10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2011

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission File Number: 001-33784

SANDRIDGE ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware	20-8084793
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
123 Robert S. Kerr Avenue Oklahoma City, Oklahoma	73102
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code:

(405) 429-5500

Former name, former address and former fiscal year, if changed since last report: Not applicable

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨

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

Large accelerated filer	þ	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  þ

The number of shares outstanding of the registrant’s common stock, par value $0.001 per share, as of the close of business on July 29, 2011, was 412,428,752.

SANDRIDGE ENERGY, INC.

FORM 10-Q

Quarter Ended June 30, 2011

INDEX

PART I. FINANCIAL INFORMATION
ITEM 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Operations	5
	Condensed Consolidated Statement of Changes in Equity	6
	Condensed Consolidated Statements of Cash Flows	7
	Notes to Condensed Consolidated Financial Statements	8
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	46
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	64
ITEM 4.	Controls and Procedures	66
PART II. OTHER INFORMATION
ITEM 1.	Legal Proceedings	67
ITEM 1A.	Risk Factors	67
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	68
ITEM 6.	Exhibits	68

2

DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (“Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements express a belief, expectation or intention and generally are accompanied by words that convey projected future events or outcomes. These forward-looking statements may include projections and estimates concerning capital expenditures, our liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, elements of our business strategy and other statements concerning our operations, economic performance and financial condition. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal,” “should,” “intend” or other words that convey the uncertainty of future events or outcomes. We have based these forward-looking statements on our current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including the risk factors discussed in Item 1A of Part II of this Quarterly Report and in Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2010 (the “2010 Form 10-K”). The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on our company, business or operations. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statements.

3

PART I. Financial Information

ITEM 1. Financial Statements

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except per share data)

	June 30, 2011			December 31, 2010
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	4,615		$	5,863
Accounts receivable, net		162,976			146,118
Derivative contracts		2,513			5,028
Inventories		7,571			3,945
Other current assets		12,897			14,636
Total current assets		190,572			175,590
Oil and natural gas properties, using full cost method of accounting
Proved		8,552,148			8,159,924
Unproved		624,668			547,953
Less: accumulated depreciation, depletion and impairment		(4,625,330	)		(4,483,736	)
		4,551,486			4,224,141
Other property, plant and equipment, net		519,364			509,724
Restricted deposits		27,902			27,886
Goodwill		235,396			234,356
Other assets		71,954			59,751
Total assets	$	5,596,674		$	5,231,448
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt	$	1,019		$	7,293
Accounts payable and accrued expenses		423,971			376,922
Billings and estimated contract loss in excess of costs incurred		41,232			31,474
Derivative contracts		149,374			103,409
Asset retirement obligation		25,360			25,360
Total current liabilities		640,956			544,458
Long-term debt		2,892,434			2,901,793
Derivative contracts		162,057			124,173
Asset retirement obligation		93,780			94,517
Other long-term obligations		10,762			19,024
Total liabilities		3,799,989			3,683,965
Commitments and contingencies (Note 15)
Equity
SandRidge Energy, Inc. stockholders’ equity
Preferred stock, $0.001 par value, 50,000 shares authorized
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at June 30, 2011 and December 31, 2010; aggregate liquidation preference of $265,000		3			3
6.0% Convertible perpetual preferred stock; 2,000 shares issued and outstanding at June 30, 2011 and December 31, 2010; aggregate liquidation preference of $200,000		2			2
7.0% Convertible perpetual preferred stock; 3,000 shares issued and outstanding at June 30, 2011 and December 31, 2010; aggregate liquidation preference of $300,000		3			3
Common stock, $0.001 par value, 800,000 shares authorized; 410,498 issued and 409,918 outstanding at June 30, 2011 and 406,830 issued and 406,360 outstanding at December 31, 2010		398			398
Additional paid-in capital		4,550,689			4,528,912
Treasury stock, at cost		(4,525	)		(3,547	)
Accumulated deficit		(3,109,725	)		(2,989,576	)
Total SandRidge Energy, Inc. stockholders’ equity		1,436,845			1,536,195
Noncontrolling interest		359,840			11,288
Total equity		1,796,685			1,547,483
Total liabilities and equity	$	5,596,674		$	5,231,448

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

4

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
				(Unaudited)
Revenues
Oil and natural gas	$	312,111		$	149,995		$	579,053		$	319,580
Drilling and services		28,537			3,901			49,571			9,661
Midstream and marketing		16,313			22,598			38,570			50,587
Other		7,813			5,945			10,427			13,606
Total revenues		364,774			182,439			677,621			393,434
Expenses
Production		81,834			56,009			155,791			106,281
Production taxes		12,666			5,404			23,242			10,242
Drilling and services		18,058			1,024			33,099			8,233
Midstream and marketing		15,873			19,779			38,156			45,285
Depreciation and depletion — oil and natural gas		76,186			54,319			150,072			106,597
Depreciation and amortization — other		13,275			11,820			26,368			24,123
General and administrative		37,678			33,865			72,091			65,539
(Gain) loss on derivative contracts		(169,988	)		(119,621	)		107,640			(181,573	)
(Gain) loss on sale of assets		(524	)		388			(725	)		84
Total expenses		85,058			62,987			605,734			184,811
Income from operations		279,716			119,452			71,887			208,623
Other income (expense)
Interest income		38			98			43			167
Interest expense		(61,725	)		(64,259	)		(121,167	)		(126,348	)
Loss on extinguishment of debt		(2,051	)		—			(38,232	)		—
Other income (expense), net		138			(530	)		1,335			706
Total other expense		(63,600	)		(64,691	)		(158,021	)		(125,475	)
Income (loss) before income taxes		216,116			54,761			(86,134	)		83,148
Income tax (benefit) expense		(7,054	)		150			(6,967	)		162
Net income (loss)		223,170			54,611			(79,167	)		82,986
Less: net income attributable to noncontrolling interest		13,154			1,096			13,161			2,234
Net income (loss) attributable to SandRidge Energy, Inc.		210,016			53,515			(92,328	)		80,752
Preferred stock dividends		13,881			8,631			27,821			17,263
Income available (loss applicable) to SandRidge Energy, Inc. common stockholders	$	196,135		$	44,884		$	(120,149	)	$	63,489
Earnings (loss) per share
Basic	$	0.49		$	0.22		$	(0.30	)	$	0.31
Diluted	$	0.42		$	0.21		$	(0.30	)	$	0.31
Weighted average number of common shares outstanding
Basic		398,435			203,839			398,343			203,831
Diluted		495,982			259,566			398,343			226,406

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

5

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(In thousands)

	SandRidge Energy, Inc. Stockholders																		Noncontrolling Interest			Total
	Convertible Perpetual Preferred Stock				Common Stock					Additional Paid-In Capital			Treasury Stock			Accumulated Deficit
	Shares		Amount		Shares			Amount
										(Unaudited)
Six months ended June 30, 2011
Balance, December 31, 2010		7,650	$	8		406,360		$	398	$	4,528,912		$	(3,547	)	$	(2,989,576	)	$	11,288		$	1,547,483
Issuance of units by SandRidge Mississippian Trust I		—		—		—			—		—			—			—			336,892			336,892
Distributions to noncontrolling interest owners		—		—		—			—		—			—			—			(1,501	)		(1,501	)
Stock issuance expense		—		—		—			—		(231	)		—			—			—			(231	)
Purchase of treasury stock		—		—		—			—		—			(4,984	)		—			—			(4,984	)
Retirement of treasury stock		—		—		—			—		(4,984	)		4,984			—			—			—
Stock purchases — retirement plans, net of distributions		—		—		(110	)		—		1,998			(978	)		—			—			1,020
Stock-based compensation		—		—		—			—		24,987			—			—			—			24,987
Stock-based compensation excess tax benefit		—		—		—			—		7			—			—			—			7
Issuance of restricted stock awards, net of cancellations		—		—		3,668			—		—			—			—			—			—
Net (loss) income		—		—		—			—		—			—			(92,328	)		13,161			(79,167	)
Convertible perpetual preferred stock dividends		—		—		—			—		—			—			(27,821	)		—			(27,821	)
Balance, June 30, 2011		7,650	$	8		409,918		$	398	$	4,550,689		$	(4,525	)	$	(3,109,725	)	$	359,840		$	1,796,685

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

6

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Six Months Ended June 30,
	2011			2010
	(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income	$	(79,167	)	$	82,986
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Provision for doubtful accounts		1,596			84
Inventory obsolescence		20			124
Depreciation, depletion and amortization		176,440			130,720
Debt issuance costs amortization		5,748			5,121
Discount amortization on long-term debt		1,162			1,049
Loss on extinguishment of debt		38,232			—
Deferred income taxes		(6,986	)		—
Unrealized loss (gain) on derivative contracts		79,350			(12,776	)
(Gain) loss on sale of assets		(725	)		84
Investment (income) loss		(67	)		261
Stock-based compensation		18,301			14,218
Changes in operating assets and liabilities		27,100			36,588
Net cash provided by operating activities		261,004			258,459
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment		(871,901	)		(427,336	)
Proceeds from sale of assets		369,251			6,042
Refunds of restricted deposits		—			5,095
Net cash used in investing activities		(502,650	)		(416,199	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings		1,725,000			841,914
Repayments of borrowings		(1,741,795	)		(662,869	)
Premium on debt redemption		(30,338	)		—
Debt issuance costs		(19,640	)		(11,546	)
Proceeds from issuance of units by SandRidge Mississippian Trust I		336,892			—
Noncontrolling interest distributions		(1,501	)		(1,506	)
Noncontrolling interest contributions		—			157
Stock issuance expense		(231	)		(87	)
Stock-based compensation excess tax benefit		7			14
Purchase of treasury stock		(6,030	)		(2,852	)
Dividends paid — preferred		(28,980	)		(11,263	)
Derivative settlements		7,014			—
Net cash provided by financing activities		240,398			151,962
NET DECREASE IN CASH AND CASH EQUIVALENTS		(1,248	)		(5,778	)
CASH AND CASH EQUIVALENTS, beginning of year		5,863			7,861
CASH AND CASH EQUIVALENTS, end of period	$	4,615		$	2,083
Supplemental Disclosure of Noncash Investing and Financing Activities
Change in accrued capital expenditures	$	2,351		$	50,209
Convertible perpetual preferred stock dividends payable	$	16,572		$	14,447
Adjustment to oil and natural gas properties for estimated contract loss	$	19,000		$	—

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

7

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

Nature of Business. SandRidge Energy, Inc. (including its subsidiaries, the “Company” or “SandRidge”) is an independent oil and natural gas company concentrating on development and production activities related to the exploitation of its significant holdings in West Texas and the Mid-Continent area of Oklahoma and Kansas. The Company’s primary areas of focus are the Permian Basin in West Texas, the Mississippian formation in the Mid-Continent and the West Texas Overthrust (“WTO”). The Company owns and operates other interests in the Mid-Continent, Cotton Valley Trend in East Texas, Gulf Coast and Gulf of Mexico. The Company also operates businesses that are complementary to its primary development and production activities, including gas gathering and treating facilities, a gas marketing business, an oil field services business, including a drilling rig business, and tertiary oil recovery operations.

Interim Financial Statements. The accompanying condensed consolidated financial statements as of December 31, 2010 have been derived from the audited financial statements contained in the Company’s 2010 Form 10-K. The unaudited interim condensed consolidated financial statements have been prepared by the Company in accordance with the accounting policies stated in the audited consolidated financial statements contained in the 2010 Form 10-K. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted, although the Company believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the information in the Company’s unaudited condensed consolidated financial statements have been included. These condensed consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in the 2010 Form 10-K.

Risks and Uncertainties. The Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, each of which depends on numerous factors beyond the Company’s control such as economic conditions, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile, and may be subject to significant fluctuations in the future. The Company’s derivative arrangements serve to mitigate a portion of the effect of this price volatility on the Company’s cash flows, and while derivative contracts are in place for the majority of expected oil production for 2011 through 2013, fixed price swap contracts are in place for only a portion of expected natural gas production in 2011 and 2012 and oil production for 2014 and 2015. No fixed price swap contracts are in place for the Company’s natural gas production beyond 2012 or oil production beyond 2015. The Company has natural gas collars in place for a portion of expected natural gas production through 2015. See Note 12 for the Company’s open oil and natural gas commodity derivative contracts.

The Company has incurred, and will have to continue to incur, capital expenditures to achieve production targets contained in certain gathering and treating arrangements. The Company depends on the availability of borrowings under its senior secured revolving credit facility (the “senior credit facility”), along with cash flows from operating activities and the proceeds from planned asset sales or other asset monetizations, to fund those capital expenditures. Based on anticipated oil and natural gas prices, availability under the senior credit facility, potential access to the capital markets and anticipated proceeds from sales or other monetizations of assets, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for 2011. However, a substantial or extended decline in oil or natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced, which could adversely impact the Company’s ability to comply with the financial covenants under its senior credit facility, which in turn would limit further borrowings to fund capital expenditures. See Note 11 for discussion of the financial covenants in the senior credit facility.

8

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

2. Recent Accounting Pronouncements

For a description of the Company’s significant accounting policies, refer to Note 1 of the consolidated financial statements included in the 2010 Form 10-K.

Recently Adopted Accounting Pronouncements. In January 2010, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update 2010-06, “Fair Value Measurements and Disclosures: Improving Disclosures about Fair Value Measurements” (“ASU 2010-06”). ASU 2010-06 requires additional disclosures and clarifies existing disclosure requirements about fair value measurement as set forth in Accounting Standards Codification (“ASC”) Topic 820, Fair Value Measurements and Disclosures. The new disclosure requirements regarding activity in Level 3 fair value measurements, which are effective for fiscal years beginning after December 15, 2010, were implemented in the first quarter of 2011 by the Company. The implementation of ASU 2010-06 had no impact on the Company’s financial position or results of operations. See Note 4.

Recent Accounting Pronouncement Not Yet Adopted. In May 2011, the FASB issued Accounting Standards Update 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS” (“ASU 2011-04”). ASU 2011-04 clarifies the FASB’s intent about the application of existing fair value measurements as set forth in ASC Topic 820 and requires additional disclosure information regarding valuation processes and inputs used. The new disclosure requirements are effective for interim and annual reporting periods beginning after December 15, 2011. As the additional requirements under ASU 2011-04, which will be implemented January 1, 2012, pertain to fair value measurement disclosures, no effect to the Company’s financial position or results of operations is expected.

3. Acquisitions and Divestitures

Arena Acquisition. On July 16, 2010, the Company acquired all of the outstanding common stock of Arena Resources, Inc. (“Arena”). In connection with the acquisition (the “Arena Acquisition”), the Company issued 4.7771 shares of its common stock and paid $4.50 in cash to Arena stockholders for each outstanding share of Arena unrestricted common stock. This resulted in the issuance of approximately 190.3 million shares of Company common stock and payment of approximately $177.9 million in cash for an aggregate estimated purchase price to stockholders of Arena equal to approximately $1.4 billion. The Company incurred approximately $0.2 million and $3.8 million in fees related to the acquisition during the three-month periods ended June 30, 2011 and 2010, respectively, and $0.6 million and $4.8 million in fees during the six-month periods ended June 30, 2011 and 2010, respectively, which have been included in general and administrative expenses in the accompanying condensed consolidated statements of operations.

In the second quarter of 2011, the Company completed its valuation of assets acquired and liabilities assumed related to the Arena Acquisition. Upon receipt of final confirmatory information for certain accruals in the second quarter of 2011 and completion of the 2010 Arena federal income tax return, the Company increased current assets, the net deferred tax liability and the value assigned to goodwill and reduced current liabilities. The accompanying condensed consolidated balance sheet at December 31, 2010 included certain preliminary allocations of the purchase price for the Arena Acquisition. During the first quarter of 2011, the Company updated certain estimates used in the purchase price allocation, primarily with respect to accruals, resulting in adjustments of $0.8 million to goodwill. Additional adjustments in the second quarter of 2011, primarily with respect to deferred taxes and other accruals, resulted in adjustments of $0.2 million to goodwill.

9

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

The following table summarizes the final valuation of assets acquired and liabilities assumed in connection with the Arena Acquisition (in thousands):

Current assets	$	83,563
Oil and natural gas properties(1)		1,587,630
Other property, plant and equipment		5,963
Deferred tax assets		48,997
Other long-term assets		16,181
Goodwill(2)		235,396
Total assets acquired		1,977,730
Current liabilities		38,964
Long-term deferred tax liability(2)		503,483
Other long-term liabilities		8,851
Total liabilities assumed		551,298
Net assets acquired	$	1,426,432

(1) Weighted average commodity prices utilized in the preliminary determination of the fair value of oil and natural gas properties were $105.58 per barrel of oil and $8.56 per Mcf of natural gas, after adjustment for transportation fees and regional price differentials. The prices utilized were based upon forward commodity strip prices, as of July 16, 2010, for the first four years and escalated for inflation at a rate of 2.5% annually beginning with the fifth year through the end of production, which was more than 50 years. Approximately 91.0% of the fair value allocated to oil and natural gas properties is attributed to oil reserves.

(2) The Company received carryover tax basis in Arena’s assets and liabilities because the merger was not a taxable transaction under the Internal Revenue Code (“IRC”). Based upon the final purchase price allocation, a step-up in basis related to the property acquired from Arena resulted in a net deferred tax liability of approximately $454.5 million, which in turn contributed to an excess of the consideration transferred to acquire Arena over the estimated fair value on the acquisition date of the net assets acquired, or goodwill. See Note 6 for further discussion of goodwill and Note 13 for further discussion of the net deferred tax liability.

The following unaudited pro forma results of operations are provided for the three and six-month periods ended June 30, 2010 as though the Arena Acquisition had been completed as of the beginning of each respective period. The pro forma information is based on the Company’s consolidated results of operations for the three and six-month periods ended June 30, 2010, Arena’s historical results of operations and estimates of the effect of the transaction on the combined results. The pro forma combined results of operations for the three and six-month periods ended June 30, 2010 have been prepared by adjusting the historical results of the Company to include the historical results of Arena, certain reclassifications to conform Arena’s presentation to the Company’s accounting policies and the impact of the purchase price allocation. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted from the acquisition or any estimated costs that have been incurred by the Company to integrate Arena. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors.

10

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

	Three Months Ended June 30, 2010				Six Months Ended June 30, 2010
	Actual		Pro Forma		Actual		Pro Forma
	(in thousands, except per share data)
Revenues	$	182,439	$	236,751	$	393,434	$	499,544
Income available to SandRidge Energy, Inc. common stockholders(1)	$	44,884	$	503,597	$	63,489	$	536,985
Earnings per common share
Basic	$	0.22	$	1.28	$	0.31	$	1.36
Diluted	$	0.21	$	1.14	$	0.31	$	1.23

(1) Pro forma columns reflect a $454.5 million reduction in tax expense related to the release of a portion of the Company’s valuation allowance on existing deferred tax assets.

