Edgar Filing: SM Energy Co

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 June 30, 2010

Commission File Number 001-31539

SM ENERGY COMPANY

(Exact name of registrant as specified in its charter)

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer x

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). Yeso No x

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

As of July 28, 2010 the registrant had 63,007,624 shares of common stock, $0.01 par value, outstanding.

SM ENERGY COMPANY

INDEX

			PAGE
Part I.	FINANCIAL INFORMATION

	Item 1.	Financial Statements (Unaudited)

		Condensed Consolidated Balance Sheets June 30, 2010, and December 31, 2009	3

		Condensed Consolidated Statements of Operations Three and Six Months Ended June 30, 2010, and 2009	4

		Condensed Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss) June 30, 2010, and June 30, 2009	5

		Condensed Consolidated Statements of Cash Flows Six Months Ended June 30, 2010, and 2009	6

		Notes to Condensed Consolidated Financial Statements June 30, 2010	8

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk (included within the content of Item 2)	59

	Item 4.	Controls and Procedures	59

Part II.	OTHER INFORMATION

	Item 1A.	Risk Factors	59

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	60

	Item 6.	Exhibits	61

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(In thousands, except share amounts)

	June 30,			December 31,
	2010			2009
ASSETS
Current assets:
Cash and cash equivalents	$	10,249		$	10,649
Accounts receivable	108,427			116,136
Refundable income taxes	23,215			32,773
Prepaid expenses and other	14,284			14,259
Derivative asset	45,481			30,295
Deferred income taxes	—			4,934
Total current assets	201,656			209,046

Property and equipment (successful efforts method), at cost:
Land	1,483			1,371
Proved oil and gas properties	3,066,300			2,797,341
Less - accumulated depletion, depreciation, and amortization	(1,203,841		)	(1,053,518		)
Unproved oil and gas properties, net of impairment allowance of $62,507 in 2010 and $66,570 in 2009	138,531			132,370
Wells in progress	97,312			65,771
Materials inventory, at lower of cost or market	31,305			24,467
Oil and gas properties held for sale less accumulated depletion, depreciation, and amortization	7,115			145,392
Other property and equipment, net of accumulated depreciation of $16,478 in 2010 and $14,550 in 2009	15,472			14,404
	2,153,677			2,127,598

Other noncurrent assets:
Derivative asset	30,169			8,251
Restricted cash subject to Section 1031 Exchange	19,595			—
Other noncurrent assets	12,288			16,041
Total other noncurrent assets	62,052			24,292

Total Assets	$	2,417,385		$	2,360,936

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	270,030		$	236,242
Derivative liability	37,903			53,929
Deposit associated with oil and gas properties held for sale	—			6,500
Deferred income taxes	4,970			—
Total current liabilities	312,903			296,671

Noncurrent liabilities:
Long-term credit facility	—			188,000
Senior convertible notes, net of unamortized discount of $16,288 in 2010, and $20,598 in 2009	271,212			266,902
Asset retirement obligation	64,284			60,289
Asset retirement obligation associated with oil and gas properties held for sale	1,526			18,126
Net Profits Plan liability	136,420			170,291
Deferred income taxes	408,997			308,189
Derivative liability	24,046			65,499
Other noncurrent liabilities	15,164			13,399
Total noncurrent liabilities	921,649			1,090,695

Commitments and contingencies

Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued: 63,110,068 shares in 2010 and 62,899,122 shares in 2009; outstanding, net of treasury shares: 63,007,433 shares in 2010 and 62,772,229 shares in 2009	631			629
Additional paid-in capital	174,973			160,516
Treasury stock, at cost: 102,635 shares in 2010 and 126,893 shares in 2009	(489		)	(1,204		)
Retained earnings	992,685			851,583
Accumulated other comprehensive income (loss)	15,033			(37,954		)
Total stockholders’ equity	1,182,833			973,570

Total Liabilities and Stockholders’ Equity	$	2,417,385		$	2,360,936

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(In thousands, except per share amounts)

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009

Operating revenues and other income:
Oil and gas production revenue	$	175,887		$	145,279		$	388,774		$	275,696
Realized oil and gas hedge gain	9,329			43,279			11,924			98,899
Gain on divestiture activity	7,021			1,244			127,999			645
Marketed gas system and other operating revenue	19,460			15,396			43,135			29,178
Total operating revenues and other income	211,697			205,198			571,832			404,418

Operating expenses:
Oil and gas production expense	45,168			49,465			93,508			105,294
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	79,770			70,391			157,535			162,103
Exploration	14,498			19,490			28,396			33,088
Impairment of proved properties	—			6,043			—			153,092
Abandonment and impairment of unproved properties	2,375			11,631			3,279			15,533
Impairment of materials inventory	—			2,719			—			11,335
General and administrative	25,398			18,160			48,884			34,559
Change in Net Profits Plan liability	(6,599		)	2,449			(33,871		)	(20,842		)
Marketed gas system expense	15,807			13,609			37,853			26,992
Unrealized derivative (gain) loss	(2,087		)	11,288			(9,822		)	13,134
Other expense	578			5,814			1,530			11,456
Total operating expenses	174,908			211,059			327,292			545,744

Income (loss) from operations	36,789			(5,861		)	244,540			(141,326		)

Nonoperating income (expense):
Interest income	54			105			183			127
Interest expense	(6,343		)	(7,663		)	(13,130		)	(13,759		)

Income (loss) before income taxes	30,500			(13,419		)	231,593			(154,958		)
Income tax benefit (expense)	(12,432		)	5,097			(87,347		)	59,013

Net income (loss)	$	18,068		$	(8,322	)	$	144,246		$	(95,945	)

Basic weighted-average common shares outstanding	62,917			62,418			62,855			62,377

Diluted weighted-average common shares outstanding	64,566			62,418			64,493			62,377

Basic net income (loss) per common share	$	0.29		$	(0.13	)	$	2.29		$	(1.54	)

Diluted net income (loss) per common share	$	0.28		$	(0.13	)	$	2.24		$	(1.54	)

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

(In thousands, except share amounts)

															Accumulated
				Additional											Other			Total
	Common Stock			Paid-in			Treasury Stock					Retained			Comprehensive			Stockholders’
	Shares	Amount		Capital			Shares		Amount			Earnings			Income (Loss)			Equity

Balances, December 31, 2009	62,899,122	$	629	$	160,516		(126,893	)	$	(1,204	)	$	851,583		$	(37,954	)	$	973,570

Comprehensive income, net of tax:
Net income	—	—		—			—		—			144,246			—			144,246
Change in derivative instrument fair value	—	—		—			—		—			—			53,765			53,765
Reclassification to earnings	—	—		—			—		—			—			(782		)	(782		)
Minimum pension liability adjustment	—	—		—			—		—			—			4			4
Total comprehensive income																		197,233
Cash dividends, $ 0.05 per share	—	—		—			—		—			(3,144		)	—			(3,144		)
Issuance of common stock under Employee Stock Purchase Plan	27,456	—		799			—		—			—			—			799
Issuance of common stock upon settlement of RSUs following expiration of restriction period, net of shares used for tax withholdings, including income tax cost of RSUs	34,588	1		(545		)	—		—			—			—			(544		)
Sale of common stock, including income tax benefit of stock option exercises	148,902	1		3,054			—		—			—			—			3,055
Stock-based compensation expense	—	—		11,149			24,258		715			—			—			11,864

Balances, June 30, 2010	63,110,068	$	631	$	174,973		(102,635	)	$	(489	)	$	992,685		$	15,033		$	1,182,833

Balances, December 31, 2008	62,465,572	$	625	$	141,283		(176,987	)	$	(1,892	)	$	957,200		$	65,293		$	1,162,509

Comprehensive loss, net of tax:
Net loss	—	—		—			—		—			(95,945		)	—			(95,945		)
Change in derivative instrument fair value	—	—		—			—		—			—			(11,852		)	(11,852		)
Reclassification to earnings	—	—		—			—		—			—			(45,494		)	(45,494		)
Minimum pension liability adjustment	—	—		—			—		—			—			4			4
Total comprehensive loss																		(153,287		)
Cash dividends, $ 0.05 per share	—	—		—			—		—			(3,120		)	—			(3,120		)
Issuance of common stock under Employee Stock Purchase Plan	49,767	—		858			—		—			—			—			858
Issuance of common stock upon settlement of RSUs following expiration of restriction period, net of shares used for tax withholdings, including income tax cost of RSUs	86,505	1		(3,249		)	—		—			—			—			(3,248		)
Sale of common stock, including income tax benefit of stock option exercises	19,570	—		207			—		—			—			—			207
Stock-based compensation expense	1,250	—		6,873			50,094		636			—			—			7,509

