senior Convertible Notes in cash and settled the excess conversion value by issuing 864,106 shares of its common stock. The Company redeemed the remaining $6.2 million of aggregate principal amount of notes that were not converted on the redemption date at par plus accrued interest in cash. The Company used funds borrowed under its credit facility to pay the cash portion of the settlement.

6.50% Senior Notes Due 2023

On June 29, 2012, the Company issued $400.0 million in aggregate principal amount of 6.50% Senior Notes due 2023 (the “2023 Notes”). The 2023 Notes were issued at par and mature on January 1, 2023. The Company received net proceeds of $392.2 million after deducting fees of $7.8 million, which are being amortized as deferred financing costs over the life of the 2023 Notes. The net proceeds were used to reduce the Company’s outstanding credit facility balance.

Prior to July 1, 2015, the Company may redeem, on one or more occasions, up to 35 percent of the aggregate principal amount of the 2023 Notes with the net cash proceeds of certain equity offerings at a redemption price of 106.5% of the principal amount thereof, plus accrued and unpaid interest. The Company may also redeem the 2023 Notes, in whole or in part, at any time prior to July 1, 2017, at a redemption price equal to 100 percent of the principal amount of the 2023 Notes to be redeemed, plus a specified make-whole premium and accrued and unpaid interest to the applicable redemption date.

On or after July 1, 2017, the Company may also redeem all or, from time to time, a portion of the 2023 Notes at the redemption prices set forth below, during the twelve-month period beginning on July 1 of each applicable year, expressed as a percentage of the principal amount redeemed, plus accrued and unpaid interest:



2017	103.250	%
2018	102.167	%
2019	101.083	%
2020 and thereafter	100.000	%

The 2023 Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt, and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the 2023 Notes. The Company is subject to certain covenants under the indenture governing the 2023 Notes that limit the Company’s ability to incur additional indebtedness, issue preferred stock, and make restricted payments, including dividends. However, the first $6.5 million of dividends paid each year are not restricted by this covenant. The Company was in compliance with all financial covenants under its 2023 Notes as of September 30, 2012, and through the filing date of this report.

Additionally, on June 29, 2012, the Company entered into a registration rights agreement that provides holders of the 2023 Notes certain registration rights under the Securities Act. The Company satisfied its obligations to exchange its outstanding $400.0 million 2023 Notes for notes registered under the Securities Act on October 30, 2012.

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Note 6 - Commitments and Contingencies

Commitments

There have been no material changes from the commitments disclosed in the notes to the Company’s consolidated financial statements included in the 2011 Form 10-K.

Contingencies

The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the results of such pending litigation and claims will not have a material effect on the results of operations, the financial position, or the cash flows of the Company.

The Company was a defendant in litigation wherein the plaintiffs claimed an aggregate overriding royalty interest of 7.46875 percent in production from approximately 22,000 of the Company’s net acres in the Eagle Ford shale play in South Texas. The plaintiffs sought to quiet title to their claimed overriding royalty interest and to recover unpaid overriding royalty interest proceeds allegedly due. The Company believes that the claimed overriding royalty interest has been terminated under the governing agreements and the applicable law, and has contested the plaintiffs’ claims. Both parties filed motions for summary judgment, and on February 8, 2011, the District Court in Webb County, Texas, issued an order granting plaintiffs’ motion for summary judgment and denying the Company’s motion for summary judgment. On September 30, 2011, the District Court entered final judgment for the plaintiffs and awarded then current damages of approximately $5.1 million, which included prejudgment interest. The District Court also awarded attorneys’ fees and costs to the plaintiffs. The Company appealed the District Court’s judgment and obtained a stay pending appeal that prevented the plaintiffs from executing on the judgment.

On May 23, 2012, the Fourth Court of Appeals for the State of Texas delivered its opinion in this case, which reversed the summary judgment granted to the plaintiffs by the District Court and rendered judgment that the plaintiffs take nothing. Accordingly, based on the judgment of the Fourth Court of Appeals, the plaintiffs are not entitled to their claimed aggregate 7.46875 percent overriding royalty interest, nor are they entitled to the claimed damages related to the overriding royalty interest, attorneys fees or costs. The plaintiffs have filed a petition with the Supreme Court of Texas requesting a review of the Fourth Court of Appeals judgment. In the event review is granted by the Supreme Court of Texas, the Company will continue to contest this litigation.

Note 7 - Compensation Plans

Cash Bonus Plan

During the first nine months of 2012 and 2011, the Company paid $24.0 million and $21.6 million for cash bonuses earned in the 2011 and 2010 performance years, respectively. The general and administrative expense and exploration expense line items in the accompanying statements of operations include $4.3 million and $3.8 million of accrued cash bonus plan expense for the three-month periods ended September 30, 2012, and 2011, respectively, and $13.6 million and $11.3 million for the nine-month periods ended September 30, 2012, and 2011, respectively, related to the respective performance year.

Restricted Stock Units Under the Equity Incentive Compensation Plan

The Company grants Restricted Stock Units (“RSUs”) as part of its long-term equity compensation program. Each RSU represents a right to one share of the Company’s common stock to be delivered upon settlement of the award at the end of the specified vesting period. Expense associated with RSUs is recognized as general and administrative expense and exploration expense over the vesting period of the award.

Total expense recorded for RSUs for the three-month periods ended September 30, 2012, and 2011, was $3.9 million and $1.6 million, respectively, and $6.5 million and $3.6 million for the nine-month periods ended September 30, 2012, and 2011, respectively. As of September 30, 2012, there was $17.5 million of total unrecognized compensation expense related to unvested RSU awards, which is being amortized through 2015.

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A summary of the status and activity of non-vested RSUs for the nine-month period ended September 30, 2012, is presented in the following table:



	RSUs		Weighted-Average Grant-Date Fair Value
Non-vested, at beginning of year	308,877		$	44.33
Granted	369,332		$	49.32
Vested	(160,991	)	$	32.02
Forfeited	(22,305	)	$	51.06
Non-vested, at end of quarter	494,913		$	51.75

During the first nine months of 2012, the Company granted 369,332 RSUs, with a fair value of $18.2 million, as part of its regular long-term equity compensation program. These RSUs will vest 1/3^rd on each of the next three anniversary dates of the grants. During the first nine months of 2012, the Company settled 160,989 RSUs that related to awards granted in previous years by issuing a net 111,452 shares of the Company’s common stock in accordance with the terms of the RSU awards. The remaining 49,537 shares were withheld to satisfy income and payroll tax withholding obligations that arose upon delivery of the shares underlying those RSUs.

Performance Stock Units Under the Equity Incentive Compensation Plan

The Company also grants Performance Stock Units as part of its long-term equity compensation program. Performance Stock Units are structurally the same as the previously granted Performance Share Awards (collectively known as “Performance Stock Units” or “PSUs”). The number of shares of the Company’s common stock issued to settle PSUs ranges from zero to two times the number of PSUs awarded and is determined based on the Company’s performance over a three-year measurement period. The performance criteria for the PSUs are based on a combination of the Company’s annualized total shareholder return (“TSR”) for the measurement period and the relative measure of the Company’s TSR compared with the annualized TSRs of a group of peer companies for the measurement period. Expense associated with PSUs is recognized as general and administrative expense and exploration expense over the vesting period of the award.

Total expense recorded for PSUs for the three-month periods ended September 30, 2012, and 2011, was $5.1 million and $5.9 million, respectively, and $13.2 million and $14.3 million for the nine-month periods ended September 30, 2012, and 2011, respectively. As of September 30, 2012, there was $25.2 million of total unrecognized compensation expense related to unvested PSUs to be amortized through 2015.

A summary of the status and activity of non-vested PSUs for the nine-month period ended September 30, 2012, is presented in the following table:



	PSUs⁽¹⁾		Weighted-Average Grant-Date Fair Value
Non-vested, at beginning of year	885,894		$	57.52
Granted	314,853		$	51.98
Vested	(473,750	)	$	43.96
Forfeited	(34,708	)	$	65.22
Non-vested, at end of quarter	692,289		$	63.90

_______________________________________


⁽¹⁾	The number of awards assumes a one multiplier. The final number of shares of common stock issued may vary depending on the three-year performance multiplier, which ranges from zero to two.

During the first nine months of 2012, the Company granted 314,853 PSUs, with a fair value of $16.4 million, as part of its regular long-term equity compensation program. These PSUs will vest 1/3^rdon each of the next three anniversary dates of the grant. During the first nine months of 2012, the Company settled 609,714 PSUs, that were granted in 2009, which earned a two times multiplier, by issuing a net 812,562 shares of the Company’s common stock in accordance with the terms of the PSU awards. There were 406,866 shares withheld to satisfy income and payroll tax withholding obligations in conjunction with the issuance of the shares.

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Stock Option Grants Under the Equity Incentive Compensation Plan

A summary of activity associated with the Company’s Stock Option Plan for the nine months ended September 30, 2012, is presented in the following table:



	Shares		Weighted- Average Exercise Price		Aggregate Intrinsic Value (in thousands)
Outstanding, at beginning of year	508,214		$	13.86	$	30,109
Exercised	(151,083	)	$	12.39	$	8,308
Forfeited	—		$	—
Outstanding, at end of quarter	357,131		$	14.48	$	14,155
Vested and exercisable, at end of quarter	357,131		$	14.48	$	14,155

As of September 30, 2012, there was no unrecognized compensation expense related to stock option awards.

Director Shares

During the nine months ended September 30, 2012, and 2011, the Company issued 30,486 and 21,568 shares, respectively, of its common stock from treasury to its non-employee directors, under the Company’s Equity Incentive Compensation Plan. The Company recorded $147,000 of compensation expense related to these awards for the three months ended September 30, 2012. There was no compensation expenses recorded for the three months ended September 30, 2011. The Company recorded $1.3 million and $1.0 million of compensation expense related to these awards for the nine months ended September 30, 2012, and 2011, respectively.

Employee Stock Purchase Plan

Under the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation, without accruing in excess of $25,000 in value from purchases for each calendar year. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on the first or last day of the purchase period. Shares issued under the ESPP have no minimum holding period requirement. The ESPP is intended to qualify under Section 423 of the Internal Revenue Code. The Company had 1.3 million shares available for issuance under the ESPP as of September 30, 2012. There were 37,124 and 22,373 shares issued under the ESPP during the first nine months of 2012 and 2011, respectively. The fair value of ESPP grants is measured at the date of grant using the Black-Scholes option-pricing model.

Net Profits Interest Bonus Plan

Cash payments made or accrued under the Company’s Net Profits Interest Bonus Plan (“Net Profits Plan”) that have been recorded as either general and administrative expense or exploration expense are presented in the table below:



	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2012		2011		2012		2011
	(in thousands)
General and administrative expense	$	4,083	$	4,229	$	12,177	$	14,820
Exploration expense	403		507		1,421		1,569
Total	$	4,486	$	4,736	$	13,598	$	16,389

Additionally, the Company accrued or made cash payments under the Net Profits Plan of $274,000 for the three-month period ended September 30, 2012, and $2.0 million and $6.3 million for the nine-month periods ended September 30, 2012, and 2011, respectively, as a result of divestiture proceeds. There were no cash payments made or accrued relating to divestiture proceeds for the three-month period ended September 30, 2011. These cash payments are accounted for as a reduction in the gain (loss) on divestiture activity in the accompanying statements of operations.

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The Company records changes in the present value of estimated future payments under the Net Profits Plan as a separate line item in the accompanying statements of operations. The change in the estimated liability is recorded as a non-cash expense or benefit in the current period. The amount recorded as an expense or benefit associated with the change in the estimated liability is not allocated to general and administrative expense or exploration expense because it is associated with the future net cash flows from oil and gas properties in the respective pools rather than results being realized through current period production. If the Company allocated the change in liability to these specific functional line items, based on the current allocation of actual distributions made by the Company, such expenses or benefits would predominately be allocated to general and administrative expense. The amount that would be allocated to exploration expense is minimal in comparison. Over time, less of the amount distributed relates to prospective exploration efforts as more of the amount distributed is paid to employees that have terminated employment and do not provide ongoing exploration support to the Company.

Note 8 - Pension Benefits

Pension Plans

The Company has a non-contributory pension plan covering substantially all employees who meet age and service requirements (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (the “Nonqualified Pension Plan”).

Components of Net Periodic Benefit Cost for Both Pension Plans

The following table presents the components of the net periodic benefit cost for both the Qualified Pension Plan and the Nonqualified Pension Plan:



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2012			2011			2012			2011
	(in thousands)
Service cost	$	1,232		$	950		$	3,697		$	2,850
Interest cost	345			296			1,034			888
Expected return on plan assets that reduces periodic pension costs	(286		)	(220		)	(858		)	(660		)
Amortization of prior service costs	4			—			13			—
Amortization of net actuarial loss	197			102			591			304
Net periodic benefit cost	$	1,492		$	1,128		$	4,477		$	3,382

Prior service costs are amortized on a straight-line basis over the average remaining service period of active participants. Gains and losses in excess of ten percent of the greater of the benefit obligation and the market-related value of assets are amortized over the average remaining service period of active participants.

Contributions

As of September 30, 2012, the Company met the requirement to contribute $5.4 million to its Qualified Pension Plan for the 2012 plan year.

Note 9 - Earnings per Share

Basic net income (loss) per common share is calculated by dividing net income (loss) available to common shareholders by the basic weighted-average common shares outstanding for the respective period. The Company’s earnings per share calculations reflect the impact of any repurchases of shares of common stock made by the Company.