Sale of Wolfberry Assets. In January 2011, the Company sold its Wolfberry assets in the Permian Basin for $153.8 million, net of fees and subject to post-closing adjustments. This asset sale was accounted for as an adjustment to the full cost pool with no gain or loss recognized.

Sale of New Mexico Assets. In April 2011, the Company sold certain oil and natural gas properties in Lea County and Eddy County, New Mexico, for approximately $198.5 million, net of fees and subject to post-closing adjustments. This asset sale was accounted for as an adjustment to the full cost pool with no gain or loss recognized.

4. Fair Value Measurements

The Company applies the guidance provided under ASC Topic 820 to its financial assets and liabilities and nonfinancial liabilities that are measured and reported on a fair value basis. Pursuant to this guidance, the Company has classified and disclosed its fair value measurements using the following levels of the fair value hierarchy:

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.

Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3: Measurement based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable for objective sources (i.e., supported by little or no market activity).

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels as described in ASC Topic 820. The determination of the fair values, stated below, takes into account the market for the Company’s financial assets and liabilities, the associated credit risk and other factors as required by ASC Topic 820. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company has assets and liabilities it has classified as Level 1 and Level 3, as described below. The Company did not have any assets or liabilities classified as Level 2 at June 30, 2011 or December 31, 2010.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Level 1 Fair Value Measurements

Restricted deposits. The fair value of restricted deposits invested in mutual funds or municipal bonds is based on quoted market prices. For restricted deposits held in savings accounts, carrying value is deemed to approximate fair value.

Other long-term assets. The fair value of other long-term assets, consisting of assets attributable to the Company’s deferred compensation plan, is based on quoted market prices.

Level 3 Fair Value Measurements

Derivative Contracts. The fair values of the Company’s oil and natural gas fixed price swaps, natural gas basis swaps, natural gas collars and interest rate swap are based upon quotes obtained from counterparties to the derivative contracts. The Company reviews other readily available market prices for its derivative contracts as there is an active market for these contracts. However, the Company does not have access to the specific valuation models used by its counterparties or other market participants. Included in these models are discount factors that the Company must estimate in its calculation. Additionally, the Company applies a weighted average credit default risk rating factor for its counterparties or gives effect to its credit risk, as applicable, in determining the fair value of its derivative contracts. Based on the inputs for the fair value measurement, the Company has classified its derivative contract assets and liabilities as Level 3.

The following tables summarize the Company’s financial assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy (in thousands):

June 30, 2011

	Fair Value Measurements						Netting(1)			Assets / Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Restricted deposits	$	27,902	$	—	$	—	$	—		$	27,902
Other long-term assets		4,908		—		—		—			4,908
Commodity derivative contracts		—		—		12,246		(9,733	)		2,513
	$	32,810	$	—	$	12,246	$	(9,733	)	$	35,323
Liabilities
Commodity derivative contracts	$	—	$	—	$	305,879	$	(9,733	)	$	296,146
Interest rate swap		—		—		15,285		—			15,285
	$	—	$	—	$	321,164	$	(9,733	)	$	311,431
December 31, 2010
	Fair Value Measurements						Netting(1)			Assets / Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Restricted deposits	$	27,886	$	—	$	—	$	—		$	27,886
Other long-term assets		4,826		—		—		—			4,826
Commodity derivative contracts		—		—		10,576		(5,548	)		5,028
	$	32,712	$	—	$	10,576	$	(5,548	)	$	37,740
Liabilities
Commodity derivative contracts	$	—	$	—	$	216,436	$	(5,548	)	$	210,888
Interest rate swaps		—		—		16,694		—			16,694
	$	—	$	—	$	233,130	$	(5,548	)	$	227,582

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

(1) Represents the impact of netting assets and liabilities with counterparties with which the right of offset exists.

The tables below set forth a reconciliation of the Company’s financial assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three and six-month periods ended June 30, 2011 and 2010 (in thousands):

	Three Months Ended June 30,
	2011									2010
	Commodity Derivative Contracts			Interest Rate Swaps			Total			Commodity Derivative Contracts			Interest Rate Swaps			Total
Balance of Level 3, March 31	$	(478,541	)	$	(14,929	)	$	(493,470	)	$	65,512		$	(12,147	)	$	53,365
Total realized and unrealized gains (losses)		169,988			(2,798	)		167,190			119,621			(6,477	)		113,144
Purchases		(3,353	)		—			(3,353	)		—			—			—
Settlements		18,273			2,442			20,715			(117,955	)		2,076			(115,879	)
Balance of Level 3, June 30	$	(293,633	)	$	(15,285	)	$	(308,918	)	$	67,178		$	(16,548	)	$	50,630

	Six Months Ended June 30,
	2011									2010
	Commodity Derivative Contracts			Interest Rate Swaps			Total			Commodity Derivative Contracts			Interest Rate Swaps			Total
Balance of Level 3, December 31	$	(205,860	)	$	(16,694	)	$	(222,554	)	$	46,153		$	(8,299	)	$	37,854
Total realized and unrealized (losses) gains		(107,640	)		(3,076	)		(110,716	)		181,573			(12,412	)		169,161
Purchases		(7,014	)		—			(7,014	)		—			—			—
Settlements		26,881			4,485			31,366			(160,548	)		4,163			(156,385	)
Balance of Level 3, June 30	$	(293,633	)	$	(15,285	)	$	(308,918	)	$	67,178		$	(16,548	)	$	50,630

During the three and six-month periods ended June 30, 2011 and 2010, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements.

See Note 12 for further discussion of the Company’s derivative contracts.

Fair Value of Debt

The Company measures the fair value of its long-term debt based on quoted market prices and also considers the effect of the Company’s credit risk. The estimated fair values of the Company’s senior notes and the carrying value at June 30, 2011 and December 31, 2010 were as follows (in thousands):

	June 30, 2011				December 31, 2010
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Floating Rate Notes due 2014	$	349,127	$	350,000	$	334,751	$	350,000
8.625% Senior Notes due 2015		—		—		663,181		650,000
9.875% Senior Notes due 2016(1)		406,146		353,619		394,527		352,707
8.0% Senior Notes due 2018		763,636		750,000		762,849		750,000
8.75% Senior Notes due 2020(2)		479,767		443,307		472,968		443,057
7.5% Senior Notes due 2021		909,203		900,000		—		—

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

(1) Carrying value is net of $11,881 and $12,793 discount at June 30, 2011 and December 31, 2010, respectively.

(2) Carrying value is net of $6,693 and $6,943 discount at June 30, 2011 and December 31, 2010, respectively.

The carrying values of the Company’s senior credit facility and remaining fixed rate debt instruments approximate fair value based on current rates applicable to similar instruments. See Note 11 for discussion of the Company’s long-term debt, including the purchase and redemption of all outstanding 8.625% Senior Notes due 2015 and the issuance of the 7.5% Senior Notes due 2021, which both occurred during 2011.

5. Property, Plant and Equipment

Property, plant and equipment consists of the following (in thousands):

	June 30, 2011			December 31, 2010
Oil and natural gas properties
Proved	$	8,552,148		$	8,159,924
Unproved		624,668			547,953
Total oil and natural gas properties		9,176,816			8,707,877
Less: accumulated depreciation, depletion and impairment		(4,625,330	)		(4,483,736	)
Net oil and natural gas properties capitalized costs		4,551,486			4,224,141
Land		14,192			14,418
Non oil and natural gas equipment(1)		674,211			666,233
Buildings and structures		106,711			89,813
Total		795,114			770,464
Less: accumulated depreciation and amortization		(275,750	)		(260,740	)
Net capitalized costs		519,364			509,724
Total property, plant and equipment, net	$	5,070,850		$	4,733,865

(1) Includes capitalized interest of approximately $5.2 million and $4.7 million at June 30, 2011 and December 31, 2010, respectively.

There were no full cost ceiling impairments during the three or six-month periods ended June 30, 2011 or 2010. Cumulative full cost ceiling limitation impairment charges of $3,548.3 million at both June 30, 2011 and December 31, 2010 were included in accumulated depreciation, depletion and impairment for oil and natural gas properties in the table above.

6. Goodwill

At June 30, 2011, the Company had $235.4 million of goodwill, including the effects of the $0.8 million and $0.2 million purchase price adjustments recorded in the first and second quarters of 2011, respectively, as a result of the excess consideration over the fair value of net assets acquired in the Arena Acquisition. Goodwill recorded in the Arena Acquisition is primarily attributable to operational and cost synergies expected to be realized from the acquisition by using the Company’s current presence in the Permian Basin, its Fort Stockton, Texas service base and its existing rig ownership to efficiently increase its drilling and oil production from Arena assets

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

acquired in the Central Basin Platform, as these assets have a proven production history. See Note 3 for additional discussion of the Arena Acquisition. The Company assigned all of the goodwill related to the Arena Acquisition to its exploration and production segment, which will be the reporting unit for impairment testing purposes. The Company will test goodwill for impairment annually on July 1, beginning in 2011. The Company monitors the existence of potential impairment indicators throughout the year. As of June 30, 2011, no such indicators were noted. Goodwill recognized is not deductible for tax purposes.

7. Other Assets

Other assets consist of the following (in thousands):

	June 30, 2011		December 31, 2010
Debt issuance costs, net of amortization	$	56,662	$	50,637
Investments		4,908		4,826
Other		10,384		4,288
Total other assets	$	71,954	$	59,751

8. Variable Interest Entities

In accordance with the guidance in ASC Topic 810, Consolidation, including the guidance in Accounting Standards Update 2009-17, “Consolidations—Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities” (“ASU 2009-17”), the Company consolidates the activities of variable interest entities (“VIEs”) of which it is the primary beneficiary. The primary beneficiary of a VIE is that variable interest holder possessing a controlling financial interest through (i) its power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE, the Company performs a qualitative analysis of the entity’s design, organizational structure, primary decision makers and related financial agreements.

The Company’s significant associated VIEs, including those for which the Company has determined it is the primary beneficiary and those for which it has determined it is not, are described below.

SandRidge Mississippian Trust I. On April 12, 2011, SandRidge Mississippian Trust I (the “Mississippian Trust”), a newly formed Delaware statutory trust, completed its initial public offering of 17,250,000 common units representing beneficial interests in the Mississippian Trust. Net proceeds to the Mississippian Trust, after certain offering expenses, were approximately $336.9 million. In conjunction with the closing, the Company conveyed certain royalty interests to the Mississippian Trust in exchange for the net proceeds of the Mississippian Trust’s initial public offering and 10,750,000 units (3,750,000 common units and 7,000,000 subordinated units) representing approximately 38.4% of the beneficial interest in the Mississippian Trust. The royalty interests conveyed to the Mississippian Trust are in certain oil and natural gas properties leased by the Company in the Mississippian formation in five counties in Northern Oklahoma. The conveyance of the royalty interests to the Mississippian Trust was recorded in April 2011 at the historical cost to the Company, or $309.0 million, and was determined by allocating the historical net book value of the Company’s full cost pool based on the fair value of the conveyed royalty interests relative to the fair value of the Company’s total full cost pool.

In order to provide support for cash distributions on the Mississippian Trust’s common units, SandRidge agreed to subordinate a portion of the Mississippian Trust units it owns (the “subordinated units”), which

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

constitute 25% of the total outstanding Mississippian Trust units. The subordinated units are entitled to receive pro rata distributions from the Mississippian Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is no less than the applicable quarterly subordination threshold. If there is not sufficient cash to fund such a distribution on all common units, the distribution to be made with respect to the subordinated units will be reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on all common units, including common units held by the Company.

SandRidge and one of its wholly owned subsidiaries entered into a development agreement with the Mississippian Trust that obligates the Company to drill, or cause to be drilled, a specified number of wells, which are also subject to the royalty interest, by December 31, 2014. In the event of delays, the Company will have until December 31, 2015 to fulfill its drilling obligation. At the end of the fourth full calendar quarter following satisfaction of the Company’s drilling obligation (the “subordination period”), the Company’s subordinated units will automatically convert into common units on a one-for-one basis and the Company’s right to receive incentive distributions will terminate. Incentive distributions are equal to 50% of the amount by which the cash available for distribution on all of the Mississippian Trust units for any quarter is 20% or greater than the target distribution for such quarter. One of the Company’s wholly owned subsidiaries also granted to the Mississippian Trust a lien in the Company’s interests in the properties where the development wells will be drilled, in order to secure the estimated amount of the drilling costs for the wells. As the Company fulfills its drilling obligation, the total amount that may be recovered by the Mississippian Trust will be proportionately reduced and completed development wells will be released from the lien. As of June 30, 2011, the maximum amount recoverable by the Mississippian Trust under the lien was $136.4 million. Additionally, the Company and the Mississippian Trust entered into an administrative services agreement, pursuant to which the Company provides certain administrative services to the Mississippian Trust, and a derivatives agreement, pursuant to which the Company passes to the Mississippian Trust the benefits and obligations of certain of the Company’s derivative contracts. The tables below present open oil and natural gas commodity derivative contracts at June 30, 2011, the benefits and obligations of which will be passed to the Mississippian Trust under the derivatives agreement. See Note 12 for further discussion of the derivatives agreement between the Company and the Mississippian Trust and a complete listing of the Company’s open commodity derivative contracts at June 30, 2011, including the derivative contracts the effects of which have been conveyed to the Mississippian Trust.

Oil

Period and Type of Contract	Notional (MBbl)		Weighted Avg. Fixed Price
July 2011 — December 2011
Price swap contracts		241	$	103.60
January 2012 — December 2012
Price swap contracts		454	$	104.15
January 2013 — December 2013
Price swap contracts		488	$	102.07
January 2014 — December 2014
Price swap contracts		541	$	100.94
January 2015 — December 2015
Price swap contracts		468	$	101.07

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Natural Gas

Period and Type of Contract	Notional (MMcf)(1)		Weighted Avg. Fixed Price		Collar Range
July 2011 — December 2011
Price swap contracts		2,086	$	4.61		—
January 2012 — June 2012
Price swap contracts		2,190	$	4.90		—
July 2012 — December 2012
Collars		402		—	$	4.00 - $6.20
January 2013 — December 2013
Collars		858		—	$	4.00 - $7.15
January 2014 — December 2014
Collars		937		—	$	4.00 - $7.78
January 2015 — December 2015
Collars		1,010		—	$	4.00 - $8.55

(1) Assumes ratio of 1:1 for Mcf to MMBtu.

The Mississippian Trust is considered a VIE due to the lack of voting or similar decision-making rights by its equity holders regarding activities that have a significant effect on the success of the Mississippian Trust. The Company’s ownership in the Mississippian Trust constitutes a variable interest. The Company has determined it is the primary beneficiary of the Mississippian Trust as it has (a) the power to direct the activities that most significantly impact the economic performance of the Mississippian Trust through (i) its participation in the creation and structure of the Mississippian Trust, (ii) the manner in which it fulfills its drilling obligation to the Mississippian Trust, and (iii) the manner in which it operates the Underlying Properties, and (b) through the end of the subordination period, the obligation to absorb losses and right to receive residual returns, through its ownership of the subordinated units, that could potentially be significant to the Mississippian Trust. As a result, the Company began consolidating the activities of the Mississippian Trust into its results of operations in April 2011. In consolidation, the common units of the Mississippian Trust owned by third parties are reflected as noncontrolling interest. As discussed above, the Company’s subordinated Mississippian Trust units will automatically convert to common Mississippian Trust units at the end of the subordination period.

The Mississippian Trust’s assets can be used to settle its own obligations and not other obligations of the Company. The Mississippian Trust’s creditors have no contractual recourse to the general credit of the Company. Although the Mississippian Trust is included in the Company’s consolidated financial statements, the Company’s legal interest in the Mississippian Trust’s assets is limited to its ownership of the Mississippian Trust units. At June 30, 2011, $350.2 million of noncontrolling interest in the accompanying condensed consolidated balance sheets was attributable to the Mississippian Trust. The Mississippian Trust’s assets and liabilities included in the accompanying condensed consolidated balance sheet at June 30, 2011 consisted of the following (in thousands):

Current assets	$	6,570
Investment in royalty interests, net(1)		304,656
Total assets	$	311,226
Current liabilities	$	651
Total liabilities	$	651

17

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

(1) Included in oil and natural gas properties on the condensed consolidated balance sheet.

Grey Ranch, L.P. Primarily engaged in treating and transportation of natural gas, Grey Ranch Plant, L.P. (“GRLP”) is a limited partnership that operates the Company’s Grey Ranch plant (the “Plant”) located in Pecos County, Texas. The Company has long-term operating and gathering agreements with GRLP and also owns a 50% interest in GRLP. Income or losses of GRLP are allocated to the partners based on ownership percentage and any operating or cash shortfalls require contributions from the partners. The Company has determined that GRLP qualifies as a VIE under the provisions of ASC Topic 810. Agreements related to the ownership and operation of GRLP provide for GRLP to pay management fees to the Company to operate the Plant and lease payments for the Plant. Under the operating agreements, lease payments are reduced if throughput volumes are below those expected. The Company has determined that it is the primary beneficiary of GRLP as it has both (i) the power to direct the activities of GRLP that most significantly impact its economic performance as operator of the Plant and (ii) the obligation to absorb losses, as a result of the operating and gathering agreements, that could potentially be significant to GRLP.

GRLP’s assets can be used to settle its own obligations and not other obligations of the Company. GRLP’s creditors have no recourse to the general credit of the Company. Although GRLP is included in the Company’s consolidated financial statements, the Company’s legal interest in GRLP’s assets is limited to its 50% ownership. At June 30, 2011 and December 31, 2010, $9.6 million and $11.3 million, respectively, of noncontrolling interest in the accompanying condensed consolidated balance sheets were related to GRLP. GRLP’s assets and liabilities included in the accompanying condensed consolidated balance sheets at June 30, 2011 and December 31, 2010 consisted of the following (in thousands):

	June 30,		December 31,
	2011		2010
Current assets	$	3,719	$	8,215
Other property, plant and equipment, net		15,560		16,079
Total assets	$	19,279	$	24,294
Current liabilities	$	318	$	1,751
Total liabilities	$	318	$	1,751

Grey Ranch Plant Genpar, LLC. The Company owns a 50% interest in Grey Ranch Plant Genpar, LLC (“Genpar”), the managing partner and 1% owner of GRLP. Additionally, the Company serves as Genpar’s administrative manager. Genpar’s ownership interest in GRLP is its only asset.