Balances, June 30, 2009	62,622,664	$	626	$	145,972		(126,893	)	$	(1,256	)	$	858,135		$	7,951		$	1,011,428

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In thousands)

	For the Six Months
	Ended June 30,
	2010			2009

Cash flows from operating activities:
Net income (loss)	$	144,246		$	(95,945	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Gain on divestiture activity	(127,999		)	(645		)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	157,535			162,103
Exploratory dry hole expense	327			4,667
Impairment of proved properties	—			153,092
Abandonment and impairment of unproved properties	3,279			15,533
Impairment of materials inventory	—			11,335
Stock-based compensation expense	11,864			7,509
Change in Net Profits Plan liability	(33,871		)	(20,842		)
Unrealized derivative (gain) loss	(9,822		)	13,134
Loss related to hurricanes	—			7,120
Amortization of debt discount and deferred financing costs	6,657			5,703
Deferred income taxes	78,820			(63,148		)
Plugging and abandonment	(6,222		)	(2,355		)
Other	2,937			1,619
Changes in current assets and liabilities:
Accounts receivable	7,628			49,149
Refundable income taxes	9,558			13,161
Prepaid expenses and other	(148		)	(7,091		)
Accounts payable and accrued expenses	26,299			(12,338		)
Excess income tax benefit from the exercise of stock options	(938		)	—
Net cash provided by operating activities	270,150			241,761

Cash flows from investing activities:
Net proceeds from sale of oil and gas properties	247,998			1,081
Capital expenditures	(304,627		)	(215,826		)
Acquisition of oil and gas properties	—			(44		)
Deposits to restricted cash	(19,595		)	—
Receipts from restricted cash	—			14,398
Receipts from short-term investments	—			1,002
Other	(6,492		)	—
Net cash used in investing activities	(82,716		)	(199,389		)

Cash flows from financing activities:
Proceeds from credit facility	204,059			1,766,000
Repayment of credit facility	(392,059		)	(1,791,000		)
Debt issuance costs related to credit facility	—			(11,060		)
Proceeds from sale of common stock	2,916			1,066
Dividends paid	(3,144		)	(3,120		)
Excess income tax benefit from the exercise of stock options	938			—
Other	(544		)	—
Net cash used in financing activities	(187,834		)	(38,114		)

Net change in cash and cash equivalents	(400		)	4,258
Cash and cash equivalents at beginning of period	10,649			6,131
Cash and cash equivalents at end of period	$	10,249		$	10,389

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

SM ENERGY COMPANY AND SUBSIDIARIES

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

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

	For the Six Months
	Ended June 30,
	2010			2009
	(In thousands)

Cash paid for interest	$	8,152		$	8,837

Cash refunded for income taxes	$	(2,392	)	$	(10,441	)

As of June 30, 2010, and 2009, $105.4 million, and $57.9 million, respectively, are included as additions to oil and gas properties and accounts payable and accrued expenses in the accompanying condensed consolidated balance sheets. These oil and gas additions are reflected as cash used in investing activities in the periods that the payables are settled.

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

SM ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

June 30, 2010

Note 1 — The Company and Business

SM Energy Company (“SM Energy” or the “Company”), formerly named St. Mary Land & Exploration Company or referred to as St. Mary, is an independent energy company engaged in the exploration, exploitation, development, acquisition, and production of natural gas, natural gas liquids, and crude oil. The Company’s operations are conducted entirely in the continental United States.

Note 2 — Basis of Presentation and Significant Accounting Policies

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 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 generally accepted accounting principles 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, 2009, (the “2009 Form 10-K”). In the opinion of management, all adjustments, consisting of normal recurring accruals that are considered necessary for a fair presentation of the 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 the condensed consolidated financial statements of SM Energy, the Company evaluated subsequent events after the balance sheet date of June 30, 2010, 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 2009 Form 10-K, and are supplemented throughout the notes to condensed consolidated financial statements in this report. It is suggested that these condensed consolidated financial statements be read in conjunction with the consolidated financial statements and notes included in the 2009 Form 10-K.

Note 3 —Divestitures and Assets Held for Sale

Legacy Divestiture

In February 2010 the Company completed the divestiture of certain non-strategic oil properties located in Wyoming to Legacy Reserves Operating LP, a wholly-owned subsidiary of Legacy Reserves LP (“Legacy”). The transaction had an effective date of November 1, 2009. Total cash received, before commission costs and Net Profits Interest Bonus Plan (“Net Profits Plan”) payments, was $125.2 million, of which $6.5 million was received as a deposit in December 2009. The final sale price is subject to normal post-closing adjustments and is expected to be finalized during the second half of 2010. The estimated gain on sale related to the divestiture is approximately $65.1 million and may be impacted by the forthcoming post-closing adjustments mentioned above. The Company determined that the sale does not qualify for discontinued operations accounting under Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 205, “Presentation of Financial Statements” (“ASC Topic 205”). A portion of the transaction was structured to qualify as a like-kind exchange under Section 1031 of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”).

Sequel Divestiture

In March 2010 the Company completed the divestiture of certain non-strategic oil properties located in North Dakota to Sequel Energy Partners, LP, Bakken Energy Partners, LLC, and Three Forks Energy Partners, LLC (collectively referred to as “Sequel”). The transaction had an effective date of November 1, 2009. Total cash received, before commission costs and Net Profits Plan payments, was $126.9 million. The final sale price is subject to normal post-closing adjustments and is expected to be finalized during the second half of 2010. The estimated gain on sale related to the divestiture is approximately $50.4 million and may be impacted by the forthcoming post-closing adjustments mentioned above. The Company determined that the sale does not qualify for discontinued operations accounting under ASC Topic 205. A portion of the transaction was structured to qualify as a like-kind exchange under Section 1031 of the Internal Revenue Code.

Assets Held for Sale

In accordance with FASB ASC Topic 360, “Property, Plant, and Equipment” (“ASC Topic 360”), 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 to determine if there is any excess of carrying value over fair value less costs to sell. Subsequent changes to estimated fair value less the cost to sell will impact the measurement of assets held for sale if the fair value is determined to be less than the carrying value of the assets.

As of June 30, 2010, the accompanying condensed consolidated balance sheets present $7.1 million in book value of assets held for sale, net of accumulated depletion, depreciation, and amortization. Additionally, the corresponding asset retirement obligation liability of $1.5 million is separately presented. The Company determined that these planned asset sales do not qualify for discontinued operations accounting under ASC Topic 205. Subsequent to June 30, 2010, the Company has completely divested of the assets held for sale.

Note 4 — Income Taxes

Income tax (expense) benefit for the six-month periods ended June 30, 2010, and 2009, 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 the domestic production activities deduction, percentage depletion, the effect of state income taxes, and other permanent differences. The provision for income taxes consists of the following:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2010			2009			2010			2009
	(In thousands)
Current portion of income tax (expense) benefit:
Federal	$	1,759		$	(2,166	)	$	(8,216	)	$	(3,249	)
State	21			(495		)	(311		)	(886		)
Deferred portion of income tax (expense) benefit	(14,212		)	7,758			(78,820		)	63,148
Total income tax (expense) benefit	$	(12,432	)	$	5,097		$	(87,347	)	$	59,013
Effective tax rate	40.8		%	38.0		%	37.7		%	38.1		%

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 between state tax jurisdictions resulting from Company activities. Non-core asset sales through June 30, 2010, and the Company’s anticipated drilling budget for the rest of 2010 applied against the Company’s cumulative temporary timing differences caused an increase in tax rate for the second quarter of 2010 when compared to the same period of 2009. The rate is also being impacted period to period as estimates for the domestic production activities deduction, percentage depletion and the impact of potential permanent state tax items affect the presented periods differently because of oil and gas price variability and the impact of non-core asset sales.