Diluted net income per common share is calculated by dividing adjusted net income by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of in-the-money outstanding options, unvested RSUs, contingent PSUs, and shares into which the 3.50% Senior Convertible Notes were convertible. When there is a loss from from continuing operations, as was the case for the three months ended September 30, 2012, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of earnings per share.

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PSUs represent the right to receive, upon settlement of the PSUs after completion of the three-year performance period, a number of shares of the Company’s common stock that may range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period applicable to such PSUs. For additional discussion on PSUs, please refer to Note 7 - Compensation Plans under the heading Performance Stock Units Under the Equity Incentive Compensation Plan.

The Company called for redemption its 3.50% Senior Convertible Notes on April 2, 2012, and the majority of the holders of the outstanding 3.50% Senior Convertible Notes elected to convert their notes. The Company issued 864,106 common shares upon conversion and these shares were included in the calculation of basic weighted-average common shares outstanding for the three and nine months ended September 30, 2012. Please refer to Note 5 - Long-Term Debt for additional discussion. Prior to calling the notes for redemption, the Company’s 3.50% Senior Convertible Notes had a net-share settlement right giving the Company the option to irrevocably elect, by notice to the trustee under the indenture for the notes, to settle the Company’s obligation, in the event that holders of the notes elected to convert all or a portion of their notes, by delivering cash in an amount equal to each $1,000 principal amount of notes surrendered for conversion and, if applicable, at the Company’s option, shares of common stock or cash, or any combination of common stock and cash, for the amount of conversion value in excess of the principal amount. Prior to the settlement of the Company’s 3.50% Senior Convertible Notes, potentially dilutive shares associated with this conversion feature were accounted for using the treasury stock method when shares of the Company’s common stock traded at an average closing price that exceeded the $54.42 conversion price. Prior to conversion, shares of the Company’s common stock traded at an average closing price exceeding the conversion price, and were included on an adjusted weighted basis for the portion of the nine months ended September 30, 2012, for which they were outstanding. Shares of the Company’s common stock traded at an average closing price exceeding the conversion price for the three-month and nine-month periods ended September 30, 2011, making them dilutive for those periods.

The treasury stock method is used to measure the dilutive impact of unvested RSUs, contingent PSUs, in-the-money stock options, and 3.50% Senior Convertible Notes.

The following table sets forth the calculations of basic and diluted earnings per share:



	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2012			2011		2012		2011
	(in thousands, except per share amounts)
Net income (loss)	$	(38,336	)	$	230,097	$	12,889	$	336,127
Basic weighted-average common shares outstanding	65,745			63,904		64,815		63,665
Add: dilutive effect of stock options, unvested RSUs, and contingent PSUs	—			2,062		1,870		2,589
Add: dilutive effect of 3.50% Senior Convertible Notes	—			1,420		658		1,136
Diluted weighted-average common shares outstanding	65,745			67,386		67,343		67,390
Basic net income (loss) per common share	$	(0.58	)	$	3.60	$	0.20	$	5.28
Diluted net income (loss) per common share	$	(0.58	)	$	3.41	$	0.19	$	4.99

Note 10 - Derivative Financial Instruments

The Company has entered into various commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. The Company’s derivative contracts include swap and collar arrangements for oil, gas, and NGLs. As of September 30, 2012, and through the filing date of this report, the Company has commodity derivative contracts outstanding through the second quarter of 2015 for a total of 10.8 million Bbls of oil production, 79.3 million MMBtu of gas production, and 1.5 million Bbls of NGL production.

The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The fair value of the commodity derivative contracts was a net asset of $36.1 million and $31.2 million at September 30, 2012, and December 31, 2011, respectively.

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Discontinuance of Cash Flow Hedge Accounting

Prior to January 1, 2011, the Company designated its commodity derivative contracts as cash flow hedges, for which unrealized changes in fair value were recorded to accumulated other comprehensive income (loss) (“AOCIL”), to the extent the hedges were effective. As of January 1, 2011, the Company elected to de-designate all of its commodity derivative contracts that had been previously designated as cash flow hedges at December 31, 2010. As a result, subsequent to December 31, 2010, the Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any such amounts in AOCIL. The Company had no derivatives designated as cash flow hedges for the three-month and nine-month periods ended September 30, 2012, and 2011, and as such, no ineffectiveness was recognized in earnings for the respective periods.

As a result of discontinuing hedge accounting on January 1, 2011, such fair values at December 31, 2010, were frozen in AOCIL as of the de-designation date and are reclassified into earnings as the original derivative transactions settle. As of September 30, 2012, AOCIL included $315,000 of net unrealized losses, net of income tax, on commodity derivative contracts that had been previously designated as cash flow hedges, all of which will be reclassified into earnings from AOCIL during the next twelve months. Please refer to Note 11 - Fair Value Measurements for more information regarding the Company’s derivative instruments, including its valuation techniques.

The following table details the fair value of derivatives recorded in the accompanying balance sheets, by category:



	As of September 30, 2012
	Derivative Assets			Derivative Liabilities
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
	(in thousands)
Commodity Contracts	Current Assets	$	41,865	Current Liabilities	$	19,352
Commodity Contracts	Noncurrent Assets	22,383		Noncurrent Liabilities	8,802
Derivatives not designated as hedging instruments		$	64,248		$	28,154



	As of December 31, 2011
	Derivative Assets			Derivative Liabilities
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
	(in thousands)
Commodity Contracts	Current Assets	$	55,813	Current Liabilities	$	42,806
Commodity Contracts	Noncurrent Assets	31,062		Noncurrent Liabilities	12,875
Derivatives not designated as hedging instruments		$	86,875		$	55,681

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The following table summarizes the components of unrealized and realized derivative (gain) loss presented in the accompanying statements of operations:



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2012			2011			2012			2011
	(in thousands)
Cash settlement (gain) loss:
Oil contracts	$	2,472		$	1,058		$	13,142		$	18,421
Gas contracts	(9,031		)	(1,434		)	(40,495		)	(3,751		)
NGL contracts	(4,362		)	4,131			(5,450		)	9,478
Total cash settlement (gain) loss	$	(10,921	)	$	3,755		$	(32,803	)	$	24,148

Unrealized (gain) loss on change in fair value:
Oil contracts	$	30,667		$	(106,780	)	$	(32,616	)	$	(90,629	)
Gas contracts	28,231			(19,083		)	40,464			(21,504		)
NGL contracts	7,879			(6,317		)	(15,085		)	4,113
Total net unrealized (gain) loss on change in fair value	$	66,777		$	(132,180	)	$	(7,237	)	$	(108,020	)
Total unrealized and realized derivative (gain) loss	$	55,856		$	(128,425	)	$	(40,040	)	$	(83,872	)

The following table summarizes the effect of derivative instruments on AOCIL and the accompanying statements of operations (net of income tax):



		Location in Statements of Operations	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	Derivatives	Location in Statements of Operations	2012			2011		2012			2011
			(in thousands)
Amount reclassified from AOCIL	Commodity Contracts	Realized hedge gain (loss)	$	(315	)	$	4,271	$	(1,465	)	$	9,149

The Company realized a net hedge gain of $501,000 and a net hedge loss of $6.8 million for the three months ended September 30, 2012, and 2011, respectively, and a net hedge gain of $2.3 million and a net hedge loss of $14.5 million from its commodity derivative contracts for the nine months ended September 30, 2012, and 2011, respectively, shown net of income tax in the table above. Realized hedge gains and losses are comprised of settlements on commodity derivative contracts that were previously designated as cash flow hedges and are reported in the total operating revenues and other income section of the accompanying statements of operations.

Credit Related Contingent Features

As of September 30, 2012, and through the filing date of this report, all of the Company’s derivative counterparties were members of the Company’s credit facility syndicate. The Company’s obligations under its credit facility and derivative contracts are secured by liens on substantially all of the Company’s proved oil and gas properties.

Convertible Note Derivative Instruments

The contingent interest provision of the 3.50% Senior Convertible Notes was an embedded derivative instrument. The fair value of this derivative was determined to be immaterial as of December 31, 2011. The 3.50% Senior Convertible Notes were settled during the second quarter of 2012. Please refer to Note 5 - Long-Term Debt for additional discussion.

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Note 11 - Fair Value Measurements

The Company follows fair value measurement authoritative accounting guidance for all assets and liabilities measured at fair value. That authoritative accounting guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs:


•	Level 1 – quoted prices in active markets for identical assets or liabilities


•	Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable


•	Level 3 – significant inputs to the valuation model are unobservable

The following is a listing of the Company’s assets and liabilities that are measured at fair value and where they are classified within the fair value hierarchy as of September 30, 2012:



	Level 1		Level 2		Level 3
	(in thousands)
Assets:
Derivatives ⁽¹⁾	$	—	$	64,248	$	—
Proved oil and gas properties ⁽²⁾	$	—	$	—	$	2,057
Unproved oil and gas properties ⁽²⁾	$	—	$	—	$	9,225
Liabilities:
Derivatives ⁽¹⁾	$	—	$	28,154	$	—
Net Profits Plan ⁽¹⁾	$	—	$	—	$	90,389

⁽¹⁾ This represents a financial asset or liability that is measured at fair value on a recurring basis.

⁽²⁾ This represents a non-financial asset or liability that is measured at fair value on a nonrecurring basis.

The following is a listing of the Company’s assets and liabilities that are measured at fair value and where they were classified within the fair value hierarchy as of December 31, 2011:



	Level 1		Level 2		Level 3
	(in thousands)
Assets:
Derivatives ⁽¹⁾	$	—	$	86,875	$	—
Proved oil and gas properties ⁽²⁾	$	—	$	—	$	139,992
Unproved oil and gas properties ⁽²⁾	$	—	$	—	$	15,809
Liabilities:
Derivatives ⁽¹⁾	$	—	$	55,681	$	—
Net Profits Plan ⁽¹⁾	$	—	$	—	$	107,731

⁽¹⁾ This represents a financial asset or liability that is measured at fair value on a recurring basis.

⁽²⁾ This represents a non-financial asset or liability that is measured at fair value on a nonrecurring basis.

Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy.

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Derivatives

The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration the counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit-price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active.

Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may ask counterparties to post collateral if their ratings deteriorate. In some instances the Company will attempt to novate the trade to a more stable counterparty.

Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any liability position with a counterparty. This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk, taking into account the Company’s credit rating, current credit facility margins, and any change in such margins since the last measurement date. All of the Company’s derivative counterparties are members of the Company’s credit facility bank syndicate.

The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with accounting authoritative guidance and with other marketplace participants, the Company recognizes that third parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date.

Refer to Note 10 - Derivative Financial Instruments for more information regarding the Company’s derivative instruments.

Net Profits Plan

The Net Profits Plan is a standalone liability for which there is no available market price, principal market, or market participants. The inputs available for this instrument are unobservable and are therefore classified as Level 3 inputs. The Company employs the income approach, which converts expected future cash flow amounts to a single present value amount. This technique uses the estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk to calculate the fair value. There is a direct correlation between realized oil, gas, and NGL commodity prices driving net cash flows and the Net Profits Plan liability. Generally, higher commodity prices result in a larger Net Profits Plan liability and lower commodity prices result in a smaller Net Profits Plan liability.

The Company records the estimated fair value of the long-term liability for estimated future payments under the Net Profits Plan based on the discounted value of estimated future payments associated with each individual pool. The calculation of this liability is a significant management estimate. For those pools currently in payout, a discount rate of 12 percent is used to calculate this liability. A discount rate of 15 percent is used to calculate the liability for pools that have not reached payout. These rates are intended to represent the best estimate of the present value of expected future payments under the Net Profits Plan.

The Company’s estimate of its liability is highly dependent on commodity prices, cost assumptions, discount rates, and the overall market conditions, which are continually evaluated to consider the current market environment. The Net Profits Plan liability is determined using price assumptions of five one-year strip prices with the fifth year’s pricing then carried out indefinitely. The average price is adjusted for realized price differentials and to include the effects of the forecasted production covered by derivatives contracts in the relevant periods. The non-cash expense associated with this significant management estimate is highly volatile from period to period due to fluctuations that occur in the crude oil, gas, and NGL commodity markets.

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If the commodity prices used in the calculation changed by five percent, the liability recorded at September 30, 2012, would differ by approximately $8 million. A one percent increase or decrease in the discount rate would result in a change of approximately $4 million. Actual cash payments to be made to participants in future periods are dependent on realized actual production, realized commodity prices, and costs associated with the properties in each individual pool of the Net Profits Plan. Consequently, actual cash payments are inherently different from the amounts estimated.

No published market quotes exist on which to base the Company’s estimate of fair value of its Net Profits Plan liability. As such, the recorded fair value is based entirely on management estimates that are described within this footnote. While some inputs to the Company’s calculation of fair value on the Net Profits Plan’s future payments are from published sources, others, such as the discount rate and the expected future cash flows, are derived from the Company’s own calculations and estimates.

The following table reflects the activity for the Company's Net Profits Plan liability measured at fair value using Level 3 inputs:



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2012			2011			2012			2011
	(in thousands)
Beginning balance	$	89,591		$	133,419		$	107,731		$	135,850
Net increase (decrease) in liability ⁽¹⁾	5,558			(20,194		)	(1,753		)	(2,001		)
Net settlements ^(1)(2)(3)	(4,760		)	(4,736		)	(15,589		)	(25,360		)
Transfers in (out) of Level 3	—			—			—			—
Ending balance	$	90,389		$	108,489		$	90,389		$	108,489

_____________________ ___ __


⁽¹⁾	Net changes in the Company's Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the accompanying statements of operations.