As managing partner of GRLP, Genpar has the sole right to manage, control and conduct the business of GRLP. However, Genpar is restricted from making certain major decisions, including the decision to remove the Company as operator of the Plant. The rights afforded the Company under the Plant operating agreement and the restrictions on Genpar serve to limit Genpar’s ability to make decisions on behalf of GRLP. Therefore, Genpar is considered a VIE. Although both the Company and Genpar’s other equity owner share equally in Genpar’s economic losses and benefits and also have agreements that may be considered variable interests, the Company determined it was the primary beneficiary due to (i) its ability, as administrative manager, to direct the activities of Genpar that most significantly impact its performance and (ii) its obligation or right, as operator of the Plant, to absorb the losses of or receive benefits from Genpar that could potentially be significant to Genpar. As the primary beneficiary, the Company consolidates Genpar’s activity. However, its sole asset, the investment in GRLP, is eliminated in consolidation. Genpar has no liabilities.

18

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Piñon Gathering Company, LLC. The Company has 20-year gas gathering and operations and maintenance agreements with Piñon Gathering Company, LLC (“PGC”). Under the gas gathering agreement, the Company is required to compensate PGC for any throughput shortfalls below a required minimum volume. By guaranteeing a minimum throughput, the Company absorbs the risk that lower than projected volumes will be gathered by the gathering system. Therefore, PGC is a VIE. While the Company operates the assets of PGC as directed under the operations and management agreement, the member and managers of PGC have the authority to directly control PGC and make substantive decisions regarding PGC’s activities including terminating the Company as operator without cause. As the Company does not have the ability to control the activities of PGC that most significantly impact PGC’s economic performance, the Company is not the primary beneficiary of PGC. Therefore, the results of PGC’s activities are not consolidated into the Company’s financial statements.

9. Century Plant Contract

The Company is constructing the Century Plant, a CO₂ treatment plant in Pecos County, Texas (the “Century Plant”), and associated compression and pipeline facilities pursuant to an agreement with Occidental Petroleum Corporation (“Occidental”). Under the terms of the agreement, the Company will construct the Century Plant and Occidental will pay the Company a minimum of 100% of the contract price, or $800.0 million, plus any subsequently agreed-upon revisions, through periodic cost reimbursements based upon the percentage of the project completed by the Company. The Company expects to complete the Century Plant in two phases. Upon completion of each phase of the Century Plant, Occidental will take ownership of the related assets and will operate the Century Plant for the purpose of separating and removing CO₂ from delivered natural gas. Phase I is in the commissioning process with completion and transfer of title to Occidental expected in the third quarter of 2011, and Phase II is under construction and expected to be completed in mid 2012. Pursuant to a 30-year treating agreement executed simultaneously with the construction agreement, Occidental will remove CO₂ from the Company’s delivered production volumes. The Company will retain all methane gas from the natural gas it delivers to the Century Plant.

The Company accounts for construction of the Century Plant using the completed-contract method, under which contract revenues and costs are recognized when work under both phases of the contract is completed and assets have been transferred to Occidental. In the interim, costs incurred on and billings related to contracts in process are accumulated on the balance sheet. Contract gains or losses will be recorded, as development costs within the Company’s oil and natural gas properties as part of the full cost pool, when it is determined that a gain or loss will be incurred. The Company recorded an addition of $124.0 million ($105.0 million in 2010 and $19.0 million in the first quarter of 2011) to its oil and natural gas properties for the estimated loss identified based on projections of the costs to be incurred in excess of contract amounts. Billings and estimated contract loss in excess of costs incurred of $41.2 million and $31.5 million at June 30, 2011 and December 31, 2010, respectively, are reported as current liabilities in the accompanying condensed consolidated balance sheets.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

10. Asset Retirement Obligation

A reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligation for the period from December 31, 2010 to June 30, 2011 is as follows (in thousands):

Asset retirement obligation, December 31, 2010	$	119,877
Liability incurred upon acquiring and drilling wells		2,702
Sales of reserves in place		(6,855	)
Liability settled in current period		(1,370	)
Accretion of discount expense		4,786
Asset retirement obligation, June 30, 2011		119,140
Less: current portion		25,360
Asset retirement obligation, net of current	$	93,780

11. Long-Term Debt

Long-term debt consists of the following (in thousands):

	June 30, 2011		December 31, 2010
Senior credit facility	$	80,000	$	340,000
Other notes payable
Drilling rig fleet and related oil field services equipment		—		6,302
Mortgage		16,527		17,020
Senior Floating Rate Notes due 2014		350,000		350,000
8.625% Senior Notes due 2015		—		650,000
9.875% Senior Notes due 2016, net of $11,881 and $12,793 discount, respectively		353,619		352,707
8.0% Senior Notes due 2018		750,000		750,000
8.75% Senior Notes due 2020, net of $6,693 and $6,943 discount, respectively		443,307		443,057
7.5% Senior Notes due 2021		900,000		—
Total debt		2,893,453		2,909,086
Less: current maturities of long-term debt		1,019		7,293
Long-term debt	$	2,892,434	$	2,901,793

For the three-month periods ended June 30, 2011 and 2010, interest payments were approximately $56.9 million and $83.3 million, respectively. For the six-month periods ended June 30, 2011 and 2010, interest payments were approximately $110.3 million and $92.3 million, respectively. Interest paid for the three and six-month periods ended June 30, 2011 included $1.5 million and $25.7 million, respectively, of accrued interest paid in connection with the purchase and redemption of the 8.625% Senior Notes due 2015. See discussion of redemption below.

Senior Credit Facility. The senior credit facility is available to be drawn on subject to limitations based on its terms and certain financial covenants, as described below. The senior credit facility matures on April 15, 2014.

On February 23, 2011, the senior credit facility was amended to, among other things, (a) exclude from the calculation of Consolidated Net Income the net income (or loss) of a Royalty Trust, except to the extent of cash

20

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

distributions received by the Company, (b) establish that an investment in a Royalty Trust and dispositions to, and of interests in, Royalty Trusts are permitted, (c) clarify that a Royalty Trust is not a Subsidiary, (d) allow the Company to net against its calculation of Consolidated Funded Indebtedness cash balances exceeding $10.0 million in the event no loans are outstanding under the senior credit facility at that time, and (e) establish that, for any fiscal quarter ending prior to March 31, 2012, if the ratio of the Company’s secured indebtedness to EBITDA is less than 1.5:1.0 then compliance with the Company’s Consolidated Leverage Ratio covenant is not required. Terms capitalized in the preceding sentence have the meaning given to them in the senior credit facility, as amended.

On April 20, 2011, the senior credit facility was amended. The amendment permits the Company to pay cash dividends on its 7.0% convertible perpetual preferred stock and reaffirms the borrowing base at $790.0 million.

As of June 30, 2011, the senior credit facility contained financial covenants, including maintaining agreed levels for the (i) ratio of total funded debt to EBITDA, which may not exceed 4.5:1.0 at each quarter end, calculated using the last four completed fiscal quarters, unless, for any quarter ending prior to March 31, 2012, the ratio of the Company’s secured indebtedness to EBITDA is less than 1.5:1.0, calculated using the last four completed fiscal quarters (in each case through the second quarter of 2011, adjusted for annualized amounts of the post-acquisition results of operations of Arena), (ii) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at each quarter end (in the current ratio calculation (as defined in the senior credit facility), any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on the Company’s derivative contracts are disregarded) and (iii) ratio of the Company’s secured indebtedness to EBITDA, which may not exceed 2.0:1.0 at each quarter end, calculated using the last four completed fiscal quarters (in each case through the second quarter of 2011, adjusted for annualized amounts of the post-acquisition results of operations of Arena). As of and during the three and six-month periods ended June 30, 2011, the Company was in compliance with all of the financial covenants under the senior credit facility.

Additionally, the senior credit facility contains various covenants that limit the ability of the Company and certain of its subsidiaries to grant certain liens; make certain loans and investments; make distributions; redeem stock; redeem or prepay debt; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets. Additionally, the senior credit facility limits the ability of the Company and certain of its subsidiaries to incur additional indebtedness with certain exceptions.

The obligations under the senior credit facility are guaranteed by certain Company subsidiaries and are secured by first priority liens on all shares of capital stock of each of the Company’s material present and future subsidiaries; all intercompany debt of the Company; and substantially all of the Company’s assets, including proved oil and natural gas reserves representing at least 80% of the discounted present value (as defined in the senior credit facility) of proved oil and natural gas reserves considered by the lenders in determining the borrowing base for the senior credit facility.

At the Company’s election, interest under the senior credit facility is determined by reference to (a) the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 2.00% and 3.00% per annum or (b) the “base rate,” which is the highest of (i) the federal funds rate plus 0.5%, (ii) the prime rate published by Bank of America or (iii) the Eurodollar rate (as defined in the senior credit facility) plus 1.00% per annum, plus, in each case under scenario (b), an applicable margin between 1.00% and 2.00% per annum. Interest is payable quarterly for base rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period

21

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

for a LIBOR loan is six months, interest is paid at the end of each three-month period. The average annual interest rate paid on amounts outstanding under the senior credit facility was 2.51% and 2.65% for the three-month periods ended June 30, 2011 and 2010, respectively, and 2.70% and 2.52% for the six-month periods ended June 30, 2011 and 2010, respectively.

Borrowings under the senior credit facility may not exceed the lower of the borrowing base or the committed amount. On March 15, 2011, the borrowing base was reduced from $850.0 million to $790.0 million as a result of the issuance of the 7.5% Senior Notes due 2021, discussed below. The Company’s borrowing base is redetermined in April and October of each year. With respect to each redetermination, the administrative agent and the lenders under the senior credit facility consider several factors, including the Company’s proved reserves and projected cash requirements, and make assumptions regarding, among other things, oil and natural gas prices and production. Because the value of the Company’s proved reserves is a key factor in determining the amount of the borrowing base, changing commodity prices and the Company’s success in developing reserves may affect the borrowing base. At the April 2011 redetermination, the borrowing base remained $790.0 million. The Company at times incurs additional costs related to the senior credit facility as a result of amendments to the credit agreement and changes to the borrowing base. During the first six months of 2011, additional costs of approximately $0.3 million were incurred. These costs have been deferred and are included in other assets in the accompanying condensed consolidated balance sheets.

At June 30, 2011, the Company had $80.0 million outstanding under the senior credit facility and $24.5 million in outstanding letters of credit, which affect the availability under the senior credit facility on a dollar-for-dollar basis.

Other Notes Payable. The Company financed a portion of its drilling rig fleet and related oil field services equipment through the issuance of notes secured by such equipment. In March 2011, the Company paid the outstanding $4.3 million principal balance on these notes.

The debt incurred to purchase the downtown Oklahoma City property that serves as the Company’s corporate headquarters is fully secured by a mortgage on one of the buildings located on the property. The note underlying the mortgage bears interest at 6.08% annually and matures on November 15, 2022. Payments of principal and interest in the amount of approximately $0.5 million are due on a quarterly basis through the maturity date.

Senior Floating Rate Notes Due 2014 and 8.625% Senior Notes Due 2015. The Company’s Senior Floating Rate Notes due 2014 (the “Senior Floating Rate Notes”) and 8.625% Senior Notes due 2015 (the “8.625% Senior Notes”) were issued in May 2008. The Senior Floating Rate Notes are jointly and severally guaranteed unconditionally on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable. See Note 20 for condensed financial information of the subsidiary guarantors. As discussed below, on April 1, 2011, the Company redeemed the 8.625% Senior Notes that remained outstanding following the completion of its tender offer in respect of such notes.

The Senior Floating Rate Notes bear interest at LIBOR plus 3.625% (3.93% at June 30, 2011). Interest is payable quarterly with the principal due on April 1, 2014. The average interest rate paid on the outstanding Senior Floating Rate Notes was 3.93% and 3.92% for the three-month periods ended June 30, 2011 and 2010, respectively, and 3.93% and 3.90% for the six-month periods ended June 30, 2011 and 2010, respectively, without consideration of the interest rate swap discussed below. The Company may redeem, at specified redemption prices, some or all of the Senior Floating Rate Notes at any time.

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

As of June 30, 2011, the Company had a $350.0 million notional interest rate swap agreement to fix the variable interest rate on the Senior Floating Rate Notes through April 1, 2013. The swap agreement effectively serves to fix the rate on the Senior Floating Rate Notes at an annual rate of 6.69% for the period from April 1, 2011 to April 1, 2013. This swap has not been designated as a hedge.

On March 1, 2011, the Company announced a cash tender offer to purchase any and all of the outstanding $650.0 million aggregate principal amount of its 8.625% Senior Notes for total consideration of $1,046.88 per $1,000 principal amount of such notes tendered by March 14, 2011. Holders tendering after March 14, 2011 were eligible to receive $1,016.88 per $1,000 principal amount of notes tendered. All holders whose notes were purchased received accrued and unpaid interest from the last interest payment date. As of March 31, 2011, the Company had purchased approximately 94.5%, or $614.2 million, of the aggregate principal amount of its 8.625% Senior Notes pursuant to the tender offer, which expired on March 28, 2011. On April 1, 2011, the Company redeemed the remaining outstanding $35.8 million aggregate principal amount of its 8.625% Senior Notes for $1,043.13 per $1,000 principal amount outstanding, plus accrued interest. All holders whose notes were redeemed received accrued and unpaid interest from October 1, 2010. The premium paid to purchase these notes and the unamortized debt issuance costs associated with the notes, totaling $2.0 million and $38.2 million for the three and six-month periods ended June 30, 2011, respectively, were recorded as a loss on extinguishment of debt and are included in the accompanying condensed consolidated statements of operations.

The $9.4 million of debt issuance costs associated with the Senior Floating Rate Notes is included in other assets in the accompanying condensed consolidated balance sheets and is being amortized over the term of the notes.

9.875% Senior Notes Due 2016. The Company’s unsecured 9.875% Senior Notes due 2016 (the “9.875% Senior Notes”) were issued in May 2009 and bear interest at a fixed rate of 9.875% per annum, payable semi-annually, with the principal due on May 15, 2016. The 9.875% Senior Notes were issued at a discount, which is amortized into interest expense over the term of the notes. The 9.875% Senior Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally guaranteed unconditionally on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable.

Debt issuance costs of $7.9 million incurred in connection with the offering of the 9.875% Senior Notes are included in other assets in the accompanying condensed consolidated balance sheets and are being amortized over the term of the notes.

8.0% Senior Notes Due 2018. The Company’s unsecured 8.0% Senior Notes due 2018 (the “8.0% Senior Notes”) were issued in May 2008 and bear interest at a fixed rate of 8.0% per annum, payable semi-annually, with the principal due on June 1, 2018. The notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally guaranteed unconditionally on an unsecured basis, by certain of the Company’s wholly owned subsidiaries and are freely tradable.

The Company incurred $16.0 million of debt issuance costs in connection with the offering of the 8.0% Senior Notes. These costs are included in other assets in the accompanying condensed consolidated balance sheets and are being amortized over the term of the notes.

8.75% Senior Notes Due 2020. The Company’s unsecured 8.75% Senior Notes due 2020 (the “8.75% Senior Notes”) were issued in December 2009 and bear interest at a fixed rate of 8.75% per annum, payable semi-annually, with the principal due on January 15, 2020. The 8.75% Senior Notes were issued at a discount which is

23

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

amortized into interest expense over the term of the notes. The 8.75% Senior Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally, guaranteed unconditionally on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable. See Note 20 for condensed financial information of the subsidiary guarantors.

Debt issuance costs of $9.7 million incurred in connection with the offering of and subsequent registered exchange of the 8.75% Senior Notes are included in other assets in the accompanying condensed consolidated balance sheets and are being amortized over the term of the notes.

7.5% Senior Notes Due 2021. In March 2011, the Company issued $900.0 million of unsecured 7.5% Senior Notes due 2021 (the “7.5% Senior Notes”) to qualified institutional buyers eligible under Rule 144A of the Securities Act and to persons outside the United States under Regulation S under the Securities Act. Net proceeds from the offering were approximately $880.7 million after deducting offering expenses, and were used to fund the tender offer for the 8.625% Senior Notes, including any accrued and unpaid interest, the redemption of the 8.625% Senior Notes that remained outstanding following the conclusion of the tender offer, including accrued and unpaid interest (each as described above) and to repay borrowings under the Company’s senior credit facility. The 7.5% Senior Notes bear interest at a fixed rate of 7.5% per annum, payable semi-annually, with the principal due on March 15, 2021. Prior to March 15, 2016, the 7.5% Senior Notes are redeemable, in whole or in part, at a specified redemption price plus accrued and unpaid interest. On or after March 15, 2016, the 7.5% Senior Notes are redeemable, in whole or in part, prior to their maturity at other various specified redemption prices. The notes are jointly and severally guaranteed unconditionally on an unsecured basis by certain of the Company’s wholly owned subsidiaries.

In conjunction with the issuance of the 7.5% Senior Notes, the Company entered into a Registration Rights Agreement requiring the Company to conduct a registered exchange offer for or register the resale of these notes before March 14, 2012. The Company is required to pay additional interest if it fails to fulfill its obligations under the agreement within the specified time periods.

Debt issuance costs of $19.3 million incurred in connection with the offering of the 7.5% Senior Notes are included in other assets in the accompanying condensed consolidated balance sheets and are being amortized over the term of the notes.

Indentures. The indentures governing the Company’s senior notes contain limitations on the incurrence of indebtedness, payment of dividends, investments, asset sales, certain asset purchases, transactions with related parties and consolidations or mergers. As of and for the three and six-month periods ended June 30, 2011, the Company was in compliance with all of the covenants contained in the indentures governing the senior notes.

12. Derivatives

None of the Company’s derivative contracts have been designated as hedges. The Company records all derivative contracts, which include commodity derivatives and an interest rate swap, at fair value. Changes in derivative contract fair values are recognized in earnings. Cash settlements and valuation gains and losses are included in (gain) loss on derivative contracts for the commodity derivative contracts and in interest expense for interest rate swaps in the consolidated statement of operations. Commodity derivative contracts are settled on a monthly basis. Settlements on interest rate swaps occur quarterly. Derivative assets and liabilities arising from the Company’s derivative contracts with the same counterparty that provide for net settlement are reported on a net basis in the consolidated balance sheet.