The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction and in various states. With few exceptions, the Company is no longer subject to U.S. federal or state income tax examinations by these tax authorities for years before 2006. In late 2009 the Internal Revenue Service announced a National Research Program (“NRP”) study of employment tax compliance that includes audits of randomly selected taxpayers for data collection purposes. During the first quarter of 2010, the Internal Revenue Service initiated an audit of SM Energy for the 2006 tax year focused primarily on compensation. In the second quarter of 2010 the Company determined its 2006 audit was not part of the NRP study. At June 30, 2010, the Company is awaiting a $5.5 million refund related to its 2006 tax year as a result of a net operating loss carry back from the Company’s 2008 tax year. This refund claim was combined with the audit discussed above and cannot be received until the audit is completed and submitted to the Joint Committee on Taxation (“JCT”) for review. The Company believes the 2006 audit will conclude in the third quarter of 2010 with no material adjustments, and its claim will be submitted to the JCT soon thereafter. The Company’s remaining refundable income tax balance at June 30, 2010, reflects its utilization of carry backs to claim a taxable net operating loss generated for the 2009 tax year against its 2005 taxable income. On July 20, 2010, the Company received $22.9 million relating to this carry back claim.

The Company’s 2005 federal income tax audit was concluded in the first quarter of 2009 with a refund to the Company of $278,000 plus interest of $41,000. There was no change to the provision for income tax expense as a result of the 2005 examination.

Note 5 — Earnings per Share

Basic net income or loss per common share of stock is calculated by dividing net income or loss available to common stockholders by the basic weighted-average common shares outstanding for the respective period. The shares represented by vested restricted stock units (“RSUs”) are included in the calculation of the basic weighted-average common shares outstanding. The earnings per share calculations reflect the impact of any repurchases of shares of common stock made by the Company.

Diluted net income or loss per common share of stock is calculated by dividing adjusted net income or loss by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted earnings per share calculation consist of unvested RSUs, in-the-money outstanding options to purchase the Company’s common stock, contingent Performance Share Awards (“PSAs”), and shares into which the 3.50% Senior Convertible Notes due 2027 (the “3.50% Senior Convertible Notes”) are convertible.

The Company’s 3.50% Senior Convertible Notes have a net-share settlement right whereby each $1,000 principal amount of notes may be surrendered for conversion to cash in an amount equal to the principal amount and, if applicable, 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. The treasury stock method is used to measure the potentially dilutive impact of shares associated with this conversion feature. The 3.50% Senior Convertible Notes have not been dilutive for any reporting period that they have been outstanding and therefore do not impact the diluted earnings per share calculation for the three-month and six-month periods ended June 30, 2010, and 2009.

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

The treasury stock method is used to measure the dilutive impact of stock options, RSUs, 3.50% Senior Convertible Notes, and PSAs. In accordance with FASB ASC Topic 260, “Earnings Per Share” when there is a loss from continuing operations, all potentially dilutive shares will be anti-dilutive. There were no dilutive shares for the three-month or six-month periods ended June 30, 2009, because the Company recorded a loss for each of those periods. Unvested RSUs, contingent PSAs, and in-the-money options had a dilutive impact for the three-month and six-month periods ended June 30, 2010, as calculated in the table below.

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

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2010		2009			2010		2009
	(In thousands, except per share amounts)

Net income (loss)	$	18,068	$	(8,322	)	$	144,246	$	(95,945	)
Basic weighted-average common stock outstanding	62,917		62,418			62,855		62,377
Add: dilutive effect of stock options, unvested RSUs, and contingent PSAs	1,649		—			1,638		—
Add: dilutive effect of 3.50% senior convertible notes	—		—			—		—
Diluted weighted-average common shares outstanding	64,566		62,418			64,493		62,377
Basic net income (loss) per common share	$	0.29	$	(0.13	)	$	2.29	$	(1.54	)
Diluted net income (loss) per common share	$	0.28	$	(0.13	)	$	2.24	$	(1.54	)

Note 6 — Commitments and Contingencies

In February 2010 the Company entered into an agreement whereby it is subject to certain natural gas gathering through-put commitments that require a minimum volume delivery of 100 Bcf by the end of the ten year contract term. As of June 30, 2010, the pipeline volume commitments associated with this agreement for the next five years and thereafter are presented below:

	Committed	Undiscounted
	Volumes	Cash Outflows
Years Ending December 31,	(In Bcf)	(In thousands)
2010	3.0	$	540
2011	6.0	1,080
2012	6.0	1,080
2013	10.0	1,800
2014	10.0	1,800
Thereafter	65.0	11,700
Total	100.0	$	18,000

On July 2, 2010, the Company entered into an agreement whereby it is subject to certain natural gas gathering through-put commitments during the ten year contract term. The Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments. In the event that no gas is delivered pursuant to the agreement, the aggregate deficiency payments will total $154.7 million over the life of the contract.

Note 7 — Compensation Plans

Cash Bonus Plan

During the first quarters of 2010 and 2009, the Company paid $7.7 million and $6.0 million for cash bonuses earned in the 2009 and 2008 performance years, respectively. Within the general and administrative expense and exploration expense line items in the accompanying condensed consolidated statements of operations is $2.9 million of cash bonus expense related to the specific performance year for each of the three-month periods ended June 30, 2010, and 2009, and $6.0 million and $5.3 million for the six-month periods ended June 30, 2010, and 2009, respectively.

Performance Share Awards Under the Equity Incentive Compensation Plan

The PSAs represent the right to receive, upon settlement of the PSAs after the completion of the three-year performance period, a number of shares of the Company’s common stock that may be from zero to two times the number of PSAs granted on the award date, depending on the extent to which the Company’s performance criteria have been achieved and the extent to which the PSAs have vested. The performance criteria for the PSAs are based on a combination of the Company’s total shareholder return (“TSR”) for the performance period and the relative performance of the Company’s TSR compared with the TSR of an index of certain peer companies for the performance period.

Total stock-based compensation expense related to PSAs for the three-month periods ended June 30, 2010, and 2009, was $3.8 million and $1.1 million, respectively, and $7.4 million and $2.5 million for the six-month periods ended June 30, 2010, and 2009, respectively. As of June 30, 2010, there was $14.7 million of total unrecognized compensation expense related to unvested PSAs. The unrecognized compensation expense will be amortized through 2012.

A summary of the status and activity of PSAs for the six-month period ended June 30, 2010, is presented in the following table:

	PSAs		Weighted- Average Grant- Date Fair Value
Non-vested, at January 1, 2010	1,069,090		$	32.52
Granted	—		$	—
Vested	(8,128	)	$	30.50
Forfeited	(87,527	)	$	31.73
Non-vested and outstanding, at June 30, 2010	973,435		$	32.61

Subsequent to June 30, 2010, the Company granted 387,651 PSAs as part of its regular annual compensation process. These PSAs will vest 1/7th on July 1, 2011, 2/7ths on July 1, 2012, and 4/7ths on July 1, 2013.

Restricted Stock Unit Incentive Program Under the Equity Incentive Compensation Plan

Total RSU compensation expense for both the three-month periods ended June 30, 2010, and 2009, was $1.7 million, and $3.5 million and $3.8 million for the six-month periods ended June 30, 2010, and 2009, respectively. As of June 30, 2010, there was $5.4 million of total unrecognized compensation expense related to unvested RSU awards. The unrecognized compensation expense will be amortized through 2012.

During the first half of 2010, the Company settled 51,115 RSUs that relate to awards granted in 2008 and 2007 through the issuance of shares of the Company’s common stock in accordance with the terms of the RSU awards. The Company and the majority of the grant participants mutually agreed to net-share settle the awards to cover income and payroll tax withholdings as provided for in the plan document and the award agreements. As a result, the Company issued 34,588 shares of common stock associated with these grants. The remaining 16,527 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon the delivery of the shares underlying those RSUs.