⁽²⁾

Settlements represent cash payments made or accrued under the Net Profits Plan. The Company accrued or made cash payments under the Net Profits Plan relating to divestiture proceeds of $274,000 for the three months ended September 30, 2012, and $2.0 million and $6.3 million for the nine months ended September 30, 2012, and 2011, respectively. There were no cash payments made or accrued relating to divestiture proceeds for the three months ended September 30, 2011.

⁽³⁾

During the first quarter of 2011, the Company elected to settle several Net Profits Plan pools associated with the acquisition of Nance Petroleum Corporation in 1999, through an aggregate $2.6 million cash payment. As a result, the Company reduced its Net Profits Plan liability by that amount. There was no impact on the accompanying statements of operations for the three-month or nine-month periods ended September 30, 2012, or 2011, related to these settlements.

Long-term Debt

The 2019 Notes and 2021 Notes are valued using Level 1 inputs based on quoted secondary market trading prices. The estimated fair value of the 2019 Notes and the 2021 Notes as of September 30, 2012, was approximately $371 million and $370 million, respectively, and as of December 31, 2011, was approximately $359 million and $360 million, respectively.

The 2023 Notes are valued using Level 2 inputs based on bond valuation prices obtained from a third party source. The price is generated by qualitative algorithms that use direct market observations, such as recent sales, bid and ask prices from brokers, dealers, buy side firms, and other market inputs. The estimated fair value of these notes was approximately $422 million as of September 30, 2012. In accordance with the registration rights agreement discussed in Note 5 - Long-Term Debt, the Company exchanged its outstanding 2023 Notes for registered notes under the Securities Act on October 30, 2012. In future periods, the Company expects to value the notes using Level 1 inputs.

The estimated fair value of the 3.50% Senior Convertible Notes was approximately $394 million as of December 31, 2011. The estimated fair value of the embedded contingent interest derivative was immaterial as of December 31, 2011. The 3.50% Senior Convertible Notes were valued using Level 1 inputs, based on quoted secondary market trading prices. The 3.50% Senior Convertible Notes were settled during the second quarter of 2012. Please refer to Note 5 - Long-Term Debt for additional discussion.

There was no long-term debt measured at fair value on the accompanying balance sheets as of September 30, 2012, or December 31, 2011; all long-term debt is presented at historical value.

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Proved Oil and Gas Properties

Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future amounts to a single present value amount, to measure the fair value of proved properties through an application of discount rates and price forecasts selected by the Company’s management. The calculation of the discount rate is based on the best information available and was estimated to be 12 percent as of September 30, 2012, and December 31, 2011. Management believes that the discount rate is representative of current market conditions and takes into account estimates of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The prices for oil and gas are forecasted based on New York Mercantile Exchange (“NYMEX”) strip pricing, adjusted for basis differentials, for the first five years. The prices for NGLs are forecasted using Oil Price Information System Mont Belvieu (“OPIS”) pricing, adjusted for basis differentials, for as long as the market is actively trading, after which a flat terminal price is used for each commodity stream. Future operating costs are also adjusted as deemed appropriate for these estimates.

As a result of asset write-downs, proved oil and gas properties measured at fair value within the accompanying balance sheets were $2.1 million at September 30, 2012, and $140.0 million at December 31, 2011.

Unproved Oil and Gas Properties

Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. The Company uses a market approach, which takes into account the following significant assumptions: future development plans, risk weighted potential resource recovery, and estimated reserve values to measure the fair value of unproved properties.

As a result of asset write-downs, unproved oil and gas properties measured at fair value within the accompanying balance sheets were $9.2 million at September 30, 2012, and $15.8 million at December 31, 2011.

Materials Inventory

Materials inventory is valued at the lower of cost or market. The Company uses Level 2 inputs to measure the fair value of materials inventory, which is primarily comprised of tubular goods. The Company uses third party market quotes and compares the quotes to the book value of the materials inventory. If the book value exceeds the quoted market price, the Company reduces the book value to the market price. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing materials inventory. There were no materials inventories measured at fair value in the accompanying balance sheets at September 30, 2012, or December 31, 2011.

Asset Retirement Obligations

The income valuation technique is utilized by the Company to determine the fair value of the asset retirement obligation liability at the point of inception by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. There were no asset retirement obligations measured at fair value in the accompanying balance sheets at September 30, 2012, or December 31, 2011.

Note 12 - Acquisition and Development Agreement

In June 2011, the Company entered into an Acquisition and Development Agreement with Mitsui E&P Texas LP (“Mitsui”), an indirect subsidiary of Mitsui & Co., Ltd. (the “Acquisition and Development Agreement”). Pursuant to the Acquisition and Development Agreement, the Company agreed to transfer to Mitsui a 12.5 percent working interest in certain non-operated oil and gas assets representing approximately 39,000 net acres in Dimmit, LaSalle, Maverick, and Webb Counties, Texas. As consideration for the oil and gas interests transferred, Mitsui agreed to pay, or carry, 90 percent of certain drilling and completion costs attributable to the Company’s remaining interest in these assets following the closing of the transaction, until Mitsui has expended an aggregate $680.0 million on behalf of the Company. Based on the Company’s forecast of the operator’s drilling plans, it will take two to three more years to fully utilize the carry. The Acquisition and Development Agreement also provided for reimbursement of capital expenditures and other costs, net of revenues, paid by the Company that were attributable to the transferred interest during the period between the effective date and the closing date, which the parties agreed would be applied over the carry period to cover the Company’s remaining ten percent of drilling and completion costs for the affected acreage.

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As of September 30, 2012, the Company held $93.8 million of contractually restricted cash payments from Mitsui, which will be used solely for development operations and accordingly are classified as non-current assets in the accompanying balance sheets. The Company has recorded a corresponding liability equal to the restricted cash balance. The portion of the liability related to development operations expected to occur within the next year is recorded in accounts payable and accrued expenses within the accompanying balance sheets. The portion of the liability related to development operations expected to occur more than one year in the future is recorded in other noncurrent liabilities within the accompanying balance sheets as of September 30, 2012. There was no net impact on the accompanying condensed consolidated statements of cash flows as restricted cash was offset against the corresponding liability in investing activities. Of the $680.0 million carry amount, $201.3 million had been spent as of September 30, 2012.

Note 13 - Impairment of Proved and Unproved Properties

Proved Properties

For the nine months ended September 30, 2012, the Company recorded $38.5 million of proved property impairments on the Company's Haynesville shale assets, due to a decline in natural gas prices during the second quarter of 2012. For the nine months ended September 30, 2011, the Company recorded $48.5 million of proved property impairments on the Company's James Lime assets, due primarily to low natural gas prices.

Unproved Properties

For the nine months ended September 30, 2012, the Company recorded $11.3 million of abandonment and impairment of unproved properties related to acreage that the Company no longer intends to develop within its Rocky Mountain region. For the nine months ended September 30, 2011, the Company recorded $4.3 million of abandonment and impairment of unproved properties associated with lease expirations in its Mid-Continent region.

Note 14 - Suspended Well Costs

In the third quarter of 2012, the Company expensed $3.6 million of costs related to two exploratory wells that had been disclosed as suspended well costs being capitalized for more than one year at December 31, 2011.

The following table reflects the net changes in capitalized exploratory well costs for the nine-month period ended September 30, 2012. The table does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs during the period:



	For the Nine Months Ended September 30, 2012
	(in thousands)
Capitalized exploratory well costs, at beginning of year	$	18,600
Additions to capitalized exploratory well costs pending the determination of proved reserves	74,359
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves	(15,176		)
Capitalized exploratory well costs charged to expense	(18,540		)
Capitalized exploratory well costs, at end of quarter	$	59,243

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The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling:



	For the Nine Months Ended September 30, 2012
	(in thousands)
Exploratory well costs capitalized for one year or less	$	59,243
Exploratory well costs capitalized for more than one year	—
Ending balance at September 30, 2012	$	59,243
Number of projects with exploratory well costs that have been capitalized more than a year	—

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This discussion and analysis contains forward-looking statements. Refer to Cautionary Information about Forward-Looking Statements at the end of this item for an explanation of these types of statements.

Overview of the Company, Highlights, and Outlook

General Overview

We are an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in onshore North America. Our assets include leading positions in the Eagle Ford shale and Bakken/Three Forks resource plays, as well as meaningful positions in the Granite Wash, Haynesville, and Woodford shale resource plays, and in the Permian Basin. We have built a portfolio of onshore properties in the contiguous United States primarily through early entrance into existing and emerging resource plays. This portfolio is comprised of properties with established production and reserves, prospective drilling opportunities, and unconventional resource prospects. We believe our strategy provides for stable and predictable production and reserve growth.

Our principal business strategy is focused on the early capture of resource plays in order to create and then enhance value for our shareholders, while maintaining a strong balance sheet. We strive to leverage industry-leading exploration and leasehold acquisition teams to quickly acquire and test new resource play concepts at a reasonable cost. Once we have identified potential value through these efforts, our goal is to develop such potential through top-tier operational and project execution, and as appropriate, mitigate our risks by selectively divesting portions of certain assets. We continually examine our portfolio for opportunities to improve the quality of our asset base in order to maximize our returns and preserve our financial strength.

In the third quarter of 2012, we had the following financial and operational results:


•	Average daily production for the three months ended September 30, 2012, was 28.6 MBbls of oil, 340.3 MMcf of gas, and 18.0 MBbls of NGLs, for a record average equivalent production rate of 619.6 MMCFE per day, compared with 462.1 MMCFE per day for the same period in 2011. Please see additional discussion below under the caption Production Results.

•

Net loss for the three months ended September 30, 2012, was $38.3 million, or $0.58 loss per diluted share due largely to a meaningful unrealized and realized derivative loss recorded for the quarter. Net income for the three months ended September 30, 2011, was $230.1 million or $3.41 per diluted share. Please refer to the Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2012, and 2011 for additional discussion regarding the components of net income (loss).


•	Costs incurred for oil and gas producing activities for the three months ended September 30, 2012, were $443.1 million, compared with $440.3 million for the same period in 2011. Please see additional discussion below under the caption Costs Incurred in Oil and Gas Producing Activities.


•	EBITDAX, a non-GAAP financial measure, for the three months ended September 30, 2012, was $260.9 million, compared with $215.5 million for the same period in 2011. Please refer to the caption Non-GAAP Financial Measures below for additional discussion, including a reconciliation from GAAP net income (loss) to EBITDAX.

Oil, Gas, and NGL Prices

Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. We sell the majority of our gas under contracts using first-of-the-month index pricing, which means gas produced in a given month is sold at the first-of-the-month price regardless of the spot price on the day the gas is produced. For assets where high BTU gas is sold at the wellhead, we also receive additional value for the high energy content contained in the gas stream. Our NGL production is generally sold using contracts paying us a monthly average of the posted OPIS daily settlement prices, adjusted for processing, transportation, and location differentials. Our oil and condensate are sold using contracts paying us either the average of the NYMEX West Texas Intermediate (“WTI”) daily settlement price or the average of alternative posted prices for the periods in which the product is produced, adjusted for quality, transportation, and location differentials.

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The following table summarizes commodity price data for the second and third quarters of 2012, as well as the third quarter of 2011:



	For the Three Months Ended
	September 30, 2012		June 30, 2012		September 30, 2011
Crude Oil (per Bbl):
Average NYMEX price	$	92.16	$	93.30	$	89.51
Realized price	$	83.98	$	82.52	$	82.63

Natural Gas:
Average NYMEX price (per MMBtu)	$	2.88	$	2.28	$	4.12
Realized price (per Mcf)	$	3.05	$	2.34	$	4.52

Natural Gas Liquids (per Bbl):
Average OPIS price	$	40.19	$	43.71	$	61.85
Realized price	$	34.82	$	37.79	$	56.10

Note: Average OPIS prices per barrel of NGL, historical or strip, are based on a product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline for all periods presented.

We expect future prices for oil, gas, and NGLs to continue to be volatile. In addition to supply and demand fundamentals, as a global commodity, the price of oil will likely continue to be impacted by real or perceived geopolitical risks in oil producing regions of the world, particularly the Middle East. The relative strength of the U.S. dollar compared to other currencies could affect the price of oil. The supply of NGLs in the U.S. is expected to grow in the near term as a result of the number of industry participants targeting projects that produce these products. The pace of NGL production is growing faster than the capacity to process or consume NGLs, which will likely negatively impact pricing in the near term. The prices of several of the specific NGL products correlate to the price of oil and accordingly are likely to directionally follow that market. Gas prices have been under downward pressure for a long period of time due to market oversupply resulting from high levels of drilling activity and tepid economic growth, although gas prices have increased moderately in the third quarter of 2012. The 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs (same product mix as discussed under the table above) as of September 30, 2012, were $93.54 per Bbl of oil, $3.74 per MMBtu of gas, and $41.08 per Bbl of NGLs, respectively. Comparable prices as of October 26, 2012, were $88.38 per Bbl of oil, $3.83 per MMBtu of gas, and $43.02 per Bbl of NGLs, respectively.

While changes in quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location, and transportation differentials for these products. Consistent with all prior periods reported, our realized prices shown in the table above do not include the impact of cash settlements from derivative contracts.