24

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Commodity Derivatives. The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil and natural gas. The Company seeks to manage this risk through the use of commodity derivative contracts. These derivative contracts allow the Company to limit its exposure to a portion of its projected oil and natural gas sales. None of the Company’s derivative contracts may be terminated early as a result of a party to the contract having its credit rating downgraded. At June 30, 2011, the Company’s commodity derivative contracts consisted of fixed price swaps, collars and basis swaps, which are described below:

Fixed price swaps:	The Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.
Collars:	Collars contain a fixed floor price (put) and a fixed ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.
Basis swaps:	The Company receives a payment from the counterparty if the settled price differential is greater than the stated terms of the contract and pays the counterparty if the settled price differential is less than the stated terms of the contract, which guarantees the Company a price differential for natural gas from a specified delivery point.

On April 12, 2011, the Company entered into a derivatives agreement with the Mississippian Trust, effective April 1, 2011, that provides the Mississippian Trust with the benefit of certain oil and natural gas derivative contracts previously entered into by the Company with third parties. The underlying commodity derivative contracts cover volumes of oil and natural gas production through December 31, 2015. Under this arrangement, the Company will pay the Mississippian Trust amounts it receives from its counterparties in accordance with the underlying contracts, and the Mississippian Trust will pay the Company any amounts that it is required to pay its counterparties under such contracts. These commodity derivative contracts are included in the open oil and natural gas derivative contracts tables below. See Note 8 for additional discussion of the Mississippian Trust and a listing of the derivative contracts, the benefits and obligations of which will be passed to the Mississippian Trust.

Interest Rate Swaps. The Company is exposed to interest rate risk on its long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes the Company to (i) changes in market interest rates reflected in the fair value of the debt and (ii) the risk that the Company may need to refinance maturing debt with new debt at a higher rate. Variable rate debt, where the interest rate fluctuates, exposes the Company to short-term changes in market interest rates as the Company’s interest obligations on these instruments are periodically redetermined based on prevailing market interest rates, primarily LIBOR and the federal funds rate.

The Company has an interest rate swap agreement to manage the interest rate risk on a portion of its floating rate debt by effectively fixing the variable interest rate on its Senior Floating Rate Notes through April 1, 2013. See Note 11 for further discussion of the Company’s interest rate swap.

25

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Fair Value of Derivatives. In accordance with ASC Topic 815, Derivatives and Hedging, the following table presents the fair value of the Company’s derivative contracts at June 30, 2011 and December 31, 2010 on a gross basis without regard to same-counterparty netting (in thousands):

Type of Contract	Balance Sheet Classification	June 30, 2011			December 31, 2010
Derivative assets
Oil price swaps	Derivative contracts-current	$	2,674		$	—
Natural gas price swaps	Derivative contracts-current		6,157			8,500
Oil price swaps	Derivative contracts-noncurrent		3,415			—
Natural gas price swaps	Derivative contracts-noncurrent		—			3,518
Derivative liabilities
Oil price swaps	Derivative contracts-current		(104,129	)		(63,123	)
Natural gas price swaps	Derivative contracts-current		(38	)		(640	)
Natural gas basis swaps	Derivative contracts-current		(41,973	)		(34,112	)
Interest rate swaps	Derivative contracts-current		(9,552	)		(9,007	)
Oil price swaps	Derivative contracts-noncurrent		(135,069	)		(84,055	)
Natural gas price swaps	Derivative contracts-noncurrent		—			(802	)
Natural gas basis swaps	Derivative contracts-noncurrent		(24,446	)		(34,908	)
Natural gas collars	Derivative contracts-noncurrent		(224	)		(238	)
Interest rate swap	Derivative contracts-noncurrent		(5,733	)		(7,687	)
Total derivative contracts, net		$	(308,918	)	$	(222,554	)

Refer to Note 4 for additional discussion on the fair value measurement of the Company’s derivative contracts.

The following table summarizes the effects of the Company’s derivative contracts on the accompanying condensed consolidated statements of operations for the three and six-month periods ended June 30, 2011 and 2010 (in thousands):

Type of Contract	Location of (Gain) Loss Recognized in Income	Amount of (Gain) Loss Recognized in Income
		Three Months Ended June 30,						Six Months Ended June 30,
		2011			2010			2011		2010
Oil and natural gas derivatives	(Gain) loss on derivative contracts	$	(169,988	)	$	(119,621	)	$	107,640	$	(181,573	)
Interest rate swaps	Interest expense		2,798			6,477			3,076		12,412
Total		$	(167,190	)	$	(113,144	)	$	110,716	$	(169,161	)

26

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

The following tables summarize the cash settlements and valuation gains and losses on our commodity derivative contracts and interest rate swaps for the three and six-month periods ended June 30, 2011 and 2010 (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
Oil and Natural Gas Derivatives	2011			2010			2011			2010
Realized loss (gain)(1)	$	18,273		$	(117,955	)	$	26,881		$	(160,548	)
Unrealized (gain) loss		(188,261	)		(1,666	)		80,759			(21,025	)
(Gain) loss on commodity derivative contracts	$	(169,988	)	$	(119,621	)	$	107,640		$	(181,573	)
	Three Months Ended June 30,						Six Months Ended June 30,
Interest Rate Swaps	2011			2010			2011			2010
Realized loss	$	2,442		$	2,076		$	4,485		$	4,163
Unrealized loss (gain)		356			4,401			(1,409	)		8,249
Loss on interest rate swaps	$	2,798		$	6,477		$	3,076		$	12,412

(1) Includes $25.8 million and $38.2 million of realized gains for the three and six-month periods ended June 30, 2011, respectively, related to settlements of commodity derivative contracts with contractual maturities after the quarterly period in which they were settled. Includes $62.4 million of realized gains for the three and six-month periods ended June 30, 2010, related to settlements of commodity derivative contracts with contractual maturities after June 30, 2010.

27

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

On June 30, 2011, the Company’s open oil and natural gas commodity derivative contracts consisted of the following:

Oil Swaps

Period and Type of Contract(1)	Notional (MBbl)		Weighted Avg. Fixed Price
July 2011 — September 2011
Price swap contracts		2,301	$	86.89
October 2011 — December 2011
Price swap contracts		2,301	$	86.89
January 2012 — March 2012
Price swap contracts		2,388	$	87.98
April 2012 — June 2012
Price swap contracts		2,479	$	87.88
July 2012 — September 2012
Price swap contracts		2,536	$	87.85
October 2012 — December 2012
Price swap contracts		2,598	$	87.79
January 2013 — March 2013
Price swap contracts		2,168	$	93.09
April 2013 — June 2013
Price swap contracts		2,192	$	93.09
July 2013 — September 2013
Price swap contracts		2,216	$	93.09
October 2013 — December 2013
Price swap contracts		2,216	$	93.09
January 2014 — March 2014
Price swap contracts		493	$	101.07
April 2014 — June 2014
Price swap contracts		499	$	101.07
July 2014 — September 2014
Price swap contracts		504	$	101.07
October 2014 — December 2014
Price swap contracts		504	$	101.07
January 2015 — March 2015
Price swap contracts		295	$	100.45
April 2015 — June 2015
Price swap contracts		299	$	100.45
July 2015 — September 2015
Price swap contracts		302	$	100.45
October 2015 — December 2015
Price swap contracts		302	$	100.45

28

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Natural Gas Swaps

Period and Type of Contract(1)	Notional (MMcf)(2)		Weighted Avg. Fixed Price
July 2011 — September 2011
Price swap contracts(3)		6,779	$	4.63
Basis swap contracts		26,220	$	(0.47	)
October 2011 — December 2011
Price swap contracts(3)		6,471	$	4.65
Basis swap contracts		26,220	$	(0.47	)
January 2012 — March 2012
Price swap contracts(3)		5,460	$	5.12
Basis swap contracts		28,210	$	(0.55	)
April 2012 — June 2012
Price swap contracts(3)		5,460	$	5.12
Basis swap contracts		28,210	$	(0.55	)
July 2012 — September 2012
Basis swap contracts		28,520	$	(0.55	)
October 2012 — December 2012
Basis swap contracts		28,520	$	(0.55	)
January 2013 — March 2013
Basis swap contracts		3,600	$	(0.46	)
April 2013 — June 2013
Basis swap contracts		3,640	$	(0.46	)
July 2013 — September 2013
Basis swap contracts		3,680	$	(0.46	)
October 2013 — December 2013
Basis swap contracts		3,680	$	(0.46	)

29

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Natural Gas Collars

Period and Type of Contract(1)	Notional (MMcf)(2)		Collar Range
July 2012 — September 2012
Collars		201		4.00 - 6.20
October 2012 — December 2012
Collars		201		4.00 - 6.20
January 2013 — March 2013
Collars		212		4.00 - 7.15
April 2013 — June 2013
Collars		214		4.00 - 7.15
July 2013 — September 2013
Collars		216		4.00 - 7.15
October 2013 — December 2013
Collars		216		4.00 - 7.15
January 2014 — March 2014
Collars		231		4.00 - 7.78
April 2014 — June 2014
Collars		234		4.00 - 7.78
July 2014 — September 2014
Collars		236		4.00 - 7.78
October 2014 — December 2014
Collars		236		4.00 - 7.78
January 2015 — March 2015
Collars		249		4.00 - 8.55
April 2015 — June 2015
Collars		252		4.00 - 8.55
July 2015 — September 2015
Collars		255		4.00 - 8.55
October 2015 — December 2015
Collars		255		4.00 - 8.55

(1) Includes derivative contracts, the benefits of which have been conveyed to the Mississippian Trust pursuant to the derivatives agreement with the Mississippian Trust. See Note 8 for a listing of open derivative contracts at June 30, 2011, the benefits and obligations of which were conveyed to the Mississippian Trust.

(2) Assumes ratio of 1:1 for Mcf to MMBtu.

(3) Includes 7,865 MMcf and 7,280 MMcf with contractual maturities in 2011 and 2012, respectively, that were settled in July 2011.

30

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

13. Income Taxes

The Company estimates for each interim reporting period the effective tax rate expected for the full fiscal year and uses that estimated rate in providing for income taxes on a current year-to-date basis. The (benefit) provision for income taxes consisted of the following components for the three and six-month periods ended June 30, 2011 and 2010 (in thousands).

	Three Months Ended June  30,					Six Months Ended June  30,
	2011			2010		2011			2010
Current
Federal	$	(137	)	$	—	$	(116	)	$	—
State		69			150		135			162
		(68	)		150		19			162
Deferred
Federal		(6,385	)		—		(6,385	)		—
State		(601	)		—		(601	)		—
		(6,986	)		—		(6,986	)		—
Total (benefit) provision		(7,054	)		150		(6,967	)		162
Less: income tax provision attributable to noncontrolling interest		—			89		2			89
Total (benefit) provision attributable to SandRidge Energy, Inc.	$	(7,054	)	$	61	$	(6,969	)	$	73

Deferred income taxes are provided to reflect the future tax consequences of temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. Deferred tax assets are reduced by a valuation allowance as necessary when a determination is made that it is more likely than not that some or all of the deferred tax assets will not be realized based on the weight of all available evidence. As of December 31, 2008, the Company determined it was appropriate to record a full valuation allowance against its net deferred tax asset. In the second quarter of 2011, the Company completed its valuation of assets acquired and liabilities assumed related to the Arena Acquisition in order to finalize the purchase price allocation. In connection therewith, the Company adjusted the previously recorded net deferred tax liability associated with the Arena Acquisition by recording an additional net deferred tax liability of $7.0 million. The adjustment resulted in the Company releasing a corresponding portion of its previously recorded valuation allowance. This release of valuation allowance is in addition to the $447.5 million released in 2010. The 2010 and 2011 partial releases of the valuation allowance were based on management’s assessment that it is more likely than not that the Company will realize a benefit from more of its existing deferred tax assets as the Arena deferred tax liabilities are available to offset the reversal of the Company’s deferred tax assets. Although the Company continued to have a full valuation allowance against its net deferred tax asset at June 30, 2011, the additional release of the valuation allowance resulted in an income tax benefit of $7.0 million for the three and six-month periods ended June 30, 2011.

IRC Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. The Company experienced an ownership change within the meaning of IRC Section 382 on December 31, 2008. The ownership change subjected certain of the Company’s tax attributes, including $302.8 million of federal net operating loss carryforwards, to the IRC Section 382 limitation. The Company experienced a subsequent ownership change within the meaning of IRC Section 382 on July 16, 2010 as a result of the Arena Acquisition. The Company expects a more restrictive limitation on certain of its tax attributes as a result of the July 16, 2010 ownership change than with the December 31, 2008 ownership change. The more restrictive limitation would apply not only

31

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

to the $302.8 million of federal net operating loss carryforwards and certain other tax attributes existing at December 31, 2008 but also to the net operating losses of approximately $491.4 million and certain other attributes generated during the period from January 1, 2009 through July 16, 2010. The subsequent limitation could result in a material amount of the loss carryforwards existing at July 16, 2010 expiring unused. Arena also experienced an ownership change on July 16, 2010 as a result of its acquisition by the Company. This ownership change is expected to result in a limitation on Arena’s net operating loss carryforwards and certain other carryforwards available to the Company on an annual basis. None of the limitations discussed above resulted in a current federal tax liability at June 30, 2011 or December 31, 2010.

As of June 30, 2011, the Company had a liability of approximately $1.52 million for unrecognized tax benefits. If recognized, approximately $1.0 million, net of federal tax expense, would be recorded as a reduction of income tax expense and would affect the effective tax rate. The liability for unrecognized tax benefits as of December 31, 2010 was $1.45 million.

Consistent with the Company’s policy to record interest and penalties on income taxes as a component of the income tax provision, the Company has included $0.02 million and $0.07 million of accrued gross interest with respect to unrecognized tax benefits in its condensed consolidated statements of operations for the three and six-month periods ended June 30, 2011, respectively. The Company did not recognize any interest and penalties related to unrecognized tax benefits during the three and six-month periods ended June 30, 2010.

The Company’s only taxing jurisdiction is the United States (federal and state). The Company’s tax years 2007 to present remain open for federal examination. Additionally, various tax years remain open for certain acquired entities beginning with tax year 2003 due to federal net operating loss carryforwards. The number of years open for state tax audits varies, depending on the state, but are generally from three to five years. Currently, several examinations are in progress. The Company does not anticipate that any federal or state audits will have a significant impact on the Company’s results of operations or financial position. In addition, the Company does not expect resolution of any uncertain tax positions that would result in a significant increase or decrease to the amount of unrecognized tax benefits during the next twelve months.

For the three-month period ended June 30, 2011, income tax refunds, net of payments, were $0.04 million. For the six-month period ended June 30, 2011, income tax payments, net of refunds, were $0.94 million. For the three and six-month periods ended June 30, 2010, income tax refunds, net of payments, were $0.1 million and $3.5 million, respectively.

32

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

14. Earnings Per Share

Basic earnings per share are computed using the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average shares outstanding during the period, but also include the dilutive effect of awards of restricted stock and outstanding convertible preferred stock. The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings per share for the three and six-month periods ended June 30, 2011 and 2010 (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Weighted average basic common shares outstanding		398,435		203,839		398,343		203,831
Effect of dilutive securities
Restricted stock		7,414		4,231		—		4,152
Convertible preferred stock outstanding		90,133		51,496		—		18,423
Weighted average diluted common and potential common shares outstanding		495,982		259,566		398,343		226,406

For the six-month period ended June 30, 2011, restricted stock awards covering 7.3 million shares were excluded from the computation of net loss per share because their effect would have been antidilutive.

In computing diluted earnings per share, the Company evaluated the if-converted method with respect to its outstanding 8.5% convertible perpetual preferred stock, 6.0% convertible perpetual preferred stock and 7.0% convertible perpetual preferred stock for the three and six-month periods ended June 30, 2011 and its outstanding 8.5% convertible perpetual preferred stock and 6.0% convertible perpetual preferred stock for the three and six-month periods ended June 30, 2010. See Note 16 for discussion of the Company’s convertible preferred stock. Under the if-converted method, the Company assumes the conversion of the preferred stock to common stock and determines if this is more dilutive than including the preferred stock dividends (paid and unpaid) in the computation of income available to common stockholders. For the three-month period ended June 30, 2011, the Company determined the if-converted method was more dilutive and did not include the 6.0%, 8.5% or 7.0% preferred stock dividends in the determination of income available to common stockholders. For the six-month period ended June 30, 2011, the Company determined the if-converted method was not more dilutive and included preferred stock dividends in the determination of loss applicable to common stockholders. For the three-month period ended June 30, 2010, the Company determined the if-converted method was more dilutive and did not include the 6.0% and 8.5% preferred stock dividends in the determination of income available to common stockholders. For the six-month period ended June 30, 2010, the Company determined the if-converted method was more dilutive with respect to its 6.0% convertible perpetual preferred stock, but not more dilutive with respect to its 8.5% convertible perpetual preferred stock. As a result, the Company did not include the 6.0% preferred stock dividends, but did include the 8.5% preferred stock dividends in the determination of income available to common stockholders for the six-month period ended June 30, 2010.

15. Commitments and Contingencies

The Company is a defendant in lawsuits from time to time in the normal course of business. In management’s opinion, the Company is not currently involved in any legal proceedings that, individually or in the aggregate, could have a material effect on the financial condition, operations or cash flows of the Company.

33

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

On or about June 27, 2008 and November 6, 2008, there were fires at the Company’s Grey Ranch Plant and a nearby compressor station. The Company, as owner of the plant and compressor station, recovered approximately $24.5 million from its insurance carriers for damages caused by the fires. At the time of the plant fire, the plant was operated by Southern Union Gas Services, Ltd. (“Southern Union Gas”). On June 4, 2010, November 10, 2010, and March 15, 2011, the Company’s insurance carriers filed lawsuits against Southern Union Gas and its parent, Southern Union Company (together with Southern Union Gas, “Southern Union”) seeking recovery for amounts paid under the Company’s insurance policies. Southern Union, in turn, has tendered indemnity requests to GRLP, of which the Company is a 50% owner. GRLP has not accepted or acknowledged any responsibility to indemnify Southern Union. To the extent the Company, as a 50% owner of GRLP, is required to fund any indemnification of Southern Union, it will pursue coverage for such liability under its general liability insurance policy. An estimate of reasonably possible losses associated with these claims cannot be made at this time. The Company has not established any reserves relating to these claims.

On February 14, 2011, Aspen Pipeline, II, L.P. (“Aspen”) filed a complaint in the District Court of Harris County, Texas, against Arena Resources, Inc. and SandRidge Energy, Inc. claiming damages based upon alleged representations by Arena in connection with the construction by Aspen of a natural gas pipeline in West Texas. The plaintiff seeks damages that include the construction cost of the pipeline, which it claims approach $90.0 million. The Company intends to defend this lawsuit vigorously and, believes the plaintiff’s claims are without merit. This case is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this claim cannot be made at this time. The Company has not established any reserves relating to this claim.