A summary of the status and activity of RSUs for the six-month period ended June 30, 2010, is presented in the following table:

	RSUs		Weighted- Average Grant- Date Fair Value
Non-vested, at January 1, 2010	407,123		$	34.67
Granted	—		$	—
Vested	(49,882	)	$	36.23
Forfeited	(26,877	)	$	36.48
Non-vested and outstanding, at June 30, 2010	330,364		$	34.28

Subsequent to June 30, 2010, the Company granted 126,821 RSUs as part of its regular annual compensation process. Each RSU represents a right to receive one share of the Company’s common stock

to be delivered upon settlement of the vested RSUs. These RSUs will vest 1/7th on July 1, 2011, 2/7ths on July 1, 2012, and 4/7ths on July 1, 2013.

Stock Option Grants Under Prior Stock Option Plans

The following table summarizes stock option activity for the six months ended June 30, 2010:

	Options		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (In years)	Aggregate Intrinsic Value (In thousands)

Outstanding, at January 1, 2010	1,274,920		$	13.31
Exercised	(148,902	)	$	14.22
Forfeited	—		$	—
Outstanding, end of period	1,126,018		$	13.19	2.6	$	30,369
Vested, or expect to vest, at end of period	1,126,018		$	13.19	2.6	$	30,369
Exercisable, end of period	1,126,018		$	13.19	2.6	$	30,369

As of June 30, 2010, there was no unrecognized compensation expense related to stock option awards.

Director Shares

In May 2010 and 2009 the Company issued 24,258 and 50,094 shares, respectively, of the Company’s common stock from treasury to the Company’s non-employee directors. The shares were issued pursuant to the Company’s Equity Incentive Compensation Plan. The Company recorded $690,000 and $517,000 of compensation expense for the three-month periods ended June 30, 2010, and 2009, respectively, and $715,000 and $636,000 for the six-month periods ended June 30, 2010, and 2009, respectively.

Employee Stock Purchase Plan

Under the Company’s Employee Stock Purchase Plan (the “ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation. 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, and shares issued under the ESPP are restricted for a period of six months from the date issued. The ESPP is intended to qualify under Section 423 of the Internal Revenue Code. The Company has set aside 2,000,000 shares of its common stock to be available for issuance under the ESPP, of which 1,440,819 shares are available for issuance as of June 30, 2010. The fair value of ESPP grants is measured at the date of grant using the Black-Scholes option-pricing model. There were 27,456 and 49,767 shares issued under the ESPP during the first half of 2010 and 2009, respectively. The Company expensed $124,000 and $390,000 for the three-month periods ended June 30, 2010, and 2009, respectively, and $263,000 and $541,000 for the six-month periods ended June 30, 2010, and 2009, respectively, based on the estimated fair values on the respective grant dates.

Net Profits Plan

Prior to 2008, all oil and gas wells that were completed or acquired during each year were assigned to a specific pool for that respective year under the Company’s legacy Net Profits Plan. Key employees become entitled to payments under the Net Profits Plan after the Company has received net cash flows

returning 100 percent of all costs associated with a pool. Thereafter, ten percent of future net cash flows generated by the pool are allocated among the participants and distributed at least annually. The portion of net cash flows from the pool to be allocated among the participants increases to 20 percent after the Company has recovered both 200 percent of the total costs for the pool and 100 percent of pool payments made under the Net Profits Plan at the ten percent level. The 2007 Net Profits Plan pool was the last pool established by the Company.

Cash payments made or accrued under the Net Profits Plan that have been recorded as either general and administrative expense or exploration expense are detailed in the table below:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2010		2009		2010		2009
	(In thousands)

General and administrative expense	$	5,381	$	4,541	$	12,315	$	7,774
Exploration expense	667		471		1,258		876
Total	$	6,048	$	5,012	$	13,573	$	8,650

Additionally, the Company made cash payments under the Net Profits Plan of $1.9 million and $20.1 million for the three-month and six-month periods ended June 30, 2010, respectively, as a result of sales proceeds mainly from the Legacy and Sequel divestitures. The cash payments are accounted for as a reduction of proceeds, which reduced the gain (loss) on divestiture activity in the accompanying condensed consolidated statements of operations. There were no cash payments made under the Net Profits Plan as a result of divestitures that occurred during the first half of 2009.

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 condensed consolidated 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. The table below presents the estimated allocation of the change in the liability if the Company did allocate the adjustment to these specific functional line items based on the current allocation of actual distributions made by the Company. As time progresses, less of the distributions relate to prospective exploration efforts as more of the distributions are made to participants that have terminated employment and do not provide ongoing exploration support to the Company.

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2010			2009		2010			2009
	(In thousands)

General and administrative expense (benefit)	$	(5,959	)	$	1,964	$	(32,604	)	$	(18,730	)
Exploration expense (benefit)	(640		)	485		(1,267		)	(2,112		)
Total	$	(6,599	)	$	2,449	$	(33,871	)	$	(20,842	)

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 Plans

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2010			2009			2010			2009
	(In thousands)
Service cost	$	848		$	625		$	1,696		$	1,250
Interest cost	280			233			560			467
Expected return on plan assets	(159		)	(107		)	(318		)	(215		)
Amortization of net actuarial loss	91			93			182			186
Net periodic benefit cost	$	1,060		$	844		$	2,120		$	1,688

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 or the market-related value of assets are amortized over the average remaining service period of active participants.

Contributions

Under the Pension Protection Act of 2006, SM Energy is not required to make a minimum contribution to the pension plans in 2010.

Note 9 — Asset Retirement Obligations

The Company recognizes an estimated liability for future costs associated with the plugging and abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and a corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is completed or acquired. The increase in carrying value is included in proved oil and gas properties in the accompanying condensed consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties. Cash paid to settle asset retirement obligations is included in the operating section of the Company’s accompanying condensed consolidated statements of cash flows.

The Company’s estimated asset retirement obligation liability is based on estimated economic lives, historical experience in plugging and abandoning wells, estimated cost to plug and abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount the Company’s abandonment liabilities range from 6.5 percent to 12.0 percent. Revisions to the liability could occur due to changes in estimated abandonment costs or well commerciality, or if federal or state regulators enact new requirements regarding the abandonment of wells. The asset retirement obligation is considered settled when the well has been plugged and abandoned or divested.

A reconciliation of the Company’s asset retirement obligation liability is as follows:

	For the Six Months Ended June 30, 2010
	(In thousands)

Beginning asset retirement obligation	$	102,080
Liabilities incurred	1,373
Liabilities settled	(24,583		)
Accretion expense	2,845
Revision to estimated cash flow	(715		)
Ending asset retirement obligation	$	81,000

As of June 30, 2010, the Company had $1.5 million of asset retirement obligation associated with the oil and gas properties held for sale included in a separate line item on the Company’s accompanying condensed consolidated balance sheets. Additionally, as of June 30, 2010, accounts payable and accrued expenses contained $15.2 million related to the Company’s current asset retirement obligation liability associated with the estimated retirement of some of the Company’s offshore platforms.

Note 10 — Derivative Financial Instruments

Oil, Natural Gas and NGL Commodity Hedges

To mitigate a portion of the exposure to potentially adverse market changes in oil and gas prices and the associated impact on cash flows, the Company has entered into various derivative contracts. The Company’s derivative contracts in place include swap and collar arrangements for oil, natural gas, and natural gas liquids (“NGLs”). As of June 30, 2010, the Company has hedge contracts in place through the first quarter of 2013 for a total of approximately 5 million Bbls of anticipated crude oil production, 46 million MMBtu of anticipated natural gas production, and 2 million Bbls of anticipated natural gas liquids production. As of July 28, 2010, the Company has hedge contracts in place through the second quarter of 2013 for a total of approximately 6 million Bbls of anticipated crude oil production, 50 million MMBtu of anticipated natural gas production, and 2 million Bbls of anticipated natural gas liquids production.

The Company attempts to qualify its oil, natural gas, and NGL derivative instruments as cash flow hedges for accounting purposes under FASB ASC Topic 815, “Derivatives and Hedging” (“ASC Topic 815”). The Company formally documents all relationships between the derivative instruments and the hedged production, as well as the Company’s risk management objective and strategy for the particular derivative contracts. This process includes linking all derivatives that are designated as cash flow hedges to the specific forecasted sale of oil, natural gas or NGLs. The Company also formally assesses (both at the derivative’s inception and on an ongoing basis) whether the derivatives being utilized have been highly effective in offsetting changes in the cash flows of hedged production and whether those derivatives may be expected to remain highly effective in future periods. If it is determined that a derivative has ceased to be highly effective as a hedge, the Company will discontinue hedge accounting for that derivative prospectively. If hedge accounting is discontinued and the derivative remains outstanding, the Company will recognize all subsequent changes in its fair value in the Company’s consolidated statements of operations for the period in which the change occurs. As of June 30, 2010, all oil, natural gas, and NGL derivative instruments qualified as cash flow hedges for accounting purposes. The Company anticipates that all forecasted transactions will occur by the end of their originally specified periods. All contracts are entered into for other-than-trading purposes.