Derivative Activity

We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our use of derivatives. The amount of our production covered by derivatives is driven by the amount of debt on our balance sheet and the level of capital commitments and long-term obligations we have in place. With our current derivative contracts, we believe we have established a base cash flow stream for our future operations and have partially reduced our exposure to volatility in commodity prices. Our use of costless collars for a portion of our derivatives allows us to participate in some of the upward movements in oil, gas, and NGL prices while also setting a price floor for a portion of our production. Please refer to Note 10 - Derivative Financial Instruments of Part I, Item 1 of this report for additional information regarding our oil, gas, and NGL derivatives, and the caption, Summary of Oil, Gas, and NGL Derivative Contracts in Place, below.

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The following table presents a reconciliation from our realized price to our adjusted price for the commodities indicated, including the effects of derivative cash settlements, for the second and third quarters of 2012, as well as the third quarter of 2011:



	For the Three Months Ended
	September 30, 2012			June 30, 2012			September 30, 2011
Crude Oil (per Bbl):
Realized price	$	83.98		$	82.52		$	82.63
Less the effects of derivative cash settlements	(1.83		)	(2.00		)	(7.61		)
Adjusted price, including the effects of derivative cash settlements	$	82.15		$	80.52		$	75.02

Natural Gas (per Mcf):
Realized price	$	3.05		$	2.34		$	4.52
Add the effects of derivative cash settlements	0.39			0.68			0.37
Adjusted price, including the effects of derivative cash settlements	$	3.44		$	3.02		$	4.89

Natural Gas Liquids (per Bbl):
Realized price	$	34.82		$	37.79		$	56.10
Add (less) the effects of derivative cash settlements	2.57			1.65			(6.39		)
Adjusted price, including the effects of derivative cash settlements	$	37.39		$	39.44		$	49.71

The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”) included provisions requiring over-the-counter derivative transactions to be executed through an exchange or centrally cleared. On July 10, 2012, the Commodities Futures Trading Commission (“CFTC”) and the SEC adopted final joint rules under Title VII of the Dodd-Frank Act, which define certain terms and determine what types of transactions will be subject to heightened scrutiny under the Dodd-Frank Act swap rules. The issuance of these final rules also triggers compliance dates for a number of other final Dodd-Frank Act rules, including new rules proposed by the CFTC governing margin requirements for uncleared swaps entered into by non-bank swap entities, and new rules proposed by U.S. banking regulators regarding margin requirements for uncleared swaps entered into by bank swap entities. The ultimate effect on our business of these new rules and any additional regulations is currently uncertain. Of particular concern to us is whether the provisions of the final rules and regulations will allow us to qualify as a non-financial, commercial end user exempt from the requirements to post margin in connection with commodity price risk management activities. Final rules and regulations on major provisions of the legislation, such as new margin requirements, are to be established through regulatory rulemaking. Although we cannot predict the ultimate outcome of these rulemakings, new rules and regulations in this area may result in increased costs and cash collateral requirements for the types of derivative instruments we use to manage our financial risks related to volatility in oil, gas, and NGL commodity prices.

Third Quarter 2012 Highlights

Operational Activities. We operated an average of 18 drilling rigs during the third quarter of 2012. The primary focus of our operated drilling activity this year has been on oil and NGL-rich gas projects. We also participated in non-operated drilling activity primarily in oil and NGL-rich plays.

In our Eagle Ford shale program in south Texas, we operated six drilling rigs throughout most of the third quarter of 2012. We released one of our rigs at the end of the quarter. We focused our drilling in areas with higher BTU gas content and condensate yields. We believe we have secured most of the requisite services, such as gas pipeline takeaway capacity and drilling and completion services, to support our current development plans. We will continue to explore additional arrangements to facilitate the continued growth of our operated program. During the quarter, additional tank batteries were installed into the third party operated Eagle Ford shale gathering system. In our non-operated Eagle Ford program, the operator had nine drilling rigs running during the third quarter of 2012. We expect the majority of our non-operated Eagle Ford drilling program to be funded over the next two to three years by our previously announced Acquisition and Development Agreement with Mitsui.

During the third quarter, we operated four drilling rigs in our Bakken/Three Forks program in the North Dakota portion of the Williston Basin focusing on our Gooseneck, Raven, and Bear Den prospects. In the southern portion of our Rocky Mountain region, we operated one rig testing various formations in the Powder River Basin of Wyoming as part of an exploration program.

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Effective January 1, 2012, we combined our ArkLaTex region into our Mid-Continent region, based in Tulsa, Oklahoma, for operational and reporting purposes. During the third quarter of 2012, we operated three drilling rigs in our Granite Wash program in western Oklahoma and the Texas Panhandle, focusing primarily on the Marmaton washes due to their higher oil and NGL contributions. Essentially all of our acreage position in this play is held by production. We completed our operated Haynesville shale program earlier in the year after reaching held by production status on substantially all of our acreage.

In our Permian region, we operated four drilling rigs during the third quarter of 2012. Two of the rigs were focused on testing the Mississippian limestone formation in the northeast Midland Basin, where we have approximately 68,000 net acres. The third rig was focused on the Bone Spring formation in New Mexico. Finally, the fourth rig operated in the Midland Basin focusing on testing the Leonard shale. We added approximately 10,300 net acres to our Permian Basin Texas acreage during the third quarter of 2012.

Production Results. The table below provides a regional breakdown of our third quarter 2012 production:



	South Texas & Gulf Coast		Mid-Continent		Permian		Rocky Mountain		Total ⁽¹⁾
Third quarter 2012 production:
Oil (MMBbl)	0.9		0.1		0.4		1.3		2.6
Gas (Bcf)	15.9		13.5		0.9		1.0		31.3
NGLs (MMBbl)	1.6		0.1		—		—		1.7
Equivalent (BCFE)	30.5		14.6		3.0		8.9		57.0
Avg. daily equivalents (MMCFE/d)	332.0		158.4		32.2		97.0		619.6
Relative percentage	54	%	25	%	5	%	16	%	100	%

_____________________________________________

⁽¹⁾ Totals may not add due to rounding.

For the third quarter of 2012, we had record production, which was driven by the development of our operated and non-operated Eagle Ford shale programs in our South Texas & Gulf Coast region. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2012, and 2011 for additional discussion on production.

Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows:



	For the Three Months Ended September 30, 2012
	(in millions)
Development costs	$	318.7
Facility costs	24.5
Exploration costs	54.4
Acquisitions:
Proved properties	0.3
Leasing activity	45.2
Total, including asset retirement obligations	$	443.1

The majority of costs incurred for oil and gas producing activities during 2012 were on the development of our Eagle Ford shale and Bakken/Three Forks programs. Please refer to Overview of Liquidity and Capital Resources below for additional discussion on how we expect to fund our capital program.

Credit Facility. The borrowing base under our credit facility was increased by our lenders to $1.55 billion from $1.4 billion during the third quarter. Please refer to Overview of Liquidity and Capital Resources below for additional discussion.

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First Nine Months 2012 Highlights

Production Results. The table below provides a regional breakdown of our first nine months of 2012 production:



	South Texas & Gulf Coast		Mid-Continent		Permian		Rocky Mountain		Total ⁽¹⁾
First nine months of 2012 production:
Oil (MMBbl)	2.3		0.3		1.0		3.9		7.5
Gas (Bcf)	41.6		40.8		2.4		3.3		88.1
NGLs (MMBbl)	3.9		0.3		—		—		4.2
Equivalent (BCFE)	78.8		44.2		8.3		27.0		158.3
Avg. daily equivalents (MMCFE/d)	287.7		161.2		30.0		98.7		577.6
Relative percentage	50	%	28	%	5	%	17	%	100	%

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⁽¹⁾ Totals may not add due to rounding.

Please refer to Third Quarter 2012 Highlights above and Comparison of Financial Results and Trends Between the Nine Months Ended September 30, 2012, and 2011 for additional discussion on production.



	For the Nine Months Ended September 30, 2012
	(in millions)
Development costs	$	917.2
Facility costs	47.7
Exploration costs	160.9
Acquisitions
Proved properties	5.6
Leasing activity	87.4
Total, including asset retirement obligations	$	1,218.8

Please refer to Third Quarter 2012 Highlights above for a discussion concerning our capital expenditures and Overview of Liquidity and Capital Resources below for additional discussion on how we expect to fund our capital program.

3.50% Senior Convertible Notes. During the first nine months of 2012, we called for the redemption of our outstanding 3.50% Senior Convertible Notes. We settled the principal amount of all converted 3.50% Senior Convertible Notes in cash with the excess value settled in shares of common stock. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.

2023 Notes. During the first nine months of 2012, we issued $400.0 million in aggregate principal amount of 2023 Notes. The notes were issued at par on June 29, 2012 and mature on January 1, 2023. We received net proceeds of $392.2 million from this issuance, which we used to pay down outstanding borrowings under our credit facility. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.

Impairment of Proved Properties. During the first nine months of 2012, we recorded an impairment of proved properties of $38.5 million related to our Haynesville shale assets due to low natural gas prices during the second quarter of 2012.

Unsuccessful Sale of Properties. During the first nine months of 2012, we reclassified assets located in our Rocky Mountain, Mid-Continent, and South Texas & Gulf Coast regions that were previously classified as held for sale to assets held and used, as these assets were no longer being actively marketed, which resulted in a $33.2 million non-cash loss. Please refer to Note 3 - Assets Held for Sale in Part I, Item 1 of this report for additional discussion.

Equity Compensation. During the first nine months of 2012, we granted 369,332 RSUs and 314,853 PSUs pursuant to our long-term equity compensation program. Additionally, we issued 924,014 shares of our common stock to settle PSU and RSU awards granted in previous years. Please refer to Note 7 - Compensation Plans in Part I, Item 1 of this report for additional discussion.

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Marketing of Properties. In the second quarter of 2012, we began to remarket our Marcellus shale assets located in Pennsylvania. Please refer to Note 3 - Assets Held for Sale in Part I, Item 1 of this report, as well as Legal Proceedings in Part II, Item 1 of this report for additional discussion.

Outlook for the Remainder of 2012

Our capital program for 2012 is expected to be approximately $1.5 billion, of which $1.1 billion to $1.2 billion will be focused on drilling and completion activities. Approximately 85 percent of our drilling and completion budget has been allocated to our operated properties, and over 95 percent of our allocated drilling and completion capital for 2012 is expected to be directed to oil and NGL-rich projects.

In our operated Eagle Ford shale program we operated six rigs during the third quarter, releasing one of our operated rigs at quarter end. Of the remaining five rigs running, three are drilling multi-well pads, while the remainder are drilling wells throughout our acreage position to satisfy leasehold obligations. Aside from the drilling necessary to satisfy leasehold obligations throughout our position, we expect to focus our drilling on the northern portion of our acreage position which has higher condensate and NGL yields. We continue to test our well design and acreage spacing assumptions, primarily in the Briscoe Ranch portion of our acreage, to determine the ultimate development spacing to optimize well performance and capital efficiency of our operated acreage.

In our non-operated Eagle Ford shale program, the operator ran nine drilling rigs and one spudder rig during the third quarter. Based on the operator’s stated plans, our expectation is that the number of its rigs will remain relatively constant throughout the remainder of the year. Mitsui is obligated to carry the majority of the drilling and completion costs of our non-operated drilling activity through 2012 and, as such, we expect to deploy minimal capital related to drilling and completion activities in this program. Costs that are not associated with drilling or completion activities, such as infrastructure construction, are not carried by Mitsui, and accordingly we will be responsible for our proportionate share of these costs.

For the remainder of the year, we expect to operate four drilling rigs in our operated Bakken/Three Forks program in the Williston Basin. Of these rigs, one will focus on Three Forks drilling in Divide County, North Dakota, while the other three rigs will target the Bakken formation in Williams and McKenzie Counties, North Dakota. As the majority of our acreage is held by production, the focus of drilling has shifted towards infill drilling where we have started drilling multi-well pads.

In our Granite Wash program, we plan to release one of the three rigs running during the third quarter, exiting the year with two operated rigs. These two rigs will focus on the liquids-rich Marmaton washes. Essentially all of our acreage in this program is held by production.

In our Permian program, we plan to keep our rig count constant at four for the remainder of the year, with two rigs delineating the Mississippian limestone play in the northern Midland Basin. One of the remaining rigs will focus on the horizontal Bone Spring program in the Delaware Basin, while the fourth rig will continue to test Leonard shale targets in the Midland Basin.

Please refer to Overview of Liquidity and Capital Resources for additional discussion regarding how we intend to fund our 2012 capital program.

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Financial Results of Operations and Additional Comparative Data

The table below provides information regarding selected production and financial information for the quarter ended September 30, 2012, and the immediately preceding three quarters. Additional details of per MCFE costs are presented later in this section.