On April 5, 2011, Wesley West Minerals, Ltd. and Longfellow Ranch Partners, LP (collectively, the “plaintiffs”) filed suit against SandRidge Energy, Inc. and SandRidge Exploration and Production, LLC (collectively, the “SandRidge Entities”) in the 83^rd District Court of Pecos County, Texas. The plaintiffs, who have leased mineral rights to the SandRidge Entities in Pecos County, allege that the SandRidge Entities have not properly paid royalties on all volumes of natural gas (including carbon dioxide, or “CO₂”) produced from the acreage leased from the plaintiffs. The plaintiffs also allege that the SandRidge Entities have inappropriately failed to pay royalties on CO₂ produced from the plaintiffs’ acreage that results from the treatment of natural gas at the Century Plant. The plaintiffs seek unspecified actual damages, punitive damages and a declaration that the SandRidge Entities must pay royalties on CO₂ produced from plaintiffs’ acreage that results from treatment of natural gas at the Century Plant. The Company intends to defend this lawsuit vigorously. This case is in the early stages and, accordingly, an estimate of reasonably possible losses, if any, associated with these claims cannot be made at this time. The Company has not established any reserves relating to these claims.

SandRidge acquired certain oil and natural gas leases in Loving County, Texas, from mineral owners in April 2010, which it subsequently sold to Energen Resources Corporation (“Energen”) in December 2010 for an allocated value of approximately $4.0 million. Subsequent to the acquisition by SandRidge of the leases and prior to their disposition to Energen, the mineral owners executed oil and natural gas leases conveying the same mineral estates to Cimarex Energy Co. (“Cimarex”). SandRidge has requested a declaratory judgment resolving all disputes between it and Cimarex regarding the validity of the leases insofar as they purport to cover the same mineral interests. In connection with that action, Cimarex has filed a third-party petition naming Energen as a third-party defendant, and is asserting quiet title and trespass to try title claims against Energen. Energen has tendered to SandRidge a demand for indemnity, and SandRidge has assumed Energen’s defense and any potential loss suffered by it. An estimate of reasonably possible losses, if any, associated with the demand for indemnity cannot be made at this time. Accordingly, the Company has not established any reserves relating to the demand.

34

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

16. Equity

Preferred Stock. The following table presents information regarding the Company’s preferred stock (in thousands):

	June 30, 2011		December 31, 2010
Shares authorized		50,000		50,000
Shares outstanding at end of period
8.5% Convertible perpetual preferred stock		2,650		2,650
6.0% Convertible perpetual preferred stock		2,000		2,000
7.0% Convertible perpetual preferred stock		3,000		3,000

The Company is authorized to issue 50,000,000 shares of preferred stock, $0.001 par value, of which 7,650,000 shares were designated as convertible perpetual preferred stock at June 30, 2011 and December 31, 2010. All of the outstanding shares of the Company’s convertible perpetual preferred stock were issued in private transactions and none of these shares are listed on a stock exchange.

8.5% Convertible perpetual preferred stock. The Company’s 8.5% convertible perpetual preferred stock was issued in January 2009. Each share of 8.5% convertible perpetual preferred stock has a liquidation preference of $100.00 and is convertible at the holder’s option at any time initially into approximately 12.4805 shares of the Company’s common stock based on an initial conversion price of $8.01, subject to adjustments upon the occurrence of certain events. Each holder of the convertible perpetual preferred stock is entitled to an annual dividend of $8.50 per share to be paid semi-annually in cash, common stock or a combination thereof, at the Company’s election. All dividend payments to date have been paid in cash. Approximately $5.6 million in dividends (all unpaid) and $11.3 million in dividends ($2.8 million paid and $8.5 million unpaid) on the 8.5% convertible perpetual preferred stock have been included in the Company’s earnings per share calculations for the three and six-month periods ended June 30, 2011, respectively, as presented in the accompanying condensed consolidated statements of operations. Approximately $5.6 million in dividends (all unpaid) and $11.3 million in dividends ($2.8 million paid and $8.5 million unpaid) on the 8.5% convertible perpetual preferred stock have been included in the Company’s earnings per share calculations for the three and six-month periods ended June 30, 2010, respectively, as presented in the accompanying condensed consolidated statements of operations. The 8.5% convertible perpetual preferred stock is not redeemable by the Company at any time. After February 20, 2014, the Company may cause all outstanding shares of the convertible perpetual preferred stock to convert automatically into common stock at the then-prevailing conversion rate if certain conditions are met.

6.0% Convertible perpetual preferred stock. The Company’s 6.0% convertible perpetual preferred stock was issued in December 2009. Each share of the 6.0% convertible perpetual preferred stock has a liquidation preference of $100.00 and is entitled to an annual dividend of $6.00 payable semi-annually in cash, common stock or any combination thereof, at the Company’s election. All dividend payments to date have been paid in cash. Approximately $3.0 million (all unpaid) and $6.0 million in dividends ($0.5 million paid and $5.5 million unpaid) on the 6.0% convertible perpetual preferred stock have been included in the Company’s earnings per share calculations for the three and six-month periods ended June 30, 2011, respectively, as presented in the accompanying condensed consolidated statements of operations. Approximately $3.0 million and $6.0 million in unpaid dividends on the 6.0% convertible perpetual preferred stock have been included in the Company’s earnings per share calculations for the three and six-month periods ended June 30, 2010, respectively, as presented in the accompanying condensed consolidated statements of operations. The 6.0% convertible perpetual preferred stock is not redeemable by the Company at any time. Each share is initially convertible into approximately 9.2115 shares of the Company’s common stock, at the holder’s option based on an initial

35

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

conversion price of $10.86 and subject to customary adjustments in certain circumstances. Five years after their issuance, all outstanding shares of the convertible preferred stock will be converted automatically into shares of the Company’s common stock at the then-prevailing conversion price as long as all dividends accrued at that time have been paid.

7.0% Convertible perpetual preferred stock. The Company’s 7.0% convertible perpetual preferred stock was issued in November 2010. Each share of the 7.0% convertible preferred stock has a liquidation preference of $100.00 per share and became convertible at the holder’s option on February 15, 2011, initially into approximately 12.8791 shares of the Company’s common stock based on an initial conversion price of $7.76 per share. The annual dividend on each share of the 7.0% convertible preferred stock is $7.00 payable semi-annually, in cash, common stock or a combination thereof, at the Company’s election beginning on May 15, 2011. All dividend payments to date have been paid in cash. Approximately $5.3 million ($2.7 million paid and $2.6 million unpaid) and $10.6 million in dividends ($8.0 million paid and $2.6 million unpaid) on the 7.0% convertible perpetual preferred stock have been included in the Company’s earnings per share calculations for the three and six-month periods ended June 30, 2011 as presented in the accompanying condensed consolidated statements of operations. The 7.0% convertible perpetual preferred stock is not redeemable by the Company at any time. After November 20, 2015, the Company may cause all outstanding shares of the 7.0% convertible perpetual preferred stock to convert automatically into common stock at the then-prevailing conversion rate if certain conditions are met.

Common Stock. The following table presents information regarding the Company’s common stock (in thousands):

	June 30, 2011		December 31, 2010
Shares authorized		800,000		800,000
Shares outstanding at end of period		409,918		406,360
Shares held in treasury		580		470

Treasury Stock. The Company makes required tax payments on behalf of employees when their restricted stock awards vest and then withholds a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. As a result of such transactions, the Company withheld approximately 617,000 shares with a total value of $5.0 million and approximately 274,000 shares with a total value of $2.9 million during the six-month periods ended June 30, 2011 and 2010, respectively. These shares were accounted for as treasury stock when withheld, and subsequently retired.

Any shares of Company common stock held as assets in a trust for the Company’s non-qualified deferred compensation plan are accounted for as treasury shares. These shares are not included as outstanding shares of common stock in this Quarterly Report. For corporate purposes and for purposes of voting at Company stockholder meetings, these shares are considered outstanding and have voting rights, which are exercised by the Company.

Equity Compensation. The Company awards restricted common stock under incentive compensation plans that vest over specified periods, subject to certain conditions. All awards issued during and after 2006 have four-year vesting periods. Shares of restricted common stock are subject to restriction on transfer. Unvested restricted stock awards are included in the Company’s outstanding shares of common stock.

For the three and six-month periods ended June 30, 2011, the Company recognized stock-based compensation expense of $8.9 million and $17.1 million, net of $1.9 million and $3.7 million capitalized,

36

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

respectively, related to restricted common stock awards. For the three and six-month periods ended June 30, 2010, the Company recognized stock-based compensation expense of $7.3 million and $14.2 million, net of $1.3 million and $2.6 million capitalized, respectively, related to restricted common stock awards.

Noncontrolling Interest. Noncontrolling interests in one of the Company’s subsidiaries and three variable interest entities of which the Company is the primary beneficiary (see Note 8) represent third-party ownership interests in the consolidated entity and are included as a component of equity in the consolidated balance sheet and consolidated statement of changes in equity.

17. Related Party Transactions

The Company enters into transactions in the ordinary course of business with certain related parties. These transactions primarily consist of purchases related to drilling and completion activities, gas treating services and drilling equipment and sales of oil field services, equipment and natural gas. Following is a summary of significant transactions with such related parties (in thousands):

	Three Months Ended June  30,				Six Months Ended June 30,
	2011		2010		2011		2010
Sales to and reimbursements from related parties	$	6,947	$	4,166	$	11,735	$	6,823
					June 30, 2011		December 31, 2010
Accounts receivable due from related parties					$	2,153	$	1,702

Oklahoma City Thunder Agreements. The Company’s Chairman and Chief Executive Officer owns a minority interest in a limited liability company that owns and operates the Oklahoma City Thunder, a National Basketball Association team playing in Oklahoma City, where the Company is headquartered. The Company is party to a sponsorship agreement, through the 2013 season, whereby it pays approximately $3.3 million per year for advertising and promotional activities related to the Oklahoma City Thunder. Additionally, the Company entered into an agreement to license a suite at the arena where the Oklahoma City Thunder plays its home games. Under this four-year agreement, the Company pays an annual license fee of $0.2 million through 2013. Amounts related to these agreements are not included in the tables above. At June 30, 2011 the Company had no amounts due under these agreements. At December 31, 2010, the amount due under these agreements was $0.8 million.

18. Subsequent Events

Events occurring after June 30, 2011 were evaluated to ensure that any subsequent events that met the criteria for recognition and/or disclosure in this Quarterly Report have been included.

SandRidge Permian Trust. On May 25, 2011, the Company and SandRidge Permian Trust (the “Permian Trust”), a newly formed Delaware trust, filed a joint registration statement with the Securities and Exchange Commission (the “SEC”) relating to a proposed public offering of up to approximately $760.7 million (before underwriting discounts and offering expenses) in common units representing beneficial interests in the Permian Trust (including common units issuable upon exercise of the underwriters’ over-allotment option). Prior to the closing of this offering, the Company intends to convey certain royalty interests to the Permian Trust in exchange for units representing approximately 40% of the beneficial interest in the Permian Trust and the net proceeds of the Permian Trust’s public offering. The royalty interests will entitle the Permian Trust to a percentage of the

37

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

proceeds received by the Company from the production of hydrocarbons from currently producing wells and development wells to be drilled by the Company on approximately 15,900 net acres in the Permian Basin’s Central Basin Platform in Andrews County, Texas. There can be no assurance that this transaction will be completed, as it is subject to market conditions and other uncertainties, as well as completion of the SEC’s review process. If the transaction is completed, the Company intends to use the proceeds it receives to repay borrowings under its senior credit facility and for general corporate purposes.

Sale of Working Interest in Mississippian Properties. On August 3, 2011, the Company entered into an agreement with Atinum Partners Co., Ltd. (“Atinum”) pursuant to which the Company agreed to sell to Atinum a 13.2% undivided working interest in approximately 860,000 acres that the Company has leased in Oklahoma and Kansas for development of the Mississippian Lime horizontal play. In exchange for the working interest, Atinum will pay the Company $250.0 million in cash at closing and will pay $250.0 million of the Company’s costs to develop the acreage over the next three years. The agreement is subject to customary closing conditions and is expected to close during the fourth quarter of 2011.

19. Business Segment Information

The Company has three business segments: exploration and production, drilling and oil field services and midstream gas services. These segments represent the Company’s three main business units, each offering different products and services. The exploration and production segment is engaged in the acquisition, development and production of oil and natural gas properties. The drilling and oil field services segment is engaged in the contract drilling of oil and natural gas wells. The midstream gas services segment is engaged in the purchasing, gathering, treating and selling of natural gas. The All Other column in the tables below includes items not related to the Company’s reportable segments, including the Company’s CO₂ gathering and sales operations and corporate operations.

38

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Management evaluates the performance of the Company’s business segments based on operating income (loss), which is defined as segment operating revenues less operating expenses and depreciation, depletion and amortization. Summarized financial information concerning the Company’s segments is shown in the following tables (in thousands):

	Exploration  and Production			Drilling and Oil Field Services			Midstream  Gas Services			All Other			Consolidated Total
Three Months Ended June 30, 2011
Revenues	$	317,768		$	96,443		$	48,278		$	2,886		$	465,375
Inter-segment revenue		(66	)		(67,906	)		(32,473	)		(156	)		(100,601	)
Total revenues	$	317,702		$	28,537		$	15,805		$	2,730		$	364,774
Operating income (loss)	$	301,197		$	4,098		$	(2,570	)	$	(23,009	)	$	279,716
Interest income (expense), net		15			4			(141	)		(61,565	)		(61,687	)
Loss on extinguishment of debt		—			—			—			(2,051	)		(2,051	)
Other income (expense), net		3			—			216			(81	)		138
Income (loss) before income taxes	$	301,215		$	4,102		$	(2,495	)	$	(86,706	)	$	216,116
Capital expenditures(1)	$	423,725		$	8,030		$	4,462		$	17,875		$	454,092
Depreciation, depletion and amortization	$	76,734		$	7,998		$	1,291		$	3,438		$	89,461
Three Months Ended June 30, 2010
Revenues	$	150,571		$	55,975		$	66,379		$	8,744		$	281,669
Inter-segment revenue		(66	)		(52,063	)		(44,223	)		(2,878	)		(99,230	)
Total revenues	$	150,505		$	3,912		$	22,156		$	5,866		$	182,439
Operating income (loss)	$	136,465		$	(294	)	$	902		$	(17,621	)	$	119,452
Interest income (expense), net		121			(254	)		(161	)		(63,867	)		(64,161	)
Other income (expense), net		13			—			56			(599	)		(530	)
Income (loss) before income taxes	$	136,599		$	(548	)	$	797		$	(82,087	)	$	54,761
Capital expenditures(1)	$	218,973		$	8,195		$	16,337		$	5,459		$	248,964
Depreciation, depletion and amortization	$	55,041		$	6,833		$	927		$	3,338		$	66,139
Six Months Ended June 30, 2011
Revenues	$	585,004		$	163,992		$	104,256		$	6,106		$	859,358
Inter-segment revenue		(133	)		(114,421	)		(66,511	)		(672	)		(181,737	)
Total revenues	$	584,871		$	49,571		$	37,745		$	5,434		$	677,621
Operating income (loss)	$	116,990		$	3,990		$	(5,098	)	$	(43,995	)	$	71,887
Interest income (expense), net		120			(101	)		(313	)		(120,830	)		(121,124	)
Loss on extinguishment of debt		—			—			—			(38,232	)		(38,232	)
Other income (expense), net		1,679			—			(485	)		141			1,335
Income (loss) before income taxes	$	118,789		$	3,889		$	(5,896	)	$	(202,916	)	$	(86,134	)
Capital expenditures(1)	$	826,813		$	14,793		$	8,635		$	24,011		$	874,252
Depreciation, depletion and amortization	$	151,206		$	15,727		$	2,388		$	7,119		$	176,440
At June 30, 2011
Total assets	$	4,951,934		$	232,165		$	153,516		$	259,059		$	5,596,674

39

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

	Exploration  and Production			Drilling and Oil Field Services			Midstream  Gas Services			All Other			Consolidated Total
Six Months Ended June 30, 2010
Revenues	$	320,755		$	142,049		$	148,916		$	19,197		$	630,917
Inter-segment revenue		(131	)		(132,377	)		(99,233	)		(5,742	)		(237,483	)
Total revenues	$	320,624		$	9,672		$	49,683		$	13,455		$	393,434
Operating income (loss)	$	246,488		$	(4,594	)	$	2,156		$	(35,427	)	$	208,623
Interest expense (expense), net		200			(567	)		(299	)		(125,515	)		(126,181	)
Other income (expense), net		781			—			56			(131	)		706
Income (loss) before income taxes	$	247,469		$	(5,161	)	$	1,913		$	(161,073	)	$	83,148
Capital expenditures(1)	$	411,050		$	17,612		$	36,759		$	12,124		$	477,545
Depreciation, depletion and amortization	$	108,034		$	14,163		$	1,803		$	6,720		$	130,720
At December 31, 2010
Total assets	$	4,612,295		$	224,784		$	151,598		$	242,771		$	5,231,448

(1) On an accrual basis.

20. Condensed Consolidating Financial Information

The Company provides condensed consolidating financial information for its subsidiaries that are guarantors of its registered debt. The subsidiary guarantors are wholly owned and have jointly and severally guaranteed unconditionally on an unsecured basis the Company’s Senior Floating Rate Notes and 8.75% Senior Notes as of June 30, 2011. Prior to their purchase and redemption, the 8.625% Senior Notes were also jointly and severally guaranteed unconditionally on an unsecured basis by the wholly owned subsidiary guarantors. The subsidiary guarantees (i) rank equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) rank senior to all of the existing and future subordinated debt of the subsidiary guarantors; (iii) are effectively subordinated in right of payment to any existing or future secured obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; and (iv) are structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors who are not themselves guarantors. The Company’s subsidiary guarantors guarantee payments of principal and interest under the Company’s registered notes. The Company has not presented separate financial and narrative information for each of the subsidiary guarantors because it believes that such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the guarantees.

The following condensed consolidating financial information represents the financial information of SandRidge Energy, Inc., its wholly owned subsidiary guarantors and its non-guarantor subsidiaries, prepared on the equity basis of accounting. The non-guarantor subsidiaries and three variable interest entities are included in the non-guarantor column in the tables below. The financial information may not necessarily be indicative of the financial position, results of operations or cash flows had the subsidiary guarantors operated as independent entities.