The Company’s oil, natural gas, and NGL hedges are measured at fair value and are included in the accompanying condensed consolidated balance sheets as derivative assets and liabilities. The Company

derives internal valuation estimates taking into consideration the counterparties’ credit worthiness, the Company’s credit worthiness, and the time value of money. Those internal valuations are then compared to the counterparties’ mark-to-market statements. The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments. The derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, natural gas, and NGL derivative markets are highly active. The fair value of oil, natural gas, and NGL derivative contracts designated and qualifying as cash flow hedges under ASC Topic 815 was a net asset of $13.7 million and a net liability of $80.9 million at June 30, 2010, and December 31, 2009, respectively.

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

	Location on Consolidated Balance Sheets	Fair Value at June 30, 2010			Fair Value at December 31, 2009
		(In thousands)
Derivative assets designated as cash flow hedges:
Oil, natural gas, and NGL commodity	Current assets	$	45,481		$	30,295
Oil, natural gas, and NGL commodity	Other noncurrent assets	30,169			8,251
Total derivative assets designated as cash flow hedges under ASC Topic 815		$	75,650		$	38,546

Derivative liabilities designated as cash flow hedges:
Oil, natural gas, and NGL commodity	Current liabilities	$	(37,903	)	$	(53,929	)
Oil, natural gas, and NGL commodity	Noncurrent liabilities	(24,046		)	(65,499		)
Total derivative liabilities designated as cash flow hedges under ASC Topic 815		$	(61,949	)	$	(119,428	)

Realized gains or losses from the settlement of oil, natural gas, and NGL derivative contracts are reported in the total operating revenues and other income section of the accompanying condensed consolidated statements of operations. The Company realized a net gain of $9.3 million and $43.3 million from its oil, natural gas, and NGL derivative contracts for the three months ended June 30, 2010, and 2009, respectively, and realized a net gain of $11.9 million and $98.9 million from its oil, natural gas, and NGL derivative contracts for the six months ended June 30, 2010, and 2009, respectively.

After-tax changes in the fair value of derivative instruments designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributed to the hedged risk, are recorded in accumulated other comprehensive income in the accompanying condensed consolidated balance sheets until the hedged item is realized in earnings upon the sale of the associated hedged production. As of June 30, 2010, the amount of unrealized gain (loss) net of deferred income taxes to be reclassified from accumulated other comprehensive income to realized oil and gas hedge gain (loss) in the Company’s accompanying condensed consolidated statements of operations in the next twelve months is $11.3 million.

The Company seeks to minimize ineffectiveness by entering into oil derivative contracts indexed to the New York Mercantile Exchange West Texas Intermediate (“NYMEX WTI”) index, natural gas derivative contracts indexed to regional index prices associated with pipelines in proximity to the Company’s areas of production, and NGL derivative contracts indexed to Oil Price Information Service Mont Belvieu. The Company’s derivative contracts utilize the same respective indices or pricing points as

the Company’s sales contracts. As a result, the derivative contracts used by the Company are highly correlated with the underlying hedged production.

The following table details the effect of derivative instruments on other comprehensive income (loss) and the condensed consolidated balance sheets (net of income tax):

	Derivatives Qualifying as Cash Flow	For the Six Months Ended June 30,
	Hedges	2010			2009
		(In thousands)

Amount of (gain) loss on derivatives recognized in OCI during the period (effective portion)	Commodity hedges	$	(53,765	)	$	11,852
Amount of (gain) loss reclassified from AOCI to realized oil and gas hedge gain (loss) (effective portion)	Commodity hedges	$	(782	)	$	(45,494	)

Any change in fair value resulting from hedge ineffectiveness is recognized currently in unrealized derivative (gain) loss in the accompanying condensed consolidated statements of operations. The following table details the effect of derivative instruments on the condensed consolidated statements of operations:

(Gain) Loss Recognized in Earnings

Classification of

(Ineffective Portion)

(Gain) Loss

For the Three Months

For the Six Months

Derivatives Qualifying

Recognized in

Ended June 30,

as Cash Flow Hedges

Earnings

2010

2009

2010

2009

(In thousands)

Commodity hedges

Unrealized derivative (gain) loss

(2,087

)

11,288

(9,822

)

13,134

Credit Related Contingent Features

As of June 30, 2010, only one of the Company’s hedge counterparties was not a member of the Company’s credit facility bank syndicate. Member banks are secured by the Company’s oil and gas assets, and therefore do not require the Company to post collateral in instances where the Company is in a liability position. When the Company is in a liability position with a non-member bank, posting of collateral may be required if the Company’s liability balance exceeds the limit set forth in the agreement with the non-member bank. With the one non-member bank, the amount of collateral, if any, that the Company is required to post depends on a number of financial metrics that are calculated quarterly. No collateral was posted as of June 30, 2010, or July 28, 2010.

Convertible Note Derivative Instruments

The contingent interest provision of the 3.50% Senior Convertible Notes is an embedded derivative instrument. As of June 30, 2010, and December 31, 2009, the value of this derivative was determined to be immaterial.

Note 11 — Fair Value Measurements

The Company follows the authoritative accounting guidance under FASB ASC Topic 820, “Fair Value Measurements and Disclosures” (“ASC Topic 820”) for all assets and liabilities measured at fair value. ASC Topic 820 establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. ASC Topic 820 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. The topic establishes market or observable inputs as the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The topic establishes a hierarchy for grouping these assets and liabilities 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 and 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 financial assets and liabilities that are measured at fair value on a recurring basis and where they are classified within the hierarchy as of June 30, 2010:

	Level 1		Level 2		Level 3
	(In thousands)
Assets:
Derivatives	$	—	$	75,650	$	—
Liabilities:
Derivatives	$	—	$	61,949	$	—
Net Profits Plan	$	—	$	—	$	136,420

There were no nonfinancial assets or liabilities measured at fair value on a nonrecurring basis at June 30, 2010.

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 hierarchy as of December 31, 2009:

	Level 1		Level 2		Level 3
	(In thousands)
Assets:
Derivatives(a)	$	—	$	38,546	$	—
Proved oil and gas properties(b)	$	—	$	—	$	11,740
Materials inventory(b)	$	—	$	13,882	$	—
Liabilities:
Derivatives(a)	$	—	$	119,428	$	—
Net Profits Plan(a)	$	—	$	—	$	170,291

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

(b) This represents a nonfinancial 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 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 hierarchy.

Derivatives

The Company uses Level 2 inputs to measure the fair value of oil and gas hedges. 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.

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 may attempt to novate trades with parties deemed to have more risk on a relative basis to a more stable and less risky 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. The majority of the Company’s derivative counterparties are members of SM Energy’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 the requirements of ASC Topic 820 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.

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 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 and gas commodity prices and their impact on net cash flows and the amount of the Net Profits Plan liability. Generally, higher commodity prices result in a larger Net Profits Plan liability and vice versa.

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 a predominate number of the pools, a discount rate of 12 percent is used to calculate this liability. This rate is 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 price, cost assumptions, and the discount rates used in the calculations. The Company continually evaluates the assumptions used in this calculation in order to consider the current market environment for oil and gas prices, costs, discount rates, and overall market conditions. The Net Profits Plan liability was determined using price assumptions that were computed using five one-year strip prices with the fifth year’s pricing being carried out indefinitely. The average price was adjusted to include the effects of hedge prices for the percentage of forecasted production hedged 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 and natural gas commodity markets.