	For the Three Months Ended
	September 30,			June 30,			March 31,		December 31,
	2012			2012			2012		2011
	(in millions, except for production data)
Production (BCFE)	57.0			50.6			50.7		51.3
Oil, gas, and NGL production revenue	$	373.9		$	312.6		$	362.6	$	397.0
Realized hedge gain (loss)	$	0.5		$	0.2		$	1.7	$	(6.2	)
Gain (loss) on divestiture activity	$	(8.5	)	$	(24.2	)	$	1.5	$	(25.0	)
Lease operating expense	$	46.5		$	46.1		$	39.4	$	43.5
Transportation costs	$	37.0		$	30.3		$	28.6	$	30.7
Production taxes	$	18.9		$	14.7		$	19.1	$	19.0
DD&A	$	192.4		$	161.6		$	169.6	$	167.3
Exploration	$	25.4		$	22.0		$	18.6	$	20.0
Impairment of proved properties	$	—		$	38.5		$	—	$	170.5
Abandonment and impairment of unproved properties	$	0.4		$	10.7		$	0.1	$	3.1
General and administrative	$	32.2		$	31.1		$	28.1	$	35.6
Change in Net Profits Plan liability	$	0.8		$	(22.1	)	$	3.9	$	(0.8	)
Unrealized and realized derivative (gain) loss	$	55.9		$	(98.1	)	$	2.2	$	46.8
Net income (loss)	$	(38.3	)	$	24.9		$	26.3	$	(120.7	)

Selected Performance Metrics:



	For the Three Months Ended
	September 30,			June 30,			March 31,			December 31,
	2012			2012			2012			2011
Average net daily production equivalent (MMCFE per day)	619.6			555.7			557.0			557.9
Lease operating expense (per MCFE)	$	0.82		$	0.91		$	0.78		$	0.85
Transportation costs (per MCFE)	$	0.65		$	0.60		$	0.56		$	0.60
Production taxes as a percent of oil, gas, and NGL production revenue	5.1		%	4.7		%	5.3		%	4.8		%
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per MCFE)	$	3.38		$	3.20		$	3.35		$	3.26
General and administrative (per MCFE)	$	0.56		$	0.62		$	0.56		$	0.69

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A three-month and nine-month overview of selected production and financial information, including trends:



	For the Three Months Ended September 30,						Amount Change Between Periods			Percent Change Between Periods		For the Nine Months Ended September 30,					Amount Change Between Periods			Percent Change Between Periods
	2012			2011			Amount Change Between Periods			Percent Change Between Periods		2012		2011			Amount Change Between Periods			Percent Change Between Periods
Net production volumes
Oil (MMBbl)	2.6			2.0			0.6			33	%	7.5		5.6			1.9			33	%
Gas (Bcf)	31.3			25.9			5.4			21	%	88.1		71.5			16.6			23	%
NGLs (MMBbl)	1.7			0.8			0.9			109	%	4.2		2.2			2.0			91	%
Equivalent (BCFE)	57.0			42.5			14.5			34	%	158.3		118.4			39.9			34	%
Average net daily production
Oil (MBbl per day)	28.6			21.5			7.0			33	%	27.4		20.6			6.8			33	%
Gas (MMcf per day)	340.3			281.2			59.1			21	%	321.5		262.0			59.6			23	%
NGLs (MBbl per day)	18.0			8.6			9.4			109	%	15.3		8.0			7.3			91	%
Equivalent (MMCFE per day)	619.6			462.1			157.5			34	%	577.6		433.7			143.9			33	%
Oil, gas, & NGL production revenue (in millions)
Oil production revenue	$	220.6		$	163.7		$	56.9		35	%	$	642.7	$	497.5		$	145.2		29	%
Gas production revenue	95.7			117.0			(21.3		)	(18	)%	244.6		322.2			(77.6		)	(24	)%
NGL production revenue	57.6			44.5			13.1			29	%	161.8		115.8			46.0			40	%
Total	$	373.9		$	325.2		$	48.7		15	%	$	1,049.1	$	935.5		$	113.6		12	%
Oil, gas, & NGL production expense (in millions)
Lease operating expense	$	46.5		$	40.1		$	6.4		16	%	$	132.1	$	106.3		$	25.8		24	%
Transportation costs	37.0			23.9			13.1			55	%	95.9		55.8			40.1			72	%
Production taxes	18.9			13.8			5.1			37	%	52.7		34.8			17.9			51	%
Total	$	102.4		$	77.8		$	24.6		32	%	$	280.7	$	196.9		$	83.8		43	%
Realized price
Oil (per Bbl)	$	83.98		$	82.63		$	1.35		2	%	$	85.76	$	88.54		$	(2.78	)	(3	)%
Gas (per Mcf)	$	3.05		$	4.52		$	(1.47	)	(33	)%	$	2.78	$	4.51		$	(1.73	)	(38	)%
NGLs (per Bbl)	$	34.82		$	56.10		$	(21.28	)	(38	)%	$	38.53	$	52.71		$	(14.18	)	(27	)%
Per MCFE	$	6.56		$	7.65		$	(1.09	)	(14	)%	$	6.63	$	7.90		$	(1.27	)	(16	)%
Per MCFE Data
Production costs:
Lease operating expenses	$	0.82		$	0.94		$	(0.12	)	(13	)%	$	0.83	$	0.90		$	(0.07	)	(8	)%
Transportation costs	$	0.65		$	0.56		$	0.09		16	%	$	0.61	$	0.47		$	0.14		30	%
Production taxes	$	0.33		$	0.33		$	—		—	%	$	0.33	$	0.29		$	0.04		14	%
General and administrative	$	0.56		$	0.70		$	(0.14	)	(20	)%	$	0.58	$	0.70		$	(0.12	)	(17	)%
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	3.38		$	2.89		$	0.49		17	%	$	3.31	$	2.90		$	0.41		14	%
Derivative cash settlement ⁽¹⁾	$	0.20		$	(0.25	)	$	0.45		(180	)%	$	0.22	$	(0.33	)	$	0.55		(167	)%

Earnings per share information
Basic net income (loss) per common share	$	(0.58	)	$	3.60		$	(4.18	)	(116	)%	$	0.20	$	5.28		$	(5.08	)	(96	)%
Diluted net income (loss) per common share	$	(0.58	)	$	3.41		$	(3.99	)	(117	)%	$	0.19	$	4.99		$	(4.80	)	(96	)%
Basic weighted-average common shares outstanding	65,745			63,904			1,841			3	%	64,815		63,665			1,150			2	%
Diluted weighted-average common shares outstanding	65,745			67,386			(1,641)			(2	)%	67,343		67,390			(47		)	—	%

⁽¹⁾ Derivative cash settlements are included within the realized hedge gain (loss) and unrealized and realized derivative (gain) loss line items in the accompanying statements of operations.

We present per MCFE information because we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis. Average daily reported production for the three and nine months ended September 30, 2012, increased 34 percent and 33 percent, respectively, compared with the same periods in 2011, driven primarily by the development of our Eagle Ford shale program, as well as a substantial increase in production from our Bakken/Three Forks program.

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Changes in production volumes, revenues, and costs reflect the cyclical and highly volatile nature of our industry. Our realized price on a per MCFE basis for the three and nine months ended September 30, 2012, decreased 14 percent and 16 percent, respectively, compared to the same periods in 2011. The decrease in realized price is due to a decline in commodity prices during 2012.

LOE on a per MCFE basis for the three and nine months ended September 30, 2012, decreased 13 percent and eight percent, respectively, compared to the same periods in 2011. Overall, LOE in all regions increased for the first nine months of 2012, however production increased at a faster rate, thereby reducing LOE on a per MCFE basis. Additionally, the divestiture of non-strategic properties in our Mid-Continent region at the end of the second quarter of 2011 with meaningfully higher per unit operating costs has reduced our LOE on a per MCFE basis for the nine months ended September 30, 2012. LOE in our South Texas & Gulf Coast region decreased for the three months ended September 30, 2012, due to cost saving initiatives in the region as well as the installation of a water recycling facility. We anticipate the installation of the water recycling facility to decrease LOE in our South Texas & Gulf Coast region for the remainder of 2012. We believe the current high level of industry activity, particularly in oil and NGL-rich gas plays, has the potential to drive LOE higher for the remainder of 2012.

Production taxes on a per MCFE basis for the nine months ended September 30, 2012, increased 14 percent compared to the same period in 2011. There was no change in production taxes on a per MCFE basis for the three months ended September 30, 2012, compared with the same period in 2011. In the second quarter of 2011, we were notified that we qualified for severance tax incentive rebate programs for wells in certain areas of Texas. A sizable incentive tax rebate was recorded in the second quarter of 2011, significantly decreasing the per MCFE rate for the nine months ended September 30, 2011. We expect our future operated wells drilled in these areas to qualify for incentive tax rebate programs. We generally expect production taxes to trend with oil, gas, and NGL revenues.

Transportation costs on a per MCFE basis for the three and nine months ended September 30, 2012, increased 16 percent and 30 percent, respectively, compared to the same periods in 2011. This is a result of increased production in our Eagle Ford shale program, where our transportation arrangements have higher per unit transportation costs compared with our other regions. We anticipate transportation costs will continue to increase on a per MCFE basis as our Eagle Ford shale program becomes a larger portion of our total production.

General and administrative expense on a per MCFE basis for the three and nine months ended September 30, 2012, decreased 20 percent and 17 percent, respectively, compared to the same periods in 2011, as production increased at a faster rate than our general and administrative expense. A portion of our general and administrative expense is linked to our profitability and cash flow, which are driven in large part by the realized commodity prices we receive for our production. The Net Profits Plan and a portion of our short-term incentive compensation correlate with net cash flows and therefore are subject to variability.

DD&A expense on a per MCFE basis for the three and nine months ended September 30, 2012, increased 17 percent and 14 percent, respectively, compared to the same periods in 2011. Our DD&A rate increased as a result of the transfer of a portion of our non-operated working interest to Mitsui, which reduced our reserve base but had no impact on the carrying value of our assets. As we utilize our carry with Mitsui, we expect our DD&A rate to improve as we add reserves without incurring capital costs. Please refer to Note 12 - Acquisition and Development Agreement in Part I, Item 1 of this report for additional discussion on the Mitsui transaction. Our DD&A rate can fluctuate as a result of impairments, divestitures, and changes in the mix of our production and the underlying proved reserve volumes. Additionally, the accounting treatment for assets that are classified as held for sale can also impact our DD&A rate since these properties are no longer depleted.

Please refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2012, and 2011 and Comparison of Financial Results and Trends Between the Nine Months Ended September 30, 2012, and 2011 for additional discussion on oil, gas, and NGL production expense, DD&A, and general and administrative expense.

Please refer to Note 9 - Earnings per Share in Part I, Item 1 of this report for additional discussion on the types of shares included in our basic and diluted net income (loss) per common share calculations. During the second quarter of 2012, we called for redemption all of our outstanding 3.50% Senior Convertible Notes. The shares issued upon conversion are reflected in our basic weighted-average common shares outstanding calculations for the three and nine months ended September 30, 2012. We recorded a net loss for the three months ended September 30, 2012. Consequently, our in-the-money stock options, unvested RSUs, and contingent PSUs were anti-dilutive for the quarter resulting in a decrease in the diluted weighted-average common shares outstanding when compared with the three months ended September 30, 2011. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion on our 3.50% Senior Convertible Notes.

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Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2012, and 2011

Oil, gas, and NGL production revenue. Average daily production increased 34 percent to 619.6 MMCFE for the quarter ended September 30, 2012, compared with 462.1 MMCFE for the quarter ended September 30, 2011. The following table presents the regional changes in our oil, gas, and NGL production, revenues, and costs between the two quarters:



	Average Net Daily Production Added (Lost)		Oil, Gas, & NGL Revenue Added (Lost)			Production Costs Increase
	(MMCFE/d)		(in millions)			(in millions)
South Texas & Gulf Coast	135.7		$	41.4		$	12.4
Mid-Continent	(6.9	)	(22.3		)	2.4
Permian	1.3		(1.3		)	2.6
Rocky Mountain	27.4		30.9			7.2
Total	157.5		$	48.7		$	24.6

The largest regional production increase occurred in the South Texas & Gulf Coast region as a result of drilling activity in our Eagle Ford shale program. Production in our Eagle Ford shale program continues to increase and we expect it to continue to do so for the next several years. We also saw an increase in production in our Rocky Mountain region as a result of strong production performance from wells drilled in Bakken/Three Forks program in late 2011 and early 2012.

The following table summarizes the realized prices we received for the three months ended September 30, 2012, and 2011 before the effects of derivative cash settlements:



	For the Three Months Ended September 30,
	2012		2011
Realized oil price ($/Bbl)	$	83.98	$	82.63
Realized gas price ($/Mcf)	$	3.05	$	4.52
Realized NGL price ($/Bbl)	$	34.82	$	56.10
Realized equivalent price ($/MCFE)	$	6.56	$	7.65

A 34 percent increase in production on an equivalent basis combined with a 14 percent decrease in realized price per MCFE resulted in a 15 percent increase in revenue between the two periods. Based on current levels of activity, we expect production volumes to increase annually for the next several years. We also expect our realized prices to trend with commodity prices.

Realized hedge gain (loss). We recorded a net realized hedge gain of $501,000 for the three-month period ended September 30, 2012, compared with a $6.8 million net realized hedge loss for the same period in 2011. These amounts are comprised of realized cash settlements on commodity derivative contracts that were previously recorded in AOCIL. Our realized oil, gas, and NGL hedge gains and losses are a function of commodity prices at the time of settlement compared with the respective derivative contract prices.

Gain (loss) on divestiture activity. We recorded an $8.5 million net loss on divestiture activity for the quarter ended September 30, 2012, compared with a $190.7 million net gain on divestiture activity for the comparable period of 2011. The net loss on divestiture activity in the third quarter of 2012 is due to a loss on unsuccessful sales of properties, the write-down of certain assets held for sale to their fair value, and a net loss on completed divestitures. The gain in the third quarter of 2011 related to the divestiture of certain operated Eagle Ford shale oil and gas assets located in our South Texas & Gulf Coast region. We will continue to evaluate our portfolio to determine whether there are non-strategic properties we could divest. Please refer to Note 3 - Assets Held for Sale in Part I, Item 1 of this report for additional discussion.