40

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Condensed Consolidating Balance Sheets

	June 30, 2011
	Parent		Guarantors		Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	806	$	217	$	3,592	$	—		$	4,615
Accounts and notes receivable, net		1,107,468		155,236		474,528		(1,574,256	)		162,976
Derivative contracts		—		2,513		3,261		(3,261	)		2,513
Other current assets		—		12,686		7,782		—			20,468
Total current assets		1,108,274		170,652		489,163		(1,577,517	)		190,572
Property, plant and equipment, net		—		4,670,983		399,867		—			5,070,850
Investment in subsidiaries		3,289,504		50,925		—		(3,340,429	)		—
Goodwill		—		235,396		—		—			235,396
Other assets		56,662		43,194		1,562		(1,562	)		99,856
Total assets	$	4,454,440	$	5,171,150	$	890,592	$	(4,919,508	)	$	5,596,674
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	123,862	$	1,411,142	$	463,223	$	(1,574,256	)	$	423,971
Derivative contracts		9,552		143,083		—		(3,261	)		149,374
Asset retirement obligation		—		25,360		—		—			25,360
Other current liabilities		—		41,232		1,019		—			42,251
Total current liabilities		133,414		1,620,817		464,242		(1,577,517	)		640,956
Long-term debt		2,876,925		—		15,509		—			2,892,434
Derivative contracts		5,734		157,885		—		(1,562	)		162,057
Asset retirement obligation		—		93,606		174		—			93,780
Other liabilities		1,523		9,239		—		—			10,762
Total liabilities		3,017,596		1,881,547		479,925		(1,579,079	)		3,799,989
Equity		1,436,844		3,289,603		410,667		(3,340,429	)		1,796,685
Total liabilities and equity	$	4,454,440	$	5,171,150	$	890,592	$	(4,919,508	)	$	5,596,674

41

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

	December 31, 2010
	Parent		Guarantors		Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	1,441	$	564	$	3,858	$	—		$	5,863
Accounts and notes receivable, net		1,224,500		141,530		408,015		(1,627,927	)		146,118
Derivative contracts		—		5,028		—		—			5,028
Other current assets		—		13,890		4,691		—			18,581
Total current assets		1,225,941		161,012		416,564		(1,627,927	)		175,590
Property, plant and equipment, net		—		4,635,747		98,118		—			4,733,865
Investment in subsidiaries		3,230,067		69,995		—		(3,300,062	)		—
Goodwill		—		234,356		—		—			234,356
Other assets		50,637		37,000		—		—			87,637
Total assets	$	4,506,645	$	5,138,110	$	514,682	$	(4,927,989	)	$	5,231,448
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	66,539	$	1,510,827	$	427,483	$	(1,627,927	)	$	376,922
Derivative contracts		9,007		94,402		—		—			103,409
Asset retirement obligation		—		25,360		—		—			25,360
Other current liabilities		—		37,776		991		—			38,767
Total current liabilities		75,546		1,668,365		428,474		(1,627,927	)		544,458
Long-term debt		2,885,764		—		16,029		—			2,901,793
Derivative contracts		7,687		116,486		—		—			124,173
Asset retirement obligation		—		94,350		167		—			94,517
Other liabilities		1,454		17,570		—		—			19,024
Total liabilities		2,970,451		1,896,771		444,670		(1,627,927	)		3,683,965
Equity		1,536,194		3,241,339		70,012		(3,300,062	)		1,547,483
Total liabilities and equity	$	4,506,645	$	5,138,110	$	514,682	$	(4,927,989	)	$	5,231,448

42

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Condensed Consolidating Statements of Operations

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Three Months Ended June 30, 2011
Total revenues	$	—		$	341,481		$	56,289		$	(32,996	)	$	364,774
Expenses
Direct operating expenses		—			122,389			38,260			(32,742	)		127,907
General and administrative		104			36,608			1,220			(254	)		37,678
Depreciation, depletion, amortization and impairment		—			83,413			6,048			—			89,461
Gain on derivative contracts		—			(160,387	)		(9,601	)		—			(169,988	)
Total expenses		104			82,023			35,927			(32,996	)		85,058
(Loss) income from operations		(104	)		259,458			20,362			—			279,716
Equity earnings from subsidiaries		266,425			6,950			—			(273,375	)		—
Interest expense, net		(61,308	)		(121	)		(258	)		—			(61,687	)
Loss on extinguishment of debt		(2,051	)		—			—			—			(2,051	)
Other income, net		—			138			—			—			138
Income before income taxes		202,962			266,425			20,104			(273,375	)		216,116
Income tax benefit		(7,054	)		—			—			—			(7,054	)
Net income		210,016			266,425			20,104			(273,375	)		223,170
Less: net income attributable to noncontrolling interest		—			—			13,154			—			13,154
Net income attributable to SandRidge Energy, Inc.	$	210,016		$	266,425		$	6,950		$	(273,375	)	$	210,016
Three Months Ended June 30, 2010
Total revenues	$	—		$	174,404		$	27,357		$	(19,322	)	$	182,439
Expenses
Direct operating expenses		—			80,214			21,506			(19,116	)		82,604
General and administrative		86			32,861			1,124			(206	)		33,865
Depreciation, depletion, amortization and impairment		—			64,444			1,695			—			66,139
Gain on derivative contracts		—			(119,621	)		—			—			(119,621	)
Total expenses		86			57,898			24,325			(19,322	)		62,987
(Loss) income from operations		(86	)		116,506			3,032			—			119,452
Equity earnings from subsidiaries		117,094			1,544			—			(118,638	)		—
Interest expense, net		(63,594	)		(295	)		(272	)		—			(64,161	)
Other expense (income), net		73			(661	)		58			—			(530	)
Income before income taxes		53,487			117,094			2,818			(118,638	)		54,761
Income tax (benefit) expense		(28	)		—			178			—			150
Net income		53,515			117,094			2,640			(118,638	)		54,611
Less: net income attributable to noncontrolling interest		—			—			1,096			—			1,096
Net income attributable to SandRidge Energy, Inc.	$	53,515		$	117,094		$	1,544		$	(118,638	)	$	53,515

43

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Six Months Ended June 30, 2011
Total revenues	$	—		$	650,777		$	70,770		$	(43,926	)	$	677,621
Expenses
Direct operating expenses		—			241,617			51,472			(43,526	)		249,563
General and administrative		189			70,342			1,960			(400	)		72,091
Depreciation, depletion, amortization and impairment		—			168,652			7,788			—			176,440
(Loss) gain on derivative contracts		—			117,241			(9,601	)		—			107,640
Total expenses		189			597,852			51,619			(43,926	)		605,734
(Loss) income from operations		(189	)		52,925			19,151			—			71,887
Equity earnings from subsidiaries		59,437			5,712			—			(65,149	)		—
Interest expense, net		(120,315	)		(293	)		(516	)		—			(121,124	)
Loss on extinguishment of debt		(38,232	)		—			—			—			(38,232	)
Other income, net		—			1,093			242			—			1,335
(Loss) income before income taxes		(99,299	)		59,437			18,877			(65,149	)		(86,134	)
Income tax (benefit) expense		(6,971	)		—			4			—			(6,967	)
Net (loss) income		(92,328	)		59,437			18,873			(65,149	)		(79,167	)
Less: net income attributable to noncontrolling interest		—			—			13,161			—			13,161
Net (loss) income attributable to SandRidge Energy, Inc.	$	(92,328	)	$	59,437		$	5,712		$	(65,149	)	$	(92,328	)
Six Months Ended June 30, 2010
Total revenues	$	—		$	373,688		$	90,633		$	(70,887	)	$	393,434
Expenses
Direct operating expenses		—			162,856			77,744			(70,475	)		170,125
General and administrative		163			63,830			1,958			(412	)		65,539
Depreciation, depletion, amortization and impairment		—			127,369			3,351			—			130,720
Gain on derivative contracts		—			(181,573	)		—			—			(181,573	)
Total expenses		163			172,482			83,053			(70,887	)		184,811
(Loss) income from operations		(163	)		201,206			7,580			—			208,623
Equity earnings from subsidiaries		205,795			4,679			—			(210,474	)		—
Interest expense, net		(124,970	)		(666	)		(545	)		—			(126,181	)
Other income, net		74			576			56			—			706
Income before income taxes		80,736			205,795			7,091			(210,474	)		83,148
Income tax (benefit) expense		(16	)		—			178			—			162
Net income		80,752			205,795			6,913			(210,474	)		82,986
Less: net income attributable to noncontrolling interest		—			—			2,234			—			2,234
Net income attributable to SandRidge Energy, Inc.	$	80,752		$	205,795		$	4,679		$	(210,474	)	$	80,752

44

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Condensed Consolidating Statements of Cash Flows

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Six Months Ended June 30, 2011
Net cash provided by (used in) operating activities	$	94,579		$	162,726		$	3,699		$	—		$	261,004
Net cash used in investing activities		—			(163,785	)		(340,366	)		1,501			(502,650	)
Net cash (used in) provided by financing activities		(95,214	)		712			336,401			(1,501	)		240,398
Net (decrease) increase in cash and cash equivalents		(635	)		(347	)		(266	)		—			(1,248	)
Cash and cash equivalents at beginning of year		1,441			564			3,858			—			5,863
Cash and cash equivalents at end of period	$	806		$	217		$	3,592		$	—		$	4,615
Six Months Ended June 30, 2010
Net cash (used in) provided by operating activities	$	(160,436	)	$	417,020		$	1,875		$	—		$	258,459
Net cash used in investing activities		—			(413,221	)		(4,484	)		1,506			(416,199	)
Net cash provided by (used in) financing activities		160,266			(6,492	)		(306	)		(1,506	)		151,962
Net decrease in cash and cash equivalents		(170	)		(2,693	)		(2,915	)		—			(5,778	)
Cash and cash equivalents at beginning of year		339			2,841			4,681			—			7,861
Cash and cash equivalents at end of period	$	169		$	148		$	1,766		$	—		$	2,083

45

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

Introduction

The following discussion and analysis is intended to help the reader understand the Company’s business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with the Company’s condensed consolidated financial statements and the accompanying notes included in this Quarterly Report, as well as the Company’s audited consolidated financial statements and the accompanying notes included in the 2010 Form 10-K. The Company’s discussion and analysis includes the following subjects:

• Overview of the Company

• Recent Developments

• Recent Accounting Pronouncements

• Results by Segment

• Consolidated Results of Operations

• Liquidity and Capital Resources

The financial information with respect to the three and six-month periods ended June 30, 2011 and June 30, 2010, discussed below, is unaudited. In the opinion of management, this information contains all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the unaudited condensed consolidated financial statements. The results of operations for the interim periods are not necessarily indicative of the results of operations for the full fiscal year.

Overview of the Company

SandRidge is an independent oil and natural gas company concentrating on development and production activities related to the exploitation of the Company’s significant holdings in West Texas and the Mid-Continent area of Oklahoma and Kansas. The Company’s primary areas of focus are the Permian Basin in West Texas, the Mississippian formation in the Mid-Continent and the WTO. The Company also owns and operates other interests in the Mid-Continent, Cotton Valley Trend in East Texas, Gulf Coast and Gulf of Mexico. In 2009, the Company began expanding the oil component of its property base. This expansion included the purchase of properties from Forest Oil Corporation and one of its subsidiaries in December 2009 and the Arena Acquisition in July 2010, both of which added significantly to the Company’s holdings in the Permian Basin area. Concurrent with these acquisitions, the Company focused on increasing oil production in the Mid-Continent by significantly growing and developing its property base in that area.

The Company operates businesses that are complementary to its development and production activities. The Company owns related gas gathering and treating facilities, a gas marketing business and an oil field services business. The extent to which each of these supplemental businesses contributes to the Company’s consolidated results of operations largely is determined by the amount of work each performs for third parties. Revenues and costs related to work performed by these businesses for the Company’s own account are eliminated in consolidation and, therefore, do not directly contribute to the Company’s consolidated results of operations.

The Company currently generates the majority of its consolidated revenues and cash flow from the production and sale of oil and natural gas. The Company’s revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas and on the Company’s ability to find and economically develop and produce oil and natural gas reserves. Prices for oil and natural gas fluctuate widely. In order to reduce the Company’s exposure to these fluctuations, the Company enters into commodity derivative contracts for a portion of its anticipated future oil and natural gas production. Reducing the Company’s exposure to price volatility helps ensure that it has adequate funds available for its capital expenditure programs.

46

Recent Developments

SandRidge Mississippian Trust I. On April 12, 2011, the Mississippian Trust completed its initial public offering of 17,250,000 common units representing beneficial interests in the Mississippian Trust. Net proceeds to the Mississippian Trust, after certain offering expenses, were approximately $336.9 million. Concurrent with the closing, the Company conveyed certain royalty interests to the Mississippian Trust in exchange for the net proceeds of the Mississippian Trust’s initial public offering and 10,750,000 units (3,750,000 common units and 7,000,000 subordinated units) representing approximately 38.4% of the beneficial interest in the Mississippian Trust. The Company used the net proceeds it received from the Mississippian Trust’s offering to repay borrowings under the Company’s senior credit facility and for general corporate purposes.

In order to provide support for cash distributions on the Mississippian Trust’s common units, SandRidge agreed to subordinate a portion of the Mississippian Trust units it owns, which constitute 25% of the total outstanding Mississippian Trust units. The subordinated units are entitled to receive pro rata distributions from the Mississippian Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is no less than the applicable quarterly subordination threshold. If there is not sufficient cash to fund such a distribution on all common units, the distribution to be made with respect to the subordinated units will be reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on all common units, including common units held by the Company.

SandRidge and one of its wholly owned subsidiaries entered into a development agreement with the Mississippian Trust that obligates the Company to drill, or cause to be drilled, a specified number of wells, which are also subject to a royalty interest, by December 31, 2014. In the event of delays, the Company will have until December 31, 2015 to fulfill its drilling obligation. One of the Company’s wholly owned subsidiaries also granted to the Mississippian Trust a lien in the Company’s interests in the properties where the development wells will be drilled, in order to secure the estimated amount of the drilling costs for the wells. Additionally, the Company and the Mississippian Trust entered into an administrative services agreement and a derivatives agreement. As the Mississippian Trust is a variable interest entity of which SandRidge is the primary beneficiary, its activities were consolidated with those of SandRidge, beginning in April 2011.

SandRidge Permian Trust. On May 25, 2011, the Company and the Permian Trust, a newly formed Delaware trust, filed a joint registration statement with the SEC relating to a proposed public offering of up to approximately $760.7 million (before underwriting discounts and offering expenses) in common units representing beneficial interests in the Permian Trust (including common units issuable upon exercise of the underwriters’ over-allotment option). Prior to the closing of this offering, the Company intends to convey certain royalty interests to the Permian Trust in exchange for units representing approximately 40% of the beneficial interest in the Permian Trust and the net proceeds of the Permian Trust’s public offering. The royalty interests will entitle the Permian Trust to a percentage of the proceeds received by the Company from the production of hydrocarbons from currently producing wells and development wells to be drilled by the Company on approximately 15,900 net acres in the Permian Basin’s Central Basin Platform in Andrews County, Texas. There can be no assurance that this transaction will be completed, as it is subject to market conditions and other uncertainties, as well as completion of the SEC’s review process. If the transaction is completed, the Company intends to use the proceeds it receives to repay borrowings under its senior credit facility and for general corporate purposes.

Sale of Working Interest in Mississippian Properties. On August 3, 2011, the Company entered into an agreement with Atinum pursuant to which the Company agreed to sell to Atinum a 13.2% undivided working interest in approximately 860,000 acres that the Company has leased in Oklahoma and Kansas for development of the Mississippian Lime horizontal play. In exchange for the working interest, Atinum will pay the Company $250.0 million in cash at closing and will pay $250.0 million of the Company’s costs to develop the acreage over the next three years. The agreement is subject to customary closing conditions and is expected to close during the fourth quarter of 2011.

47

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements, see Note 2 to the Company’s condensed consolidated financial statements included in Item 1 of this Quarterly Report.

Results by Segment

SandRidge operates in three business segments: exploration and production, drilling and oil field services and midstream gas services. The All Other column in the tables below includes items not related to the Company’s reportable segments, including its CO₂ gathering and sales operations and corporate operations. Management evaluates the performance of the Company’s business segments based on operating income (loss), which is defined as segment operating revenues less operating expenses and depreciation, depletion and amortization. Results of these measurements provide important information to the Company about the activity and profitability of our lines of business. Set forth in the tables below is financial information regarding the Company’s business segments for the three and six-month periods ended June 30, 2011 and 2010 (in thousands).

	Exploration  and Production			Drilling and Oil Field Services			Midstream  Gas Services			All Other			Consolidated Total
Three Months Ended June 30, 2011
Revenues	$	317,768		$	96,443		$	48,278		$	2,886		$	465,375
Inter-segment revenue		(66	)		(67,906	)		(32,473	)		(156	)		(100,601	)
Total revenues	$	317,702		$	28,537		$	15,805		$	2,730		$	364,774
Operating income (loss)	$	301,197		$	4,098		$	(2,570	)	$	(23,009	)	$	279,716
Interest income (expense), net		15			4			(141	)		(61,565	)		(61,687	)
Loss on extinguishment of debt		—			—			—			(2,051	)		(2,051	)
Other income (expense), net		3			—			216			(81	)		138
Income (loss) before income taxes	$	301,215		$	4,102		$	(2,495	)	$	(86,706	)	$	216,116
Three Months Ended June 30, 2010
Revenues	$	150,571		$	55,975		$	66,379		$	8,744		$	281,669
Inter-segment revenue		(66	)		(52,063	)		(44,223	)		(2,878	)		(99,230	)
Total revenues	$	150,505		$	3,912		$	22,156		$	5,866		$	182,439
Operating income (loss)	$	136,465		$	(294	)	$	902		$	(17,621	)	$	119,452
Interest income (expense), net		121			(254	)		(161	)		(63,867	)		(64,161	)
Other income (expense), net		13			—			56			(599	)		(530	)
Income (loss) before income taxes	$	136,599		$	(548	)	$	797		$	(82,087	)	$	54,761

48

	Exploration  and Production			Drilling and Oil Field Services			Midstream  Gas Services			All Other			Consolidated Total
Six Months Ended June 30, 2011
Revenues	$	585,004		$	163,992		$	104,256		$	6,106		$	859,358
Inter-segment revenue		(133	)		(114,421	)		(66,511	)		(672	)		(181,737	)
Total revenues	$	584,871		$	49,571		$	37,745		$	5,434		$	677,621
Operating income (loss)	$	116,990		$	3,990		$	(5,098	)	$	(43,995	)	$	71,887
Interest income (expense), net		120			(101	)		(313	)		(120,830	)		(121,124	)
Loss on extinguishment of debt		—			—			—			(38,232	)		(38,232	)
Other income (expense), net		1,679			—			(485	)		141			1,335
Income (loss) before income taxes	$	118,789		$	3,889		$	(5,896	)	$	(202,916	)	$	(86,134	)
Six Months Ended June 30, 2010
Revenues	$	320,755		$	142,049		$	148,916		$	19,197		$	630,917
Inter-segment revenue		(131	)		(132,377	)		(99,233	)		(5,742	)		(237,483	)
Total revenues	$	320,624		$	9,672		$	49,683		$	13,455		$	393,434
Operating income (loss)	$	246,488		$	(4,594	)	$	2,156		$	(35,427	)	$	208,623
Interest income (expense), net		200			(567	)		(299	)		(125,515	)		(126,181	)
Other income (expense), net		781			—			56			(131	)		706
Income (loss) before income taxes	$	247,469		$	(5,161	)	$	1,913		$	(161,073	)	$	83,148

Exploration and Production Segment

The primary factors affecting the financial results of the Company’s exploration and production segment are the prices the Company receives for its oil and natural gas production, the quantity of oil and natural gas it produces and changes in the fair value of commodity derivative contracts used to reduce the volatility of the prices received for its oil and natural gas production. Quarterly comparisons of production and price data are presented in the tables below. Changes in the Company’s results for these periods reflect, in part, the acquisition of oil and natural gas properties in the Arena Acquisition in July 2010, which increased production volumes and revenues attributable to the Company’s exploration and production segment.