If the commodity prices used in the calculation changed by five percent, the liability recorded at June 30, 2010, would differ by approximately $11 million. A one percentage point increase in the discount rate would decrease the liability by approximately $6 million whereas a one percentage point decrease in the discount rate would increase the liability by $7 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 the 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 liabilities measured at fair value using Level 3 inputs:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2010			2009			2010			2009
	(In thousands)
Beginning balance	$	143,019		$	154,075		$	170,291		$	177,366
Net increase (decrease) in liability (a)	1,318			7,461			(218		)	(12,192		)
Net settlements (a)(b)	(7,917		)	(5,012		)	(33,653		)	(8,650		)
Transfers in (out) of Level 3	—			—			—			—
Ending balance	$	136,420		$	156,524		$	136,420		$	156,524

(a) Net changes in the Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the accompanying condensed consolidated statements of operations.

(b) Settlements represent cash payments made or accrued under the Net Profits Plan and include $1.9 million and $20.1 million of cash payments related primarily to the Legacy and Sequel divestitures for the three-month and six-month periods ending June 30, 2010, respectively. There were no cash payments made under the Net Profits Plan as a result of divestitures that occurred during the first half of 2009.

3.50% Senior Convertible Notes Due 2027

Based on the market price of the 3.50% Senior Convertible Notes, the estimated fair value of the notes was approximately $306 million and $290 million as of June 30, 2010, and December 31, 2009, respectively.

Proved Oil and Gas Properties

Proved oil and gas property costs are evaluated for impairment and reduced to fair value if the sum of the expected undiscounted future cash flows is less than net book value pursuant to ASC Topic 360. 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 discount rate is a rate that management believes is representative of current market conditions and includes the following factors: 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 price forecast is based on NYMEX strip pricing, adjusted for basis differentials, for the first five years. Future operating costs are also adjusted as deemed appropriate for these estimates.

In accordance with ASC Topic 820, of the $2.1 billion of long-lived assets, excluding materials inventory, $11.7 million were measured at fair value at December 31, 2009. There were no long-lived assets measured at fair value within the accompanying condensed consolidated balance sheets at June 30, 2010.

Asset Retirement Obligations

The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, “Asset Retirement and Environmental Obligations.” The income valuation technique is utilized by the Company to determine the fair value of the 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 within the accompanying consolidated balance sheets at June 30, 2010, or December 31, 2009.

Refer to Note 10 — Derivative Financial Instruments and Note 9 — Asset Retirement Obligations for more information regarding the Company’s hedging instruments and asset retirement obligations.

Note 12 — Recent Accounting Pronouncements

The Company partially adopted FASB ASC Update 2010-06, “Fair Value Measurements and Disclosures — Improving Disclosures about Fair Value Measurements” (“ASC Update 2010-06”) that requires additional disclosures surrounding transfers between Levels 1 and 2, inputs and valuation techniques used to value Level 2 and 3 measurements, and push down of previously prescribed fair value disclosures to each class of asset and liability for Levels 1, 2, and 3. These disclosures were effective for the Company for the quarter ended March 31, 2010. The partial adoption of this pronouncement did not have a material impact on the Company’s consolidated financial statements.

ASC Update 2010-06 also requires that purchases, sales, issuances, and settlements for Level 3 measurements be disclosed. This portion of the new authoritative guidance is effective for interim and annual reporting periods beginning after December 15, 2010. The Company will apply this new guidance in the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2011. The adoption of these portions of ASC Update 2010-06 are not expected to have a material impact on the Company’s financial statements.

The Company adopted FASB ASC Update 2010-09, “Subsequent Events - Amendments to Certain Recognition and Disclosure Requirements,” that removes the requirement for SEC filers to disclose the date through which an entity has evaluated subsequent events. However, the date-disclosure exemption does not relieve management of an SEC filer from its responsibility to evaluate subsequent events through the date on which financial statements are issued. This authoritative guidance was effective upon issuance on February 24, 2010. The adoption of this pronouncement did not have a material impact on the Company’s consolidated financial statements.

Note 13 — Carry and Earning Agreement

On April 29, 2010, the Company entered into a Carry and Earning Agreement (the “CEA”), which effectively provides for a third party to earn 95 percent of SM Energy’s interest in approximately 8,400 net acres in a portion of the Company’s East Texas Haynesville shale acreage, as well as an interest in several wells and five percent of SM Energy’s interest in approximately 23,400 net acres in a separate portion of the Company’s Haynesville acreage in East Texas. In exchange for these interests, the third party has agreed to invest $91.3 million to fund the drilling and completion costs of horizontal wells in the portion of the leases where the Company is retaining 95 percent of its current interest. Of this, $86.7 million represents SM Energy’s carried drilling and completion costs, being 95 percent of the total amount invested by the third party. The Company received an initial payment of $45.6 million on April 29, 2010, and the CEA provides that the Company will receive the balance of the committed funds less any adjustments allowed under the CEA for title defects within 30 days of the completion of the fourth commitment well. Once SM Energy has completed the expenditure of the total carry amount, the parties will share all costs of operations within the area of joint ownership in accordance with their respective ownership interests.

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 focused on the development, exploration, exploitation, acquisition, and production of natural gas, natural gas liquids, and crude oil in the continental United States. Generally, we generate nearly all our revenues and cash flows from the sale of produced natural gas and crude oil. In the first half of 2010 we have generated significant gains and cash proceeds from the sale of non-strategic oil and gas properties. Our oil and gas reserves and operations are concentrated primarily in the Rocky Mountain Williston Basin; the Mid-Continent Anadarko and Arkoma basins; the Permian Basin; the productive formations of East Texas and North Louisiana; north central Pennsylvania; the Maverick Basin in South Texas; and the onshore Gulf Coast. We have developed a balanced and diverse portfolio of proved reserves, development drilling opportunities, and unconventional resource prospects.

Our mission is to deliver outstanding net asset value per share growth to our investors via attractive oil and gas investments. Our strategy is to focus on early entrance into existing and emerging resource plays in North America. By entering these plays earlier, we believe that we can capture larger resource potential at lower cost. We believe this organic-centered model allows for more stable and predictable production and proved reserves growth.

Financial Standing and Liquidity

In the first quarter of 2010, the borrowing base on our credit facility was redetermined by our bank group and maintained at a value of $900 million despite the divestiture of non-strategic Rocky Mountain oil properties during the quarter. The commitment amount of the bank group remained unchanged at $678 million. At the end of the second quarter 2010 and through the filing date of this report, we had no outstanding borrowings under the revolving credit facility. We have no debt maturities until 2012, at which time our credit facility matures and our outstanding convertible notes can be put to us. Given our debt and asset levels, credit standing, and relationships with the participants in our bank group, we believe we will be able to extend or obtain a replacement credit facility before our current credit facility matures in 2012. We also believe our convertible notes could be put to us in 2012, at which time we have the option of settling with some combination of cash and/or common stock. The condition of the capital markets has improved significantly since last year, and therefore we believe we could access capital through the public markets, if necessary, to redeem these notes.

We expect our generated cash flows from operations in 2010 plus proceeds from our Rocky Mountain oil and other non-core asset divestitures to fund the majority of our capital budget for 2010. We plan to use our credit facility to fund the remaining balance of our capital program. Accordingly, we do not anticipate accessing the equity or public debt markets for the remainder of 2010. Given the size of and commitments associated with our existing inventory of potential drilling projects, our needs for capital could increase significantly in 2011 and beyond. As a result, we may consider accessing the capital markets, as well as other alternatives, as we determine how to best fund our capital program. We continue to believe we have adequate liquidity available as discussed under the caption Overview of Liquidity and Capital Resources.