Marketed gas system revenue and expense. Marketed gas system revenue decreased $8.5 million to $13.3 million for the quarter ended September 30, 2012, compared with $21.8 million for the same period of 2011 as a result of declining gas prices. Marketed gas system expense decreased $8.0 million to $11.1 million for the quarter ended September 30, 2012, compared with $19.1 million for the same period of 2011. There was no significant change in our net margin. We expect that marketed gas system revenue and expense will continue to correlate with increases and decreases in production and our realized gas price.

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Oil, gas, and NGL production expense. Total production costs for the third quarter of 2012 increased 32 percent to $102.4 million compared with $77.8 million for the same period of 2011 due to a 34 percent increase in net production volumes on an equivalent basis. Please refer to the caption A three-month and nine-month overview of selected production and financial information, including trends above for discussion of production costs on a per MCFE basis.

Depletion, depreciation, amortization, and asset retirement obligation liability accretion. DD&A expense increased $69.3 million, or 56 percent, to $192.4 million for the three-month period ended September 30, 2012, compared with $123.1 million for the same period in 2011 due to an increase in our depreciable asset base as a result of the continued development of our Eagle Ford and Bakken/Three Forks assets and the associated growth in our production. Please refer to the caption A three-month and nine-month overview of selected production and financial information, including trends above for discussion of DD&A on a per MCFE basis.

Exploration. The components of exploration expense are summarized as follows:



	For the Three Months Ended September 30,
	2012		2011
	(in millions)
Geological and geophysical expenses	$	1.4	$	0.2
Exploratory dry hole expense	10.4		—
Overhead and other expenses	13.6		11.1
Total	$	25.4	$	11.3

Exploration expense for the three months ended September 30, 2012, increased 125 percent compared to the same period in 2011 as a result of exploratory wells being deemed dry in the third quarter of 2012. An exploratory project resulting in non-commercial quantities of oil, gas, or NGLs is deemed an exploratory dry hole and impacts the amount of exploration expense we record.

Impairment of proved properties. We had no proved property impairments during the third quarter of 2012. We recorded impairment of proved properties of $48.5 million during the third quarter of 2011 related to legacy assets in the James Lime formation in our Mid-Continent region due to low natural gas prices. Proved property impairments are more likely to occur in periods of low commodity prices.

General and administrative. General and administrative expense increased $2.4 million to $32.2 million for the three months ended September 30, 2012, compared with $29.8 million for the same period of 2011. The change is due to an increase in employee headcount, which resulted in an increase to base compensation, benefits, accruals for cash bonuses, long-term equity compensation expense, and general corporate office expenses incurred. These were offset by in an increase in COPAS overhead reimbursement as a result of an increase in our operated well count. Please refer to the caption A three-month and nine-month overview of selected production and financial information, including trends above for discussion of general and administrative expense on a per MCFE basis.

Change in Net Profits Plan liability. This non-cash expense generally relates to the change in the estimated value of the associated liability between reporting periods. For the quarter ended September 30, 2012, we recorded a non-cash expense of $798,000 compared to a benefit of $24.9 million for the same period in 2011. Strip prices for oil, gas, and NGLs increased during the period from June 30, 2012, to September 30, 2012, resulting in an increase in the liability and corresponding increase in expense recognized on the accompanying statements of operations. Strip prices decreased in the comparable period in 2011, resulting in a decrease in the liability and a corresponding benefit. The change in our liability is subject to estimation and may change dramatically from period to period based on assumptions used for production rates, reserve quantities, commodity pricing, discount rates, and production costs. Payments made to participants as a result of divestitures and ongoing operations will also impact our liability. We broadly expect the change in our Net Profits Plan liability to trend with changes in strip prices for oil, gas, and NGLs.

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Unrealized and realized derivative (gain) loss. We recognized an unrealized and realized derivative loss of $55.9 million for the third quarter of 2012 compared to a gain of $128.4 million for the same period in 2011, as commodity prices have increased moderately during the third quarter of 2012, resulting in less favorable derivative positions. These amounts include the change in fair value on commodity derivative contracts and realized cash settlement gains or losses on derivatives for which unrealized changes in fair value were not previously recorded in AOCIL. Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report for additional discussion.

Income tax benefit (expense). We recorded an income tax benefit of $22.7 million for the third quarter of 2012 compared to an expense of $133.3 million for the third quarter of 2011, resulting in effective tax rates of 37.2 percent and 36.7 percent, respectively. The decrease in income tax expense reflects the decrease in net income before income tax between comparable quarters. The 2012 increase in the effective rate from 2011 primarily reflects changes in the mix of the highest marginal state tax rates, the state tax rate effect on year-to-date net income from divestitures and drilling activities in the periods, the effect related to recording research and development tax credits and changes in the effects of other permanent differences. Based on our projections at the end of the third quarter of 2012, we expect that we will not owe federal income taxes for the current year.

Comparison of Financial Results and Trends Between the Nine Months Ended September 30, 2012, and 2011

Oil, gas, and NGL production revenue. Average daily production increased 33 percent to 577.6 MMCFE for the nine months ended September 30, 2012, compared with 433.7 MMCFE for the same period in 2011. The following table presents the regional changes in our oil, gas, and NGL production, revenues, and costs between the two periods:



	Average Net Daily Production Added (Lost)		Oil, Gas, & NGL Revenue Added (Lost)			Production Costs Increase
	(MMCFE/d)		(in millions)			(in millions)
South Texas & Gulf Coast	118.8		$	109.3		$	56.2
Mid-Continent	(4.0	)	(75.1		)	2.6
Permian	(2.1	)	(15.1		)	3.2
Rocky Mountain	31.2		94.5			21.8
Total	143.9		$	113.6		$	83.8

Please refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2012, and 2011 in the above section for additional discussion regarding the above results.

The following table summarizes the realized prices we received for the nine months ended September 30, 2012, and 2011 before the effects of derivative cash settlements:



	For the Nine Months Ended September 30,
	2012		2011
Realized oil price ($/Bbl)	$	85.76	$	88.54
Realized gas price ($/Mcf)	$	2.78	$	4.51
Realized NGL price ($/Bbl)	$	38.53	$	52.71
Realized equivalent price ($/MCFE)	$	6.63	$	7.90

Revenue increased 12 percent between the two periods due to a 34 percent increase in production volumes on an equivalent basis, which was partially offset by a 16 percent decrease in the realized price per MCFE.

Realized hedge gain (loss). We recorded a net realized hedge gain of $2.3 million for the nine-month period ended September 30, 2012, compared with a $14.5 million net loss for the same period in 2011. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2012, and 2011 in the above section for additional discussion.

Gain (loss) on divestiture activity. We recorded a $31.2 million net loss on divestiture activity for the nine months ended September 30, 2012. The net loss on divestiture activity for the nine months ended 2012 is due to a loss on unsuccessful sales of properties and the write-down of certain assets held for sale to their fair value that was offset by a small net gain on completed divestitures. We recorded a $245.7 million net gain for the comparable period of 2011, which related to the divestiture of non-strategic oil and gas properties located in our Mid-Continent, Rocky Mountain, and South Texas & Gulf Coast regions. Please refer to Note 3 - Assets Held for Sale in Part I, Item 1 of this report for additional discussion.

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Marketed gas system revenue and expense. Marketed gas system revenue decreased $13.9 million to $42.4 million for the nine months ended September 30, 2012, compared with $56.3 million for the same period of 2011, as a result of declining gas prices. Concurrent with the decrease in marketed gas system revenue, marketed gas system expense decreased $13.5 million to $38.1 million for the nine months ended September 30, 2012, compared with $51.6 million for the same period of 2011. There was no significant change in our net margin.

Oil, gas, and NGL production expense. Total production costs for the first nine months of 2012 increased 43 percent to $280.7 million compared with $196.9 million for the same period of 2011, as a result of a 34 percent increase in net production volumes on an equivalent basis and an increase in oil and gas service costs, which started to level out during third quarter 2012. Please refer to the caption A three-month and nine-month overview of selected production and financial information, including trends above for discussion of production costs on a per MCFE basis.

Depletion, depreciation, amortization, and asset retirement obligation liability accretion. DD&A expense increased 52 percent to $523.6 million for the nine-month period ended September 30, 2012, compared with $343.8 million for the same period in 2011 due to an increase in our depreciable asset base as a result of the continued development of our Eagle Ford and Bakken/Three Forks assets and the associated growth in our production. Please refer to the caption A three-month and nine-month overview of selected production and financial information, including trends above for discussion of DD&A on a per MCFE basis.

Exploration. The components of exploration expense are summarized as follows:



	For the Nine Months Ended September 30,
	2012		2011
	(in millions)
Geological and geophysical expenses	$	6.8	$	2.3
Exploratory dry hole expense	18.6		—
Overhead and other expenses	40.6		31.3
Total	$	66.0	$	33.6

Exploration expense for the nine months ended September 30, 2012, increased 96 percent compared to the same period in 2011 as a result of exploratory wells being deemed dry during the first nine months of 2012 and an increase in our technical employee headcount. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2012, and 2011 in the above section for additional discussion.

Impairment of proved properties. We recorded a $38.5 million impairment of proved properties for the nine months ended September 30, 2012, related to our Haynesville shale assets. We recorded impairment of proved properties of $48.5 million for the comparable period in 2011 related to legacy assets located in our Mid-Continent region. The impairment recognized in both periods is a result of depressed gas prices.

Abandonment and impairment of unproved properties. We recorded abandonment and impairment of unproved properties expense of $11.3 million for the nine months ended September 30, 2012, the majority of which related to acreage that the Company no longer intends to develop within our Rocky Mountain region. We recorded $4.3 million of abandonment and impairment of unproved properties for the same period in 2011 primarily associated with lease expirations in our Mid-Continent region.

General and administrative. General and administrative expense increased $8.4 million to $91.4 million for the nine months ended September 30, 2012, compared with $83.0 million for the same period of 2011. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2012, and 2011 and A three-month and nine-month overview of selected production and financial information, including trends in the above sections for additional discussion.

Change in Net Profits Plan liability. For the nine months ended September 30, 2012, we recorded a non-cash benefit of $17.3 million compared to a benefit of $24.7 million for the same period in 2011. Strip prices for oil, gas, and NGLs experienced a greater decline from December 31, 2010, to September 30, 2011, compared with December 31, 2011, to September 30, 2012, resulting in a more significant decrease in the liability and corresponding increase in the benefit recognized in the accompanying statements of operations. Please refer to Note 11 - Fair Value Measurements in Part I, Item 1 of this report for a discussion of the impact a direct payment to cash-out several pools had on our change in Net Profits Plan liability in 2011. See Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2012, and 2011 in the above section for additional discussion.

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Unrealized and realized derivative (gain) loss. We recognized an unrealized and realized derivative gain of $40.0 million for the nine-month period ended September 30, 2012, compared to a gain of $83.9 million for the same period in 2011. Declining commodity prices in both periods resulted in favorable derivative positions, although commodity prices began to increase in the third quarter of 2012, reducing our 2012 nine-month period gain. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2012, and 2011 in the above section for additional discussion.

Income tax benefit (expense). We recorded income tax expense of $7.7 million for the nine-month period ended September 30, 2012, compared to an expense of $195.1 million for the same period in 2011, resulting in effective tax rates of 37.5 percent and 36.7 percent, respectively. The decrease in income tax expense reflects the decrease in net income before income tax between comparable periods. The 2012 increase in the effective rate from 2011 primarily reflects changes in the mix of the highest marginal state tax rates, the state tax rate effect on year-to-date net income from divestitures and drilling activities, the effect of recording our research and development tax credits and changes in the effects of other permanent differences.

Overview of Liquidity and Capital Resources

We believe that we have sufficient liquidity and capital resources to execute our business plans for the foreseeable future. We manage our liquidity and capital resources by entering into commitments for drilling and completion services for varying durations of time, which provides us some flexibility to reduce activity and capital expenditures in periods of prolonged commodity price decline.

Sources of Cash

We currently expect our remaining 2012 capital program to be partially funded by cash flows from operations and the anticipated shortfall to be funded with our credit facility. Although we anticipate that cash flow and borrowing capacity under our credit facility will be sufficient to fund our current capital program, accessing the capital markets is an option if deemed the best solution for our needs. We will continue to evaluate our asset portfolio to identify potential divestiture candidates.

Our primary sources of liquidity are the cash flows provided by our operating activities, borrowings under our credit facility, divestitures of properties, and other financing alternatives, including accessing capital markets. From time to time, we may enter into carrying cost funding and sharing arrangements with third parties for particular exploration and/or development programs. All of our sources of liquidity can be impacted by the general condition of the broader economy and by fluctuations in commodity prices, operating costs, and volumes produced, all of which affect us and our industry. We have no control over the market prices for oil, gas, or NGLs, although we are able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of derivative contracts as part of our commodity price risk management program. The borrowing base under our credit facility could be reduced as a result of lower commodity prices, divestitures of producing properties, or newly issued debt. Historically, decreases in commodity prices have limited our industry’s access to capital markets.