	Three Months Ended June 30,				Change
	2011		2010		Amount			Percent
Production data
Oil (MBbl)(1)		2,767		1,344		1,423			105.9	%
Natural gas (MMcf)		17,239		19,316		(2,077	)		(10.8	)%
Combined equivalent volumes (MBoe)		5,640		4,564		1,076			23.6	%
Average daily combined equivalent volumes (MBoe/d)		62		50		12			24.0	%
Average prices — as reported(2)
Oil (per Bbl)(1)	$	89.09	$	62.56	$	26.53			42.4	%
Natural gas (per Mcf)	$	3.81	$	3.41	$	0.40			11.7	%
Combined equivalent (per Boe)	$	55.34	$	32.87	$	22.47			68.4	%
Average prices — including impact of derivative contract settlements
Oil (per Bbl)(1)	$	76.26	$	65.86	$	10.40			15.8	%
Natural gas (per Mcf)	$	3.31	$	6.06	$	(2.75	)		(45.4	)%
Combined equivalent (per Boe)	$	47.52	$	45.03	$	2.49			5.5	%

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	Six Months Ended June 30,				Change
	2011		2010		Amount			Percent
Production data
Oil (MBbl)(1)		5,348		2,555		2,793			109.3	%
Natural gas (MMcf)		34,505		38,373		(3,868	)		(10.1	)%
Combined equivalent volumes (MBoe)		11,099		8,951		2,148			24.0	%
Average daily combined equivalent volumes (MBoe/d)		61		49		12			24.5	%
Average prices — as reported(2)
Oil (per Bbl)(1)	$	84.59	$	64.43	$	20.16			31.3	%
Natural gas (per Mcf)	$	3.67	$	4.04	$	(0.37	)		(9.2	)%
Combined equivalent (per Boe)	$	52.17	$	35.71	$	16.46			46.1	%
Average prices — including impact of derivative contract settlements
Oil (per Bbl)(1)	$	74.33	$	67.39	$	6.94			10.3	%
Natural gas (per Mcf)	$	3.46	$	6.40	$	(2.94	)		(45.9	)%
Combined equivalent (per Boe)	$	46.58	$	46.67	$	(0.09	)		(0.2	)%

(1) Includes natural gas liquids.

(2) Prices represent actual average prices for the periods presented and do not give effect to derivative transactions.

Exploration and Production Segment — Three months ended June 30, 2011 compared to the three months ended June 30, 2010

Exploration and production segment revenues increased $167.2 million, or 111.1%, to $317.7 million in the three months ended June 30, 2011 from $150.5 million in the three months ended June 30, 2010, as a result of a 105.9% increase in oil production and a 42.4% increase in the average price the Company received for its oil production. These increases were slightly offset by the 10.8% decrease in natural gas production. The increase in oil production was due to the addition of Permian Basin properties acquired from Arena, and a focus on increased oil drilling throughout 2010 and 2011. Properties acquired from Arena produced 985 MBbls of oil for the three-month period ended June 30, 2011. The decrease in natural gas production was a result of the decline in the number of rigs drilling for natural gas during 2010 and 2011 due to depressed natural gas prices.

The average price received for the Company’s oil production increased 42.4%, or $26.53 per barrel, to $89.09 per barrel during the three months ended June 30, 2011 from $62.56 per barrel during the same period in 2010. The average price received for the Company’s natural gas production for the three-month period ended June 30, 2011 increased 11.7%, or $0.40 per Mcf, to $3.81 per Mcf from $3.41 per Mcf in the comparable period in 2010. Including the impact of derivative contract settlements, the effective price received for oil for the three-month period ended June 30, 2011 was $76.26 per Bbl compared to $65.86 per Bbl during the same period in 2010. Including the impact of derivative contract settlements, the effective price received for natural gas for the three-month period ended June 30, 2011 was $3.31 per Mcf compared to $6.06 per Mcf during the same period in 2010. The Company’s derivative contracts are not designated as hedges and, as a result, gains or losses on commodity derivative contracts are recorded as a component of operating expenses. Internally, management views the settlement of such derivative contracts as adjustments to the price received for oil and natural gas production to determine “effective prices.” Realized gains or losses from the settlement of derivative contracts with contractual maturities outside of the reporting period are not considered in the calculation of “effective prices.”

During the three-month period ended June 30, 2011, the exploration and production segment reported a $170.0 million net gain on its commodity derivative positions ($18.3 million realized loss and $188.3 million unrealized gain) compared to a $119.6 million net gain on its commodity derivative positions ($117.9 million realized gain and $1.7 million unrealized gain) in the same period in 2010. The realized loss for the three months

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ended June 30, 2011 was primarily due to higher oil prices at the time of settlement compared to the contract price. Realized gains totaling $25.8 million resulting from settlements of commodity derivative contracts with original contractual maturities after June 30, 2011 were included in the net realized loss for the three months ended June 30, 2011. The realized gain of $117.9 million for the three months ended June 30, 2010 was primarily due to lower natural gas prices at the time of settlement compared to the contract price. Realized gains totaling $62.4 million resulting from settlements of commodity derivative contracts with original contractual maturities after June 30, 2010 were included in the net realized gain for the three-month period ended June 30, 2010. Unrealized gains or losses on derivative contracts represent the change in fair value of open derivative contracts during the period. The unrealized gain on the Company’s commodity contracts recorded during the three months ended June 30, 2011 was primarily attributable to a decrease in average oil prices at June 30, 2011 compared to the average oil prices at March 31, 2011 or the contract price for contracts entered into during the second quarter of 2011. The unrealized gain on the Company’s commodity contracts recorded during the three months ended June 30, 2010 was attributable to a decrease in average oil prices and increases in the price differentials on the Company’s basis swaps at June 30, 2010 compared to the average oil prices and price differentials at March 31, 2010. This amount was partially offset by increases in the average natural gas price at June 30, 2010 compared to the average natural gas price at March 31, 2010.

For the three months ended June 30, 2011, the Company had operating income of $301.2 million in its exploration and production segment compared to operating income of $136.5 million for the same period in 2010. The increases of $162.1 million in oil and natural gas revenues and $50.4 million in gain on derivative contracts were partially offset by increases of $25.8 million in production expense and $21.9 million in depreciation and depletion on oil and natural gas properties during the three months ended June 30, 2011. See discussion of production expense and depreciation and depletion under “Consolidated Results of Operations.”

Exploration and Production Segment — Six months ended June 30, 2011 compared to the six months ended June 30, 2010

Exploration and production segment revenues increased $264.3 million, or 82.4%, to $584.9 million in the six months ended June 30, 2011 from $320.6 million in the six months ended June 30, 2010, as a result of a 109.3% increase in oil production and a 31.3% increase in the average price the Company received for its oil production. These increases were slightly offset by the 10.1% decrease in natural gas production and a 9.2% decrease in the average price received for the Company’s natural gas production. The increase in oil production was due to the addition of Permian Basin properties acquired from Arena, and a focus on increased oil drilling throughout 2010 and 2011. Properties acquired from Arena produced 1,870 MBbls of oil for the six-month period ended June 30, 2011. The decrease in natural gas production was a result of the decline in the number of rigs drilling for natural gas during 2010 and 2011 due to depressed natural gas prices.

The average price received for the Company’s oil production increased 31.3%, or $20.16 per barrel, to $84.59 per barrel during the six months ended June 30, 2011 from $64.43 per barrel during the same period in 2010. The average price received for the Company’s natural gas production for the six-month period ended June 30, 2011 decreased 9.2%, or $0.37 per Mcf, to $3.67 per Mcf from $4.04 per Mcf in the comparable period in 2010. Including the impact of derivative contract settlements, the effective price received for oil for the six-month period ended June 30, 2011 was $74.33 per Bbl compared to $67.39 per Bbl during the same period in 2010. Including the impact of derivative contract settlements, the effective price received for natural gas for the six-month period ended June 30, 2011 was $3.46 per Mcf compared to $6.40 per Mcf during the same period in 2010.

During the six-month period ended June 30, 2011, the exploration and production segment reported a $107.6 million net loss on its commodity derivative positions ($26.9 million realized loss and $80.7 million unrealized loss) compared to a $181.6 million net gain on its commodity derivative positions ($160.6 million realized gain and $21.0 million unrealized gain) in the same period in 2010. The realized loss for the six months ended June 30, 2011 was primarily due to higher oil prices at the time of settlement compared to the contract price. Realized gains totaling $38.2 million resulting from settlements of commodity derivative contracts with

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original contractual maturities after the quarterly period in which they were settled were included in the net realized loss for the six months ended June 30, 2011. The realized gain of $160.6 million for the six months ended June 30, 2010 was primarily due to lower natural gas prices at the time of settlement compared to the contract price. Realized gains totaling $62.4 million resulting from settlements of commodity derivative contracts with original contractual maturities after the quarterly period in which they were settled were included in the net realized gain for the six months ended June 30, 2010. The unrealized loss on the Company’s commodity contracts recorded during the six months ended June 30, 2011 was primarily attributable to an increase in average oil prices at June 30, 2011 compared to the average oil prices at December 31, 2010 or the contract price for contracts entered into during first six months of 2011. The unrealized gain for the six-month period ended June 30, 2010 was attributable to a decrease in average oil prices and increases in the price differentials on the Company’s basis swaps at June 30, 2010 compared to the average oil prices and price differentials at December 31, 2009 or the contract price for contracts entered into during the first six months of 2010. This amount was partially offset by increases in the average price of natural gas at June 30, 2010 compared to the average price of natural gas at December 31, 2009, or as stated in the contract for contracts entered into during the first six months of 2010.

For the six months ended June 30, 2011, the Company had operating income of $117.0 million in its exploration and production segment compared to operating income of $246.5 million for the same period in 2010. Offsetting the $259.5 million increase in oil and natural gas revenues were the increases of $49.5 million in production expense and $43.5 million in depreciation and depletion on oil and natural gas properties during the six months ended June 30, 2011. Additionally, the Company recorded a $107.6 million net loss on the Company’s commodity derivative contracts for the six months ended June 30, 2011 compared to a $181.6 million net gain for the same period in 2010. See discussion of production expense and depreciation and depletion under “Consolidated Results of Operations.”

Drilling and Oil Field Services Segment

The financial results of the Company’s drilling and oil field services segment depend primarily on demand and prices that can be charged for its services. In addition to providing drilling services, the Company’s oil field services business also conducts operations that complement its exploration and production segment such as providing pulling units, trucking, rental tools, location and road construction and roustabout services. On a consolidated basis, drilling and oil field service revenues earned and expenses incurred in performing services for third parties, including third party working interests in wells the Company operates, are included in drilling and services revenues and expenses while drilling and oil field service revenues earned and expenses incurred in performing services for the Company’s own account are eliminated in consolidation.

As of June 30, 2011, the Company owned 31 drilling rigs. The table below presents a summary of the Company’s rigs as of June 30, 2011 and 2010:

	June 30,
	2011		2010
Rigs working for SandRidge		20		20
Rigs working for third parties		11		2
Idle rigs		—		4
Total operational		31		26
Non-operational rigs(1)		—		5
Total rigs owned		31		31

(1) Includes two rigs being constructed, two rigs being converted and one rig that was retired at June 30, 2010.

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Drilling and Oil Field Services Segment — Three months ended June 30, 2011 compared to the three months ended June 30, 2010

Drilling and oil field services segment revenues increased to $28.5 million in the three-month period ended June 30, 2011 from $3.9 million in the three-month period ended June 30, 2010 and drilling and oil field services segment expenses increased $20.2 million to $24.4 million during the same period. The increase in revenue resulted in operating income of $4.1 million in the three-month period ended June 30, 2011 compared to an operating loss of $0.3 million for the same period in 2010. The increase in revenues and expenses was primarily attributable to an increase in the number of rigs working for third parties and an increase in oil field services performed for third parties during the 2011 period. The increase in the number of rigs working for third parties was a result of increased demand for the Company’s rigs and the result of additional rigs becoming available in West Texas as the Company decreased its drilling activity in the WTO beginning in 2010 and transitioned to drilling more oil wells in the Permian Basin and Mid-Continent areas.

Drilling and Oil Field Services Segment — Six months ended June 30, 2011 compared to the six months ended June 30, 2010

Drilling and oil field services segment revenues increased to $49.6 million in the six-month period ended June 30, 2011 from $9.7 million in the six-month period ended June 30, 2010 and drilling and oil field services segment expenses increased $31.3 million during the same period to $45.6 million. The increase in revenue resulted in operating income of $4.0 million in the six-month period ended June 30, 2011 compared to an operating loss of $4.6 million for the same period in 2010. The increase in revenues and expenses was primarily attributable to an increase in the number of rigs working for third parties and an increase in oil field services performed for third parties during the 2011 period.

Midstream Gas Services Segment

Midstream gas services segment revenues consist mostly of revenue from gas marketing, which is a very low-margin business. Midstream gas services are primarily undertaken to realize incremental margins on natural gas purchased at the wellhead, and provide value-added services to customers. On a consolidated basis, midstream and marketing revenues represent natural gas sold on behalf of third parties and the fees the Company charges to gather, compress and treat this natural gas. Gas marketing operating costs represent payments made to third parties for the proceeds from the sale of natural gas owned by such parties, net of any applicable margin and actual costs the Company charges to gather, compress and treat the natural gas. In general, natural gas purchased and sold by the Company’s midstream gas business is priced at a published daily or monthly index price. The primary factors affecting the results of the Company’s midstream gas services segment are the quantity of natural gas the Company gathers, treats and markets and the prices it pays and receives for natural gas.

The Company owns and operates two gas treating plants in West Texas, which remove CO₂ from natural gas production and deliver residue gas to nearby pipelines. During the first six months of 2011, the Company continued with the operational assessment phase of the Century Plant, in Pecos County, Texas, including diverting some of the Company’s natural gas from the Company’s gas treating plants and processing it at the Century Plant during this time. As a result of this assessment, in April 2011, the Century Plant was taken off line to resolve certain operational issues. The Company is currently in the process of diverting its high CO₂ natural gas production back through the Century Plant and anticipates commencing performance testing for Train 1 of the Century Plant during the third quarter of 2011. Upon successful completion of the performance testing, the use of the Company’s two gas treating plants in West Texas may be limited, the extent of which will depend on certain variables, including natural gas prices and the expected need for such plants to back up the Century Plant going forward. During the second quarter of 2011, the Company evaluated its gas treating plants for impairment in connection with completion of the operational assessment phase of Train I of the Century Plant and concluded there was no impairment necessary.

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Midstream Gas Services Segment — Three months ended June 30, 2011 compared to the three months ended June 30, 2010

Midstream gas services segment revenues for the three months ended June 30, 2011 were $15.8 million compared to $22.2 million in the same period in 2010. The decrease in revenue along with the continued impact of fixed charges resulted in an operating loss of $2.6 million for the three months ended June 30, 2011 compared to operating income of $0.9 million for the comparable period in 2010. The decrease in revenue was due to a decrease in third party volumes the Company marketed and a decrease in natural gas volumes processed in the Company’s gas treating plants in the three-month period ended June 30, 2011 compared to the same period in 2010.

Midstream Gas Services Segment — Six months ended June 30, 2011 compared to the six months ended June 30, 2010

Midstream gas services segment revenues for the six months ended June 30, 2011 were $37.7 million compared to $49.7 million in the same period in 2010. The decrease in revenue along with the continued impact of fixed charges resulted in an operating loss of $5.1 million for the six months ended June 30, 2011 compared to operating income of $2.2 million for the comparable period in 2010. The decrease in revenue was due to a decrease in third party volumes the Company marketed, a decrease in natural gas prices and a decrease in natural gas volumes processed in the Company’s gas treating plants in the six-month period ended June 30, 2011 compared to the same period in 2010.

Consolidated Results of Operations

Three months ended June 30, 2011 compared to the three months ended June 30, 2010

Revenues. Total revenues increased 99.9% for the three months ended June 30, 2011 from the same period in 2010. This increase was primarily due to the increase in oil and natural gas sales.

	Three Months Ended June 30,
	2011		2010		$ Change			% Change
	(In thousands)
Revenues
Oil and natural gas	$	312,111	$	149,995	$	162,116			108.1	%
Drilling and services		28,537		3,901		24,636			631.5	%
Midstream and marketing		16,313		22,598		(6,285	)		(27.8	)%
Other		7,813		5,945		1,868			31.4	%
Total revenues	$	364,774	$	182,439	$	182,335			99.9	%

Total oil and natural gas revenues increased $162.1 million for the three months ended June 30, 2011 compared to the same period in 2010, primarily as a result of an increase in the amount of oil the Company produced and the price received for the Company’s oil production, offset slightly by a decrease in the amount of natural gas the Company produced. The 1,423 MBbl increase in oil production was primarily due to the properties acquired from Arena and the Company’s focus on increased oil drilling throughout 2010 and into 2011. The average price received for the Company’s oil production, excluding the impact of derivative contracts, increased 42.4% in the 2011 period to $89.09 per Bbl compared to $62.56 per Bbl in 2010.

Drilling and services revenues increased $24.6 million for the three months ended June 30, 2011 compared to the same period in 2010 due to an increase in the number of rigs working for third parties and an increase in oil field services work performed for third parties.