Oil and Gas Prices

Our financial condition and the results of our operations are significantly affected by the prices we receive for oil, natural gas, and natural gas liquids, which can fluctuate dramatically. Please refer to Comparison of Financial Results and Trends between the three months ended June 30, 2010, and 2009 for our realized price tables. We sell a majority of our natural gas under contracts that use first of the month index pricing, which means that 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. We account for our natural gas sales as they occur at the wellhead and accordingly do not present a separate production stream for natural gas liquids that are processed from our natural gas production. We receive value for the NGL content in our natural gas stream, which can result in us realizing a higher per unit price for our reported gas production. Our crude oil is sold using contracts that pay us either the average of the NYMEX WTI daily settlement price or the average of alternative posted prices for the periods in which the crude oil is produced, adjusted for quality, transportation, and location differentials. The following table is a summary of commodity price data for the second quarters of 2010 and 2009 and the first quarter of 2010:

	For the Three Months Ended
	June 30, 2010		March 31, 2010		June 30, 2009
Crude Oil (per Bbl):
Average NYMEX price	$	77.88	$	78.84	$	59.69
Realized price, before the effects of hedging	$	70.92	$	72.73	$	53.96
Net realized price, including the effects of hedging	$	65.17	$	66.96	$	56.72
Natural Gas (per Mcf):
Average NYMEX price	$	4.33	$	5.09	$	3.71
Realized price, before the effects of hedging	$	4.54	$	6.15	$	3.07
Net realized price, including the effects of hedging	$	5.59	$	6.84	$	5.19

We expect future prices for oil, NGLs, and natural gas to be volatile. In addition to supply and demand fundamentals, the relative strength of the U.S. Dollar will likely continue to impact crude oil prices. Generally, NGL prices historically have trended and correlated with the price for crude oil. The supply of NGLs is expected to grow in the near term as a result of a number of industry participants targeting projects that produce these products, which could negatively impact future pricing. Future natural gas prices are facing downward pressure as a result of a perceived supply overhang resulting from increased levels of drilling activity across the country, as well as tepid demand recovery due to the recession. The 12-month strip prices for NYMEX WTI crude oil and NYMEX Henry Hub gas as of June 30, 2010, were $77.74 per Bbl and $5.07 per MMBTU, respectively. Comparable prices as of July 28, 2010, were $79.69 per Bbl and $4.99 per MMBTU, respectively.

While changes in quoted NYMEX oil and natural gas prices are generally used as a basis for comparison within our industry, the price we receive for oil and natural gas is affected by quality, energy content, location, and transportation differentials for these products. We refer to this price as our realized price, which excludes the effects of hedging. Our realized price is further impacted by the results of our hedging arrangements that are settled in the respective periods. We refer to this price as our net realized price. For the three months ended June 30, 2010, our net natural gas price realization was positively impacted by $17.4 million of realized hedge settlements and our net oil price realization was negatively impacted by $8.1 million of realized hedge settlements.

Hedging Activities

On July 21, 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act was enacted into law. This financial reform legislation includes provisions that require over-the-counter derivative transactions to be executed through an exchange or centrally cleared. In addition, the legislation provides an exemption from mandatory clearing requirements based on regulations to be developed by the Commodity Futures Trading Commission and the Securities and Exchange Commission for transactions by non-financial institutions to hedge or mitigate commercial risk. At the same time, the legislation includes provisions under which the CFTC may impose collateral requirements for transactions, including those that are used to hedge commercial risk. However, during drafting of the legislation, members of Congress adopted report language and issued a public letter stating that it was not their intention to impose margin and collateral requirements on counterparties that utilize transactions to hedge commercial risk. Final rules on major provisions in the legislation, like new margin requirements, will be established through rulemakings and will not take effect until 12 months after the date of enactment. Although we cannot predict the ultimate outcome of these rulemakings, new regulations in this area may result in increased costs and cash collateral requirements for the types of oil and gas derivative instruments we use to hedge and otherwise manage our financial risks related to volatility in oil and gas commodity prices.

Hedging is an important part of our financial risk management program. We have a Board-authorized financial risk management policy that governs our practices related to hedging. The amount of production we hedge is driven by the amount of debt on our consolidated balance sheet and the level of capital commitments and long-term obligations we have in place. In the case of a significant acquisition of producing properties, we will consider hedging a portion of the acquired production in order to protect the economics assumed in the acquisition. With the hedges we have in place, we believe we have established a base cash flow stream for our future operations, and our use of collars for a portion of the hedges allows us to participate in upward movements in oil and gas prices while also setting a price floor for a portion of our production. Please see Note 10 — Derivative Financial Instruments of Part I, Item 1 of this report for additional information regarding our oil and gas hedges, and see the caption, Summary of Oil and Gas Production Hedges in Place, later in this section.

We attempt to qualify our oil and gas derivative instruments as cash flow hedges for accounting purposes under ASC Topic 815. Changes in the value of our hedge positions are primarily reflected in our consolidated balance sheets. A portion of the change in the value of our hedge positions is recognized in our consolidated statements of operations due to hedges being partially ineffective at offsetting the fluctuations in cash flow due to change in the spot price for oil, natural gas and natural gas liquids. We recognized $2.1 million in non-cash unrealized derivative gain in the second quarter of 2010. Changes in the fair value of our hedge portfolio from March 31, 2010, through June 30, 2010, was primarily caused by decreases in prices of natural gas on the indexes on which we have hedges. As a result, our hedge position changed from a $22.4 million net liability at the end of the first quarter of 2010 to a $13.7 million net asset at the end of the second quarter of 2010. Corresponding changes are reflected in accumulated other comprehensive income on the consolidated balance sheets and unrealized derivative (gain) loss on the statement of operations.

Second Quarter 2010 Highlights

Operational activities. During the second quarter, we had an average of nine operated drilling rigs running company-wide. The thrust of our operated drilling activities this year has been focused on oil and NGL-rich gas programs and selected projects of potential strategic importance to the Company. Additionally, our operating partners have increased their levels of activity in oil and NGL-rich gas plays.

In the Eagle Ford shale in South Texas, we continued to operate two drilling rigs on our acreage during the second quarter. Our focus was on drilling in areas with higher MMBTU gas content and higher condensate yields. We have continued to test different ways to drill and complete these wells with the objective of optimizing our future development potential. Securing infrastructure to transport and process

production from the Eagle Ford has been an issue we have worked to address over the last year, particularly in recent months. Subsequent to quarter end, we entered into a gas services agreement whereby we committed a significant amount of production from the Eagle Ford to a ten year transportation and processing arrangement beginning in 2011. This agreement has shortfall penalties in the event that we are unable to deliver the committed volumes of gas. We are continuing to explore other arrangements to further address our infrastructure needs for this program. On our outside-operated acreage in the Eagle Ford, our operating partner has increased their rig count to six rigs at quarter-end, up from two rigs earlier in the year. This outside-operated acreage has limited infrastructure to support the development of the play and as a result we have been participating in the construction of infrastructure with our partner. The increase in partner-operated rigs and the infrastructure build-out have resulted in higher capital expenditures in this program than we initially planned for at the beginning of the year.

We operated an average of two drilling rigs in the Williston Basin during the second quarter of the year, both of which were focused on Bakken and Three Forks drilling. Our results in this program have met or exceeded expectations as several strong wells came online in the second quarter. Partners in the Williston Basin have steadily increased their activity during the second quarter. Elsewhere in the Rocky Mountain region, we drilled and completed our first operated horizontal well targeting the Niobrara formation in southeastern Wyoming. Interest in the Niobrara formation increased significantly during the first half of 2010 based on positive field reports coming out of the play. Our early results have been encouraging from this exploratory program.

In our Mid-Continent region, we drilled our first two wells in the horizontal Granite Wash in Beckham County in western Oklahoma. One of these wells was highly productive with strong condensate and NGL-rich gas contribution. Our acreage position is held by production and given the multiple productive formations in the play, we think the potential from this emerging program could be significant.

The Permian region ran two operated rigs in the second quarter, with the focus of the activity being on Wolfberry tight oil targets. In our operated Haynesville shale program, we had one or two drilling rigs operating in the play for most of the quarter and we are currently awaiting the completion of several wells. In the Marcellus shale, our first well in the play was turned to sales during the quarter and we continued to work on the gathering line that will service development of our acreage in McKean County, Pennsylvania.

Financial and production results. We recorded net income for the quarter ended June 30, 2010, of $18.1 million or $0.28 per diluted share compared to second quarter 2009 results of a net loss of $8.3 million or $0.13 per diluted share.