In the second quarter of 2012, we issued $400.0 million in aggregate principal amount under our 2023 Notes. In the fourth quarter of 2011, we issued our 2021 Notes and some of the proceeds from that issuance were available for use in 2012. In late 2011, we consummated our Acquisition and Development Agreement with Mitsui pursuant to which Mitsui funds, or carries, 90 percent of certain drilling and completion costs attributable to our remaining interest in our non-operated Eagle Ford shale acreage until $680.0 million has been expended on our behalf. This carry is expected to be realized over the next two to three years, and, as of September 30, 2012, the remaining carry amount was $478.7 million. Please refer to Note 12 - Acquisition and Development Agreement in Part I, Item 1 of this report for additional discussion.

Current proposals to fund the federal government budget include eliminating or reducing current tax deductions for intangible drilling costs, domestic production activities, and percentage depletion. Legislation modifying or eliminating these deductions would have the immediate effect of reducing operating cash flows, thereby reducing funding available for our and our peers’ exploration and development capital programs. These funding reductions could have a significant adverse effect on oil and gas drilling in the United States for a number of years.

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Credit Facility

In May 2011, we executed our Fourth Amended and Restated Credit Agreement, providing a $2.5 billion senior secured revolving credit facility with a scheduled maturity date of May 27, 2016. In August 2012, our borrowing base under the credit facility was increased to $1.55 billion from $1.4 billion. Our borrowing base is subject to regular semi-annual redeterminations by our lenders and the next scheduled re-determination date is April 1, 2013. As of the filing date of this report, our lenders have committed to a current aggregate commitment amount of $1.0 billion under the credit agreement. We believe the current commitment amount is sufficient to meet our anticipated liquidity and operating needs. Through the filing date of this report, we have experienced no issues utilizing our credit facility. No individual bank participating in our credit facility represents more than ten percent of the lending commitments under the credit facility.

The following table presents the outstanding balance, total amount of letters of credit, and available borrowing capacity under our credit facility as of September 30, 2012, and October 26, 2012.



	As of September 30, 2012		As of October 26, 2012
	(in millions)
Credit facility balance	$	228.0	$	254.0
Letters of credit ⁽¹⁾	$	0.8	$	0.8
Available borrowing capacity	$	771.2	$	745.2

⁽¹⁾ Letters of credit reduce the amount available under the credit facility on a dollar-for-dollar basis.

Our daily weighted-average credit facility debt balance was approximately $157.3 million for the three months ended September 30, 2012. We had no outstanding borrowings during the third quarter of 2011. Our daily weighted-average credit facility debt balance was $131.5 million, and $5.4 million for the nine months ended September 30, 2012, and 2011, respectively. Borrowings under our credit facility are secured by mortgages on our oil and gas properties.

Weighted-Average Interest Rates

Our weighted-average interest rates in the current and prior year include cash interest payments, cash fees paid on the unused portion of the credit facility’s aggregate commitment amount, letter of credit fees, amortization of the debt discount related to our 3.50% Senior Convertible Notes through April 2, 2012, and amortization of deferred financing costs. Our weighted-average borrowing rate includes cash interest payments, and excludes cash fees paid on the unused portion of the credit facility’s aggregate commitment amount, letter of credit fees, amortization of the debt discount related to our 3.50% Senior Convertible Notes through April 2, 2012, and amortization of deferred financing costs.

The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the three-month and nine-month periods ended September 30, 2012, and 2011.



	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2012		2011		2012		2011
Weighted-average interest rate	6.6	%	7.9	%	6.5	%	9.0	%
Weighted-average borrowing rate	6.0	%	5.2	%	5.5	%	5.1	%

The decrease in our weighted-average interest rates from 2011 is a result of our 2019 Notes and 2021 Notes being outstanding for the entire three and nine months ended September 30, 2012, at rates below the average interest rate for the same periods in 2011, as well as a higher average balance on our revolving credit facility, which reduces the fee paid on the unused portion of our commitment. During the first nine months of 2011, our 2019 Notes were outstanding for only part of the period.

Our weighted-average borrowing rates for the three and nine months ended September 30, 2012, were higher than the rates for the comparable periods in 2011 due to the three tranches of high yield unsecured debt that we have issued since February 2011, as well as the redemption of our 3.50% Senior Convertible Notes in the second quarter of 2012. Each tranche of high yield unsecured debt has a coupon rate that is higher than the coupon rate on the 3.50% Senior Convertible Notes, and is also higher than the average borrowing rates on the credit facility incurred during 2011. This had the effect of increasing our average borrowing rate because high yield unsecured debt replaced lower cost secured bank debt and our 3.50% Senior Convertible Notes.

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We are subject to customary covenants under our credit facility, including limitations on dividend payments and requirements to maintain certain financial ratios, which include debt to EBITDAX, as defined under the caption Non-GAAP Financial Measures below, of less than 4.0 to 1.0 and an adjusted current ratio, as defined by our credit agreement, of no less than 1.0. As of September 30, 2012, our debt to EBITDAX ratio and adjusted current ratio, as defined by our credit agreement, were 1.3 and 2.2, respectively. As of the filing date of this report, we are in compliance with all financial and non-financial covenants under our credit facility.

Uses of Cash

We use cash for the acquisition, exploration, and development of oil and gas properties and for the payment of trade payables, overhead, income taxes, dividends, and debt obligations, including interest. Expenditures for the exploration and development of oil and gas properties are the primary use of our capital resources. In the first nine months of 2012, we spent $1.1 billion for exploration and development capital activities and leasehold acquisitions. These amounts differ from the cost incurred amounts, which are accrual-based.

The amount and allocation of future capital expenditures will depend upon a number of factors, including the number and size of available acquisition and drilling opportunities, our cash flows from operating, investing, and financing activities, and our ability to assimilate acquisitions and execute our drilling program. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, and the timing and results of our operated and non-operated development and exploratory activities may lead to changes in funding requirements for future development. We regularly review our capital expenditure budget to assess changes in current and projected cash flows, acquisition and divestiture activities, debt requirements, and other factors.

We may from time to time repurchase certain amounts of our outstanding debt securities for cash and/or through exchanges for other securities. Such repurchases or exchanges may be made in open market transactions, privately negotiated transactions, or otherwise. Any such repurchases or exchanges will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material.

During the first nine months of 2012, we have paid $3.2 million in dividends to our stockholders, which constitutes a dividend of $0.05 per share. Additionally, we declared a dividend payment of $3.3 million to be paid in the fourth quarter of 2012. Our intention is to continue to make dividend payments for the foreseeable future, subject to our future earnings, our financial condition, credit facility and other covenants, and other factors which could arise. Payment of future dividends remains at the discretion of our Board of Directors. Additionally, during the second quarter of 2012 we paid $287.5 million to settle our 3.50% Senior Convertible Notes.

As of the filing date of this report, we had authorization from our Board of Directors to repurchase up to 3,072,184 shares of our common stock under our stock repurchase program. Shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our credit facility and the indentures governing our 2019 Notes, 2021 Notes, and 2023 Notes, compliance with securities laws, and the terms and provisions of our stock repurchase program. We currently do not plan to repurchase any outstanding shares in 2012.

The following table presents changes in cash flows between the nine-month periods ended September 30, 2012, and 2011. The analysis following the table should be read in conjunction with our condensed consolidated statements of cash flows in Part I, Item 1 of this report.



	For the Nine Months Ended September 30,						Amount Change Between Periods			Percent Change Between Periods
	2012			2011			Amount Change Between Periods			Percent Change Between Periods
	(in millions)
Net cash provided by operating activities	$	653.6		$	489.7		$	163.9		33	%
Net cash (used in) investing activities	$	(1,083.7	)	$	(756.9	)	$	(326.8	)	43	%
Net cash provided by financing activities	$	311.1		$	292.0		$	19.1		7	%

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Analysis of Cash Flow Changes Between the Nine Months Ended September 30, 2012, and 2011

Operating activities. Cash received from oil, gas, and NGL production revenues, including derivative cash settlements, increased $212.5 million, or 24 percent, to $1.1 billion for the first nine months of 2012, compared to the same period in 2011. This increase was due to an increase in production volumes and favorable hedge settlements resulting from declining commodity prices throughout the first half of the year. Cash paid for lease operating expenses increased $24.9 million to $135.9 million for the first nine months of 2012, compared to the same period in 2011, due to increased service costs caused by higher demand. Cash paid for interest during the first nine months of 2012 increased $17.3 million compared to the same period in 2011 due to interest payments on our 2019 Notes and 2021 Notes.

Investing activities. Capital expenditures in 2012 increased $45.1 million, or four percent, compared with the same period in 2011. This increase was due to increased drilling activity, which was driven by our successful development activities in our Eagle Ford shale and Bakken/Three Forks programs. Net proceeds from the sale of oil and gas properties decreased $276.4 million between the two periods.

Financing activities. During the the first nine months of 2012, we paid $287.5 million to settle our 3.50% Senior Convertible Notes. We received $392.2 million of net proceeds from the issuance of our 2023 Notes in 2012, compared with $341.1 million of proceeds from the issuance of our 2019 Notes in 2011. We had net borrowings against our credit facility of $228.0 million during the nine months ended September 30, 2012, compared with net repayments of $48.0 million made during the same period in 2011.

Commodity Price Risk and Interest Rate Risk

We are exposed to market risk, which is estimated as the potential change in fair value resulting from an immediate hypothetical one percentage point parallel shift in the yield curve, including the effects of changes in oil, gas, and NGL commodity prices and changes in interest rates. Changes in interest rates can affect the amount of interest we earn on our cash and cash equivalents and the amount of interest we pay on borrowings under our credit facility. Changes in interest rates do not affect the amount of interest we pay on our fixed-rate 2019 Notes, 2021 Notes, or 2023 Notes, but do affect their fair market value. The carrying amount of our floating-rate debt typically approximates its fair value. As of September 30, 2012, we had $228.0 million of floating-rate debt outstanding, and our fixed-rate debt outstanding totaled $1.1 billion.

There has been no material change to the oil and gas price sensitivity analysis previously disclosed. Please refer to the corresponding section under Part II, Item 7 of our 2011 Form 10-K.

Summary of Oil, Gas, and NGL Derivative Contracts in Place

Our oil, gas, and NGL derivative contracts include costless swaps and costless collar arrangements. All contracts are entered into for other-than-trading purposes. Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report for additional information regarding accounting for our derivative transactions.

As of September 30, 2012, and through the filing date of this report, we had derivative positions in place covering a portion of anticipated production through the second quarter of 2015, totaling 10.8 million Bbls of oil, 79.3 million MMBtu of gas, and 1.5 million Bbls of NGLs.

In a typical commodity swap agreement, if the agreed upon published third-party index price is lower than the swap fixed price, we receive the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, we pay the difference. For collar agreements, we receive the difference between an agreed upon index and the floor price if the index price is below the floor price. We pay the difference between the agreed upon ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices.

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The following tables describe the approximate volumes, average contract prices, and fair values of contracts we had in place as of September 30, 2012:

Oil Contracts

Oil Swaps



Contract Period	NYMEX WTI Volumes	Weighted-Average Contract Price		Fair Value at September 30, 2012 (Liability)
	(Bbls)	(per Bbl)		(in millions)
Fourth quarter 2012	854,000	$	88.61	$	(3.5	)
2013	1,613,000	$	90.10	(5.9		)
2014	1,256,000	$	90.92	(1.0		)
2015	356,000	$	88.40	(0.3		)
All oil swaps	4,079,000			$	(10.7	)

Oil Collars



Contract Period	NYMEX WTI Volumes	Weighted- Average Floor Price		Weighted- Average Ceiling Price		Fair Value at September 30, 2012 Asset
	(Bbls)	(per Bbl)		(per Bbl)		(in millions)
Fourth quarter 2012	566,000	$	80.03	$	112.28	$	0.2
2013	2,866,000	$	78.14	$	110.11	1.6
2014	2,174,000	$	83.71	$	107.93	6.3
2015	1,120,000	$	85.00	$	98.58	1.9
All oil collars	6,726,000					$	10.0

Gas Contracts

Gas Swaps



Contract Period	Volumes	Weighted-Average Contract Price		Fair Value at September 30, 2012 Asset (Liability)
	(MMBtu)	(per MMBtu)		(in millions)
Fourth quarter 2012	10,951,000	$	4.15	$	10.1
2013	27,523,000	$	4.22	13.3
2014	18,469,000	$	4.15	1.0
2015	9,985,000	$	3.90	(3.3		)
All gas swaps*	66,928,000			$	21.1

*Gas swaps are comprised of IF CIG (1%), IF HSC (52%), IF NGPL TXOK (5%), IF PEPL (15%), IF Reliant N/S (19%), and IF TETCO STX (8%).

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Gas Collars



Contract Period	Volumes	Weighted- Average Floor Price		Weighted- Average Ceiling Price		Fair Value at September 30, 2012 Asset
	(MMBtu)	(per MMBtu)		(per MMBtu)		(in millions)
2013	6,650,000	$	4.39	$	5.34	$	5.0
2014	5,734,000	$	4.38	$	5.36	3.3
All gas collars*	12,384,000					$	8.3

*Gas collars are comprised of IF HSC (18%), IF NGPL TXOK (18%), IF Reliant N/S (29%), and IF TETCO STX (35%).

NGL Contracts

NGL Swaps



Contract Period	Volumes	Weighted-Average Contract Price		Fair Value at September 30, 2012 Asset
	(approx. Bbls)	(per Bbl)		(in millions)
Fourth quarter 2012	465,000	$	49.32	$	3.7
2013	1,081,000	$	44.22	3.7
All NGL swaps*	1,546,000			$	7.4

*NGL swaps are comprised of OPIS Mont. Belvieu Ethane Purity (41%), OPIS Mont. Belvieu LDH Propane (29%), OPIS Mont. Belvieu NON-LDH Isobutane (4%), OPIS Mont. Belvieu NON-LDH Normal Butane (5%), and OPIS Mont. Belvieu NON-LDH Natural Gasoline (21%).

Off-Balance Sheet Arrangements

As part of our ongoing business, we have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPE”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. As of September 30, 2012, and through the filing date of this report, we have not been involved in any unconsolidated SPE transactions.

We evaluate our transactions to determine if any variable interest entities exist. If it is determined that we are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial statements.

Critical Accounting Policies and Estimates

Please refer to the corresponding section in Part II, Item 7 of our 2011 Form 10-K and to the footnote disclosures included in Part I, Item 1 of this report for a discussion of our accounting policies and estimates.

New Accounting Pronouncements

Please refer to Note 2 - Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards under Part I, Item 1 of this report for new accounting matters.

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Non-GAAP Financial Measures

EBITDAX represents income (loss) before interest expense, interest income, income taxes, depreciation, depletion, amortization and accretion, exploration expense, property impairments, non-cash stock compensation expense, unrealized derivative gains and losses, change in the Net Profit Plan liability, and gains and losses on divestitures. EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally one-time or whose timing and/or amount cannot be reasonably estimated. EBITDAX is a non-GAAP measure that is presented because we believe that it provides useful additional information to investors, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our credit facility based on our debt to EBITDAX ratio. In addition, EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by (used in) operating activities, profitability, or liquidity measures prepared under GAAP. Because EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the EBITDAX amounts presented may not be comparable to similar metrics of other companies. The following table provides a reconciliation of our net income (loss) to EBITDAX for the periods presented:



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2012			2011			2012			2011
	(in thousands)
Net income (loss)	$	(38,336	)	$	230,097		$	12,889		$	336,127
Interest expense	18,362			9,372			45,352			33,636
Interest income	(126		)	(27		)	(201		)	(382		)
Income tax (benefit) expense	(22,736		)	133,346			7,740			195,142
Depreciation, depletion, amortization, and asset retirement obligation liability accretion	192,432			123,067			523,610			343,805
Exploration	25,417			11,272			66,031			33,587
Impairment of proved properties	—			48,525			38,523			48,525
Abandonment and impairment of unproved properties	447			—			11,296			4,316
Stock-based compensation expense	9,359			7,713			21,731			19,550
Unrealized derivative (gain) loss	66,777			(132,180		)	(7,237		)	(108,020		)
Change in Net Profits Plan liability	798			(24,930		)	(17,342		)	(24,719		)
(Gain) loss on divestiture activity	8,532			(190,728		)	31,246			(245,662		)
EBITDAX	$	260,926		$	215,527		$	733,638		$	635,905

Cautionary Information about Forward-Looking Statements

This Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this report that address activities, events, or developments with respect to our financial condition, results of operations, or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “intend,” “plan,” “project,” “will,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear in a number of places in this report, and include statements about such matters as:


•	the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;


•	the drilling of wells and other exploration and development activities and plans, as well as possible future acquisitions;


•	the possible divestiture or farm-down of, or joint venture relating to, certain properties;

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•	proved reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those proved reserve estimates;


•	future oil, gas, and NGL production estimates;


•	our outlook on future oil, gas, and NGL prices, well costs, and service costs;


•	cash flows, anticipated liquidity, and the future repayment of debt;


•	business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, and our outlook on our future financial condition or results of operations; and


•	other similar matters such as those discussed in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section of this report.

Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. These statements are subject to a number of known and unknown risks and uncertainties, which may cause our actual results and performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. These risks are described in the Risk Factors section of our 2011 Form 10-K, and include such factors as:


•	the volatility of oil, gas, and NGL prices, and the effect it may have on our profitability, financial condition, cash flows, access to capital, and ability to grow production volumes and/or proved reserves;


•	the continued weakness in economic conditions and uncertainty in financial markets;


•	our ability to replace reserves in order to sustain production;


•	our ability to raise the substantial amount of capital that is required to replace our reserves;


•	our ability to compete against competitors that have greater financial, technical, and human resources;


•	our ability to attract and retain key personnel;


•	the imprecise estimations of our actual quantities and present value of proved oil, gas, and NGL reserves;


•	the uncertainty in evaluating recoverable reserves and estimating expected benefits or liabilities;


•	the possibility that exploration and development drilling may not result in commercially producible reserves;


•	our limited control over activities on non-operated properties;


•	our reliance on the skill and expertise of third-party service providers on our operated properties;


•	the possibility that title to properties in which we have an interest may be defective;


•	the possibility that our planned drilling in existing or emerging resource plays using some of the latest available horizontal drilling and completion techniques is subject to drilling and completion risks and may not meet our expectations for reserves or production;


•	the uncertainties associated with divestitures, joint ventures, farm-downs, farm-outs and similar transactions with respect to certain assets, including whether such transactions will be consummated or completed in the form or timing and for the value that we anticipate;


•	the uncertainties associated with enhanced recovery methods;


•	our commodity derivative contracts may result in financial losses or may limit the prices that we receive for oil, gas, and NGL sales;

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•	the inability of one or more of our vendors, customers, or contractual counterparties to meet their obligations;


•	price declines or unsuccessful exploration efforts resulting in write-downs of our asset carrying values;


•	the impact that lower oil, gas, or NGL prices could have on our ability to borrow under our credit facility;


•	the possibility that our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt;


•	operating and environmental risks and hazards that could result in substantial losses;


•	complex laws and regulations, including environmental regulations, that result in substantial costs and other risks;


•	the availability and capacity of gathering, transportation, processing, and/or refining facilities;


•	our ability to sell and/or receive market prices for our oil, gas, and NGLs;


•	the possibility that new technologies may cause our current exploration and drilling methods to become obsolete;


•	the possibility of security threats, including terrorist attacks and cybersecurity breaches, against, or otherwise impacting, our facilities and systems; and


•	litigation, environmental matters, the potential impact of government regulations, and the use of management estimates regarding such matters.

We caution you that forward-looking statements are not guarantees of future performance and that actual results or performance may be materially different from those expressed or implied in the forward-looking statements. The forward-looking statements in this report speak as of the filing date of this report. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by securities laws.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by this item is provided under the captions Commodity Price Risk and Interest Rate Risk and Summary of Oil, Gas, and NGL Derivative Contracts in Place in Item 2 above and is incorporated herein by reference. Please also refer to the sensitivity analysis within our 2011 Form 10-K in Part II, Item 7.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures that are designed to reasonably ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to reasonably ensure that such information is accumulated and communicated to our management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) (“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our Disclosure Controls are effective at a reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There have been no changes during the third quarter of 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of business. As of the filing date of this report, no legal proceedings are pending against us that we believe individually or collectively could have a materially adverse effect upon our financial condition, results of operations or cash flows.

We were a defendant in litigation, captioned W.H. Sutton, et al. vs. St. Mary Land & Exploration Co., et al., wherein the plaintiffs claimed an aggregate overriding royalty interest of 7.46875 percent in production from approximately 22,000 of our net acres in the Eagle Ford shale play in South Texas. The plaintiffs sought to quiet title to their claimed overriding royalty interest and to recover unpaid overriding royalty interest proceeds allegedly due. We believed that the claimed overriding royalty interest had been terminated under the governing agreements and the applicable law, and contested the plaintiffs’ claims. Both parties filed motions for summary judgment, and on February 8, 2011, the District Court in Webb County, Texas, issued an order granting plaintiffs’ motion for summary judgment and denying our motion for summary judgment. On September 30, 2011, the District Court entered final judgment for the plaintiffs and awarded then current damages of approximately $5.1 million, which included prejudgment interest. The District Court also awarded attorneys fees and costs to the plaintiffs. We appealed the District Court’s judgment and obtained a stay pending appeal that prevented the plaintiffs from executing on the judgment.

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On May 23, 2012, the Fourth Court of Appeals for the State of Texas delivered its opinion in this matter, which reversed the summary judgment granted to the plaintiffs by the District Court and rendered judgment that the plaintiffs take nothing. Accordingly, based on the judgment of the Fourth Court of Appeals, the plaintiffs are not entitled to their claimed 7.46875 percent overriding royalty interest, nor are they entitled to the claimed damages related to the overriding royalty interest, attorneys fees or costs. The plaintiffs have petitioned the Supreme Court of Texas for a review of the judgment of the Fourth Court of Appeals. In the event the plaintiffs’ petition is granted, we will continue to contest this litigation.

We cannot predict the ultimate outcome of this lawsuit. If the plaintiffs were to ultimately prevail in any further appeal, the overriding royalty interest would have the effect of reducing our net revenue interest in the affected acreage, which would negatively impact our economics in this portion of our acreage, but we do not believe would have a material adverse effect upon our financial condition, results of operations, or cash flows.

We also filed a declaratory judgment action in Webb County, Texas, captioned SM Energy Company vs. W.H. Sutton, et al., seeking a judgment declaring that the lease at issue in W.H. Sutton, et al. vs. St. Mary Land & Exploration Co., et al. had terminated with respect to the remaining 18,000 acres, based upon a failure of continuous development, and that any overriding royalty interest claimed by the defendants has been extinguished. On September 19, 2012, the District Court in Webb County, Texas, granted our motion for summary judgment, concluding that the defendants' claims for any overriding royalty interest had been extinguished.

We, and our working interest partners, filed an action against Endeavour Operating Corporation ("Endeavour") in Harris County, Texas, captioned SM Energy Company, et al. v. Endeavour Operating Corporation, seeking an order requiring Endeavour to honor its obligations to consummate the purchase of certain assets located in Pennsylvania, or in the alternative, for damages. We are required to take reasonable measures to attempt to mitigate our potential losses, and, subsequent to March 31, 2012, we initiated efforts to remarket such assets. If we are successful in such efforts and complete a sale of these assets for less than the $110 million ($80 million of which is attributable to our interest) Endeavour agreed to pay to us and our working interest partners , we will continue to prosecute this action to recover any such deficiency and any amounts expended in our efforts to remarket the assets, and to obtain any other relief to which we are entitled.

With the exception of the above disclosures, there have been no material changes to the legal proceedings as previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2011, under Item 3, Part I. See Note 6 - Commitments and Contingencies, in Part I, Item 1 of this report, for additional discussion.

ITEM 1A. RISK FACTORS

There have been no material changes to the risk factors as previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2011.

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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS


(c)	The following table provides information about purchases by the Company or any “affiliated purchaser” (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the fiscal quarter ended September 30, 2012, of shares of the Company's common stock, which is the sole class of equity securities registered by the Company pursuant to Section 12 of the Exchange Act:

PURCHASES OF EQUITY SECURITIES BY ISSUER

AND AFFILIATED PURCHASERS



Period	(a) Total Number of Shares Purchased ⁽¹⁾	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Program	(d) Maximum Number of Shares that May Yet Be Purchased Under the Program ⁽²⁾
07/01/12 - 07/31/12	14,407	$	48.11	—	3,072,184
08/01/12 - 08/31/12	441,820	$	47.30	—	3,072,184
09/01/12 - 09/30/12	—	$	—	—	3,072,184
Total:	456,227	$	47.32	—	3,072,184


⁽¹⁾	All shares purchased in the third quarter of 2012 were to offset tax withholding obligations that occur upon the delivery of outstanding shares underlying RSUs and PSUs delivered under the terms of grants under our Equity Incentive Compensation Plan.

⁽²⁾

In July 2006, our Board of Directors approved an increase in the number of shares that may be repurchased under the original August 1998 authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the date of this filing, we may repurchase up to 3,072,184 shares of common stock on a prospective basis. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our credit facility, the indentures governing our 2019 Notes, 2021 Notes, and 2023 Notes and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flow, or borrowings under our credit facility. The stock repurchase program may be suspended or discontinued at any time.

Our payment of cash dividends to our stockholders is subject to covenants in our credit facility that limit our annual dividend payments to no more than $50.0 million per year. We are also subject to certain covenants under our 2019 Notes, 2021 Notes and 2023 Notes that restrict certain payments, including dividends; provided, however, that the first $6.5 million of dividends paid each year are not restricted by these covenants. We do not anticipate that these restrictions will limit our payment of dividends at our current rate for the foreseeable future if declared by our Board of Directors.

Table of Contents

ITEM 6. EXHIBITS

The following exhibits are filed or furnished with or incorporated by reference into this report:



Exhibit		Description
31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002
31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002
32.1**		Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002
99.1*		Audit Committee Pre-Approval of Non-Audit Services
101.INS****		XBRL Instance Document
101.SCH****		XBRL Schema Document
101.CAL****		XBRL Calculation Linkbase Document
101.LAB****		XBRL Label Linkbase Document
101.PRE****		XBRL Presentation Linkbase Document
101.DEF****		XBRL Taxonomy Extension Definition Linkbase Document

_____________________________________



	*	Filed with this report.
	**	Furnished with this report.
	****	Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.



	SM ENERGY COMPANY

November 1, 2012		By:	/s/ ANTHONY J. BEST
			Anthony J. Best
			Chief Executive Officer

November 1, 2012		By:	/s/ A. WADE PURSELL
			A. Wade Pursell
			Executive Vice President and Chief Financial Officer

November 1, 2012		By:	/s/ MARK T. SOLOMON
			Mark T. Solomon
			Vice President and Controller