The table below details the regional breakdown of our second quarter 2010 production:

	Mid- Continent		ArkLaTex		South Texas & Gulf Coast		Permian		Rocky Mountain		Total (1)
Second Quarter 2010 Production:
Oil (MBbl)	45.9		20.7		181.0		438.2		726.3		1,412.2
Gas (MMcf)	7,894.3		3,170.5		3,147.5		1,074.1		1,390.8		16,677.3
Equivalent (MMCFE)	8,169.6		3,294.9		4,233.6		3,703.6		5,748.7		25,150.5
Avg. Daily Equivalents (MMCFE/d)	89.8		36.2		46.5		40.7		63.2		276.4
Relative percentage	32	%	13	%	17	%	15	%	23	%	100	%

(1) Totals may not add due to rounding

For the second quarter of 2010 our production performance was led by our Eagle Ford shale and Woodford shale programs. Both our operated and partner-operated programs targeting the Eagle Ford have contributed more production than anticipated this year. The Woodford shale program in the Arkoma Basin of eastern Oklahoma has not been a focus area for us this year, however stronger than projected base production performance has benefited our 2010 production. Please refer to Comparison of Financial Results and Trends between the three months ended June 30, 2010, and 2009 for additional discussion on production.

First Six Months 2010 Highlights

Legacy Divestiture. On February 17, 2010, we closed on a divestiture of non-core properties in Wyoming to Legacy Reserves Operating LP. Total cash received, before commission costs and Net Profits Plan payments, was $125.2 million. The final sale price is subject to normal post-closing adjustments and is expected to be finalized during the second half of 2010. The estimated gain on sale of proved properties related to the divestiture is approximately $65.1 million and may be impacted by the forthcoming post-closing adjustments mentioned above. We diverted a portion of the proceeds from this divestiture to restricted cash and will attempt to use these funds to acquire other properties in a like-kind exchange tax deferral strategy under Section 1031 of the Internal Revenue Code.

Sequel Divestiture. On March 12, 2010, we completed the divestiture of certain non-strategic properties located in North Dakota to Sequel Energy Partners, LP, Bakken Energy Partners, LLC, and Three Forks Energy Partners, LLC. Total cash received, before commission costs and Net Profits Plan payments, was $126.9 million. The final sale price is subject to normal post-closing adjustments and is expected to be finalized during the second half of 2010. The estimated gain on sale of proved properties related to the divestiture is approximately $50.4 million and may be impacted by the forthcoming post-closing adjustments mentioned above. We diverted a portion of the proceeds from this divestiture to restricted cash and will attempt to use these funds to acquire other properties in a like-kind exchange tax deferral strategy under Section 1031 of the Internal Revenue Code.

Net Profits Plan. In 2008, the Net Profits Plan was replaced with grants of performance shares and thus the 2007 Net Profits Plan pool was the last pool established by the Company. The Company will continue to make payments from the existing Net Profits Plan pools and will continue to make prospective adjustments to the long-term liability as necessary.

For the six months ended June 30, 2010, the change in the value of this liability resulted in a non-cash benefit of $33.9 million compared with a $20.8 million benefit for the same period in 2009. Current year payments made or accrued as part of allocating the proceeds received from the first half of 2010 divestitures have decreased the estimated liability for the future amounts to be paid to plan participants. This liability is a significant management estimate. Adjustments to the liability are subject to estimation and may change dramatically from period to period based on assumptions used for production rates, reserve quantities, commodity pricing, discount rates, tax rates, and production costs.

Payments made from the Net Profits Plan have been expensed as compensation costs in the amounts of $13.6 million and $8.7 million for the six months ended June 30, 2010, and 2009, respectively. Additionally, the above described sales of oil and gas properties were included in a number of profit pools and resulted in payments under the Net Profits Plan of $20.1 million during the first half of 2010. These cash payments are accounted for as a reduction of net sale proceeds and impact the gain on divestiture activity in the accompanying condensed consolidated statements of operations. There were no significant cash payments made or accrued under the Net Profits Plan as a result of divestitures during the first half of 2009.

The recurring Net Profits Plan cash payments we make are dependent on actual production, realized prices, and operating and capital costs associated with the properties in each individual pool. Actual cash payments will be inherently different from the estimated liability amounts. More detailed discussion is included in Note 11 — Fair Value Measurements in Part I, Item 1. An increasing percentage of the costs

associated with the payments under the Net Profits Plan are now being categorized as general and administrative expense as compared to exploration expense. This is a function of the normal departure of employees who previously contributed to our exploration efforts.

The calculation of the estimated liability for the Net Profits Plan is highly sensitive to our price estimates and discount rate assumptions. For example, if we changed the commodity prices in our calculation by five percent, the liability recorded on the balance sheet at June 30, 2010, would differ by approximately $11 million. A one percentage point increase in the discount rate would decrease the liability by approximately $6 million whereas a one percentage point decrease in the discount rate would increase the liability by $7 million. We frequently re-evaluate the assumptions used in our calculations and consider the possible impacts stemming from the current market environment including current and future oil and gas prices, discount rates, and overall market conditions.

Production results. The table below details the regional breakdown of our first half of 2010 production.

	Mid- Continent		ArkLaTex		South Texas & Gulf Coast		Permian		Rocky Mountain		Total (1)
First six months of 2010 Production:
Oil (MBbl)	107.2		40.2		317.8		884.0		1,588.5		2,937.7
Gas (MMcf)	16,247.1		6,275.2		5,795.5		2,023.4		2,902.7		33,243.9
Equivalent (MMCFE)	16,890.1		6,516.1		7,702.2		7,327.7		12,434.0		50,870.1
Avg. Daily Equivalents (MMCFE/d)	93.3		36.0		42.6		40.5		68.7		281.1
Relative percentage	33	%	13	%	15	%	14	%	25	%	100	%

(1) Totals may not add due to rounding

For the first half of 2010 our production has outperformed our expectations for 2010 due to stronger than anticipated production results from our South Texas & Gulf Coast and Mid-Continent regions. Please refer to the three months discussion under Financial and production results above and A three-month and six-month overview of selected production and financial information, including trends and Comparison of Financial Results and Trends between the six months ended June 30, 2010, and 2009 for additional discussion on production.

Outlook for the Remainder of 2010

Our development program entering 2010 was focused on the drilling of oil and rich gas projects. This decision has been reinforced as natural gas prices have been under downward pressure most of this year. We continue to evaluate ways to shift capital away from natural gas drilling wherever possible, except for activities necessary to satisfy leasehold commitments or to test emerging resource plays.

We are increasing our 2010 capital investment forecast to $871 million, up from $725 million. The increase in capital reflects the success we have seen in several of our plays this year, as well as an increase in costs throughout the industry to drill and complete wells. The largest portion of the increase relates to our non-operated acreage in the Eagle Ford shale, where our operating partner has increased their rig count to six rigs and we anticipate them going to an even higher rig count by year end. This portion of the play is in an area with higher condensate yields and a richer gas stream. The increase in our partner-operated rig count accounts for over $100 million of our increased capital investment when compared to our original budget. Additionally, related to this increase in partner-operated drilling is an increase in the requirement for infrastructure on our non-operated Eagle Ford

acreage. Accordingly, the revised capital expenditure forecast includes increased investments for facilities and infrastructure that will service development of this portion of our Eagle Ford shale position in the coming years.

We are adding a rig in our operated horizontal Granite Wash program where we now plan to drill seven operated wells this year, up from the four operated wells that we initially planned for the year. In the Williston Basin, recent success in our Bakken and Three Forks plays has resulted in an increase in this program’s capital budget. We plan to drill several more wells with our operated rigs, and have allocated additional capital to account for increased levels of partner-operated activity in the Williston Basin. The balance of our capital program remains relatively consistent with our original budget. We have remained flexible with respect to deployment of our exploration capital. Based on early encouraging data from our Niobrara test, we have reallocated capital toward this program for later in the year and are currently looking for a rig to drill a second test well. We plan on operating two drilling rigs in the East Texas portion of our Haynesville shale position for the remainder of 2010 and we currently have two wells waiting on completion. Our activity level in the Haynesville has not changed significantly from what we planned at the beginning of the year, although our amount of capital investment was substantially reduced as a result of the carry and earning agreement we entered into in the second quarter of 2010.

Financial Results of Operations and Additional Comparative Data

The table below provides information regarding selected production and financial information for the quarter ended June 30, 2010, and the immediately preceding three quarters. Additional details of per MCFE costs are presented later in this section.

For the Three Months Ended

June 30,

March 31,

December 31,

September 30,

2010

2009

(In millions, except production sales data)

Production (BCFE)

25.2

25.7

26.1

26.4

Oil and gas production revenue, excluding the effects of hedging