Midstream and marketing revenues decreased $6.3 million, or 27.8%, in the three-month period ended June 30, 2011 compared to the three-month period ended June 30, 2010. The decrease in midstream and

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marketing revenues was attributable to a decrease in third party volumes the Company marketed due to decreased natural gas production and a decrease in natural gas volumes processed at the Company’s gas treating plants in the three-month period ended June 30, 2011 compared to the same period in 2010.

Operating Costs and Expenses. Total operating costs and expenses increased to $85.1 million for the three months ended June 30, 2011 compared to $63.0 million for the same period in 2010. The increase was primarily due to increases in production expenses, production taxes, drilling and services expense and depreciation and depletion on oil and natural gas properties.

	Three Months Ended June 30,
	2011			2010			$ Change			% Change
	(In thousands)
Operating costs and expenses
Production	$	81,834		$	56,009		$	25,825			46.1	%
Production taxes		12,666			5,404			7,262			134.4	%
Drilling and services		18,058			1,024			17,034			1,663.5	%
Midstream and marketing		15,873			19,779			(3,906	)		(19.7	)%
Depreciation and depletion — oil and natural gas		76,186			54,319			21,867			40.3	%
Depreciation and amortization — other		13,275			11,820			1,455			12.3	%
General and administrative		37,678			33,865			3,813			11.3	%
Gain on derivative contracts		(169,988	)		(119,621	)		(50,367	)		42.1	%
(Gain) loss on sale of assets		(524	)		388			(912	)		(235.1	)%
Total operating costs and expenses	$	85,058		$	62,987		$	22,071			35.0	%

Production expenses include the costs associated with the Company’s exploration and production activities, including, but not limited to, lease operating expenses and treating costs. Production expenses increased $25.8 million primarily due to the addition of operating expenses associated with properties acquired from Arena and newly completed oil wells brought on production during late 2010 and the first six months of 2011. Additionally, higher production costs were incurred on oil production compared to production costs on natural gas volumes as oil volumes continued to comprise a larger portion of the Company’s total production. Oil production increased 1,423 MBbls in the three-month period ended June 30, 2011 compared to the same period in 2010.

Production taxes increased $7.3 million, or 134.4%, due to taxes on increased oil production, including taxes for production from properties acquired from Arena and newly producing wells, in the three-month period ended June 30, 2011 compared to the same period in 2010.

Drilling and services expenses, which include operating expenses attributable to the drilling and oil field services segment and the Company’s CO₂ services company, increased $17.0 million for the three months ended June 30, 2011 compared to the same period in 2010 primarily due to an increase in the number of rigs working for third parties and an increase in oil field services work performed for third parties during the three-month period ended June 30, 2011 compared to the same period in 2010.

Midstream and marketing expenses decreased $3.9 million, or 19.7%, to $15.9 million due to decreased volumes of natural gas purchased from third parties as a result of decreased natural gas production during the three-month period ended June 30, 2011.

Depreciation and depletion for the Company’s oil and natural gas properties increased $21.9 million for the three-month period ended June 30, 2011 from the same period in 2010. The increase was primarily due to an increase in depreciation and depletion per Boe to $13.51 in the second quarter of 2011 from $11.90 per Boe in

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the comparable period in 2010 as a result of an increase to the Company’s depreciable oil and natural gas properties, primarily due to the acquisition of properties from Arena and an increase in the Company’s combined production volume.

The Company recorded a net gain of $170.0 million ($18.3 million realized loss and $188.3 million unrealized gain) on its commodity derivative contracts for the three-month period ended June 30, 2011 compared to a net gain of $119.6 million ($117.9 million realized gain and $1.7 million unrealized gain) in the same period of 2010. See further discussion of gains and losses on commodity derivative contracts under “Results by Segment — Exploration and Production Segment.”

Other Income (Expense). Total other expense decreased to $63.6 million in the three-month period ended June 30, 2011 from $64.7 million in the three-month period ended June 30, 2010. The decrease is reflected in the table below.

	Three Months Ended June 30,
	2011			2010			$ Change			% Change
	(In thousands)
Other income (expense)
Interest income	$	38		$	98		$	(60	)		(61.2	)%
Interest expense		(61,725	)		(64,259	)		2,534			(3.9	)%
Loss on extinguishment of debt		(2,051	)		—			(2,051	)		(100.0	)%
Other income (expense), net		138			(530	)		668			(126.0	)%
Total other expense	$	(63,600	)	$	(64,691	)	$	1,091			(1.7	)%
Income before income taxes	$	216,116		$	54,761		$	161,355			294.7	%
Income tax (benefit) expense		(7,054	)		150			(7,204	)		(4,802.7	)%
Net income		223,170			54,611			168,559			308.7	%
Less: net income attributable to noncontrolling interest		13,154			1,096			12,058			1,100.2	%
Net income attributable to SandRidge Energy, Inc.	$	210,016		$	53,515		$	156,501			292.4	%

Interest expense decreased to $61.7 million for the three months ended June 30, 2011 from $64.3 million for the same period in 2010. This decrease was primarily attributable to a $3.7 million decrease in the net loss on the Company’s interest rate swap for the three-month period ending June 30, 2011 compared to the same period in 2010, slightly offset by an increase in interest expense due to higher average debt balances outstanding for the three months ending June 30, 2011.

In connection with the redemption of the remaining 8.625% Senior Notes, the Company recognized a loss on extinguishment of debt of $2.0 million in the second quarter of 2011. The loss represents the premium paid to redeem these notes and the unamortized debt issuance costs associated with the remaining notes.

In the second quarter of 2011, the Company completed its valuation of assets acquired and liabilities assumed related to the Arena Acquisition in order to finalize the purchase price allocation. In connection therewith, the Company recorded an additional net deferred tax liability of $7.0 million associated with the Arena Acquisition. Management determined that it is more likely than not that the Company will now realize a benefit from more of its existing deferred tax assets as the additional Arena deferred tax liabilities are available to offset the reversal of the Company’s deferred tax assets. Accordingly, the tax benefit of $7.1 million for the three-month period ended June 30, 2011 is primarily comprised of the partial release of the Company’s previously recorded valuation allowance against its net deferred tax asset.

Net income attributable to noncontrolling interest increased to $13.2 million for the three months ended June 30, 2011 from $1.1 million for the same period in 2010 due to completion of the Mississippian Trust’s

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initial public offering in April 2011. As a result of the offering, 17,250,000 common units, or approximately 61.6% of the Mississippian Trust’s beneficial interests, are held by third parties. The portion of the Mississippian Trust’s net income or loss attributable to beneficial interests held by third parties is reflected as net income or loss attributable to noncontrolling interest.

Six months ended June 30, 2011 compared to the six months ended June 30, 2010

Revenues. Total revenues increased 72.2% for the six months ended June 30, 2011 from the same period in 2010. This increase was primarily due to the increase in oil and natural gas sales.

	Six Months Ended June 30,
	2011		2010		$ Change			% Change
	(In thousands)
Revenues
Oil and natural gas	$	579,053	$	319,580	$	259,473			81.2	%
Drilling and services		49,571		9,661		39,910			413.1	%
Midstream and marketing		38,570		50,587		(12,017	)		(23.8	)%
Other		10,427		13,606		(3,179	)		(23.4	)%
Total revenues	$	677,621	$	393,434	$	284,187			72.2	%

Total oil and natural gas revenues increased $259.5 million for the six months ended June 30, 2011 compared to the same period in 2010, primarily as a result of an increase in the amount of oil the Company produced and the price received for the Company’s oil production, offset slightly by a decrease in the amount of natural gas the Company produced as well as decreased prices received for the Company’s natural gas production. The 2,793 MBbl increase in oil production was primarily due to the properties acquired from Arena and the Company’s focus on increased oil drilling throughout 2010 and in 2011. The average price received for the Company’s oil production, excluding the impact of derivative contracts, increased 31.3% in the 2011 period to $84.59 per Bbl compared to $64.43 per Bbl in 2010.

Drilling and services revenues increased $39.9 million for the six months ended June 30, 2011 compared to the same period in 2010 due to an increase in the number of rigs working for third parties and an increase in oil field services work performed for third parties.

Midstream and marketing revenues decreased $12.0 million, or 23.8%, in the six-month period ended June 30, 2011 compared to the six-month period ended June 30, 2010. The decrease in midstream and marketing revenues was attributable to a decrease in third party volumes the Company marketed due to decreased natural gas production, a decrease in natural gas prices and a decrease in natural gas volumes processed at the Company’s gas treating plants in the six-month period ended June 30, 2011 compared to the same period in 2010.

Other revenues decreased $3.2 million for the six months ended June 30, 2011 from the same period in 2010. The decrease was due to lower CO₂ volumes sold to third parties from the Company’s gas treating plants during the six-month period ended June 30, 2011 compared to the same period in 2010 as a result of less natural gas treated at these plants.

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Operating Costs and Expenses. Total operating costs and expenses increased to $605.7 million for the six months ended June 30, 2011 compared to $184.8 million for the same period in 2010. The increase was primarily due to increases in production expenses, production taxes, drilling and services expense and depreciation and depletion on oil and natural gas properties and the loss on derivative contracts.

	Six Months Ended June 30,
	2011			2010			$ Change			% Change
	(In thousands)
Operating costs and expenses
Production	$	155,791		$	106,281		$	49,510			46.6	%
Production taxes		23,242			10,242			13,000			126.9	%
Drilling and services		33,099			8,233			24,866			302.0	%
Midstream and marketing		38,156			45,285			(7,129	)		(15.7	)%
Depreciation and depletion — oil and natural gas		150,072			106,597			43,475			40.8	%
Depreciation and amortization — other		26,368			24,123			2,245			9.3	%
General and administrative		72,091			65,539			6,552			10.0	%
Loss (gain) on derivative contracts		107,640			(181,573	)		289,213			(159.3	)%
(Gain) loss on sale of assets		(725	)		84			(809	)		(963.1	)%
Total operating costs and expenses	$	605,734		$	184,811		$	420,923			227.8	%

Production expenses increased $49.5 million primarily due to the addition of operating expenses associated with properties acquired from Arena and additional oil wells brought on production during late 2010 and the first six months of 2011. Additionally, higher production costs were incurred on oil production compared to production costs on natural gas volumes. Oil production increased 2,793 MBbls in the six-month period ended June 30, 2011 compared to the same period in 2010.

Production taxes increased $13.0 million, or 126.9%, due to taxes on increased oil production, including taxes for production from properties acquired from Arena and additional oil wells brought on production during late 2010 and the first six months of 2011, in the six-month period ended June 30, 2011 compared to the same period in 2010.

Drilling and services expenses increased $24.9 million, or 302.0%, for the six months ended June 30, 2011 compared to the same period in 2010 primarily due to an increase in the number of rigs working for third parties and an increase in oil field services work performed for third parties during the six-month period ended June 30, 2011 compared to the same period in 2010.

Midstream and marketing expenses decreased $7.1 million, or 15.7%, to $38.2 million due to decreased volumes of natural gas purchased from third parties as a result of decreased natural gas production during the six-month period ended June 30, 2011.

Depreciation and depletion for the Company’s oil and natural gas properties increased $43.5 million for the six-month period ended June 30, 2011 from the same period in 2010. The increase was primarily due to an increase in the depreciation and depletion per Boe to $13.52 in the first six months of 2011 from $11.91 per Boe in the comparable period in 2010 as a result of an increase to the Company’s depreciable oil and natural gas properties, primarily due to the acquisition of properties from Arena, and an increase in the Company’s combined production volume.

The Company recorded a net loss of $107.6 million ($26.9 million realized loss and $80.7 million unrealized loss) on its commodity derivative contracts for the six-month period ended June 30, 2011 compared to a net gain of $181.6 million ($160.6 million realized gain and $21.0 million unrealized gain) in the same period of 2010. See further discussion of gains and losses on commodity derivative contracts under “Results by Segment — Exploration and Production Segment.”

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Other Income (Expense). Total other expense increased to $158.0 million in the six-month period ended June 30, 2011 from $125.5 million in the six-month period ended June 30, 2010. The increase is reflected in the table below.

	Six Months Ended June 30,
	2011			2010			$ Change			% Change
	(In thousands)
Other income (expense)
Interest income	$	43		$	167		$	(124	)		(74.3	)%
Interest expense		(121,167	)		(126,348	)		5,181			(4.1	)%
Loss on extinguishment of debt		(38,232	)		—			(38,232	)		(100.0	)%
Other income, net		1,335			706			629			89.1	%
Total other expense	$	(158,021	)	$	(125,475	)	$	(32,546	)		25.9	%
(Loss) income before income taxes	$	(86,134	)	$	83,148		$	(169,282	)		(203.6	)%
Income tax (benefit) expense		(6,967	)		162			(7,129	)		(4,400.6	)%
Net (loss) income		(79,167	)		82,986			(162,153	)		(195.4	)%
Less: net income attributable to noncontrolling interest		13,161			2,234			10,927			489.1	%
Net (loss) income attributable to SandRidge Energy, Inc.	$	(92,328	)	$	80,752		$	(173,080	)		(214.3	)%

Interest expense decreased to $121.2 million for the six months ended June 30, 2011 from $126.3 million for the same period in 2010. This decrease was primarily attributable to a $9.3 million decrease in the net loss on the Company’s interest rate swaps for the six-month period ending June 30, 2011 compared to the same period in 2010, partially offset by an increase in interest expense due to higher average debt balances outstanding for the six months ending June 30, 2011.

In connection with the tender offer to repurchase and the redemption of the 8.625% Senior Notes, the Company recognized a loss on extinguishment of debt of $38.2 million for the six-month period ended June 30, 2011. The loss represents the premium paid to purchase these notes and the unamortized debt issuance costs associated with the notes.

In the second quarter of 2011, the Company completed its valuation of assets acquired and liabilities assumed related to the Arena Acquisition in order to finalize the purchase price allocation. In connection therewith, the Company recorded an additional net deferred tax liability of $7.0 million associated with the Arena Acquisition. Management determined that it is more likely than not that the Company will now realize a benefit from more of its existing deferred tax assets as the additional Arena deferred tax liabilities are available to offset the reversal of the Company’s deferred tax assets. Accordingly, the tax benefit of $7.0 million for the six-month period ended June 30, 2011 is primarily comprised of the partial release of the Company’s previously recorded valuation allowance against its net deferred tax asset.

Net income attributable to noncontrolling interest increased to $13.2 million for the six months ended June 30, 2011 compared to $2.2 million for the same period in 2010 due to completion of the Mississippian Trust’s initial public offering in April 2011, which resulted in approximately 61.6% of the Mississippian Trust units being held by third parties.

Liquidity and Capital Resources

The Company’s primary sources of liquidity and capital resources are cash flow generated from operations, borrowings under the Company’s senior credit facility, the issuance of equity and debt securities and proceeds from sales or other monetization of assets. As described in “Recent Developments,” the Company received proceeds of $336.9 million in April 2011 as partial consideration for conveyance of royalty interests in certain of the Company’s oil and natural gas properties to the Mississippian Trust. The Company’s primary uses of capital

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are expenditures related to its oil and natural gas properties and other fixed assets, the acquisition of oil and natural gas properties, the repayment of amounts outstanding on its senior credit facility, the payment of dividends on its outstanding convertible perpetual preferred stock and interest payments on its outstanding debt. The Company maintains access to funds that may be needed to meet capital funding requirements through its senior credit facility.

Working Capital

The Company’s working capital balance fluctuates as a result of the timing and amount of borrowings or repayments under its credit arrangements and changes in the fair value of its outstanding commodity derivative instruments. Absent any significant effects from its commodity derivative instruments, the Company typically has a working capital deficit or a relatively small amount of positive working capital because the Company’s capital spending generally has exceeded the Company’s cash flows from operations and it generally uses excess cash to pay down borrowings outstanding under its credit arrangements.

At June 30, 2011, the Company had a working capital deficit of $450.4 million compared to a deficit of $368.9 million at December 31, 2010. Current assets increased $15.0 million at June 30, 2011, compared to current assets at December 31, 2010, primarily due to an increase in accounts receivable balances as a result of increased oil production and prices received on the Company’s oil production. Current liabilities increased $96.5 million, primarily due to a $47.0 million increase in accounts payable and accrued expenses due to increased drilling activity and a $46.0 million increase in the liability positions on the Company’s current derivative contracts, resulting primarily from an increase in average oil prices at June 30, 2011 compared to applicable contract prices.

The Company expects to fund its planned capital expenditures budget, debt service requirements and working capital needs for 2011 based on cash flow from operating activities, availability under its senior credit facility, potential access to the capital markets and anticipated proceeds from sales or other monetizations of assets.

Cash Flows

The Company’s cash flows for the six months ended June 30, 2011 and 2010 were as follows:

	Six Months Ended June 30,
	2011			2010
	(In thousands)
Cash flows provided by operating activities	$	261,004		$	258,459
Cash flows used in investing activities		(502,650	)		(416,199	)
Cash flows provided by financing activities		240,398			151,962
Net decrease in cash and cash equivalents	$	(1,248	)	$	(5,778	)

Cash Flows from Operating Activities

The Company’s operating cash flow is mainly influenced by the prices the Company receives for its oil and natural gas production; the quantity of oil and natural gas it produces; third-party demand for its drilling rigs and oil field services and the rates it is able to charge for these services; and the margins it obtains from its natural gas and CO₂ gathering and treating contracts.

Net cash provided by operating activities for the six months ended June 30, 2011 and 2010 was $261.0 million and $258.5 million, respectively. Cash provided by operating activities increased slightly due to an increase in oil production and prices, which was partially offset by a decrease in realized gains on our commodity derivative contracts.

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Cash Flows from Investing Activities

The Company dedicates and expects to continue to dedicate a substantial portion of its capital expenditure program toward the development, production and acquisition of oil and natural gas reserves. These capital expenditures are necessary to offset inherent declines in production and proven reserves, which is typical in the capital-intensive oil and natural gas industry.

Cash flows used in investing activities increased to $502.7 million in the six-month period ended June 30, 2011 from $416.2 million in the comparable 2010 period primarily due to increased capital expenditures as a result of increased oil drilling activity in the Mid-Continent and Permian Basin areas, offset somewhat by proceeds from asset sales.

Capital Expenditures. The Company’s capital expenditures, on an accrual basis, by segment for the six-month periods ended June 30, 2011 and 2010 are summarized below:

	Six Months Ended June 30,
	2011		2010
	(In thousands)
Capital Expenditures
Exploration and production	$	826,813	$	411,050
Drilling and oil field services		14,793		17,612
Midstream gas services		8,635		36,759
Other		24,011		12,124
Total	$	874,252	$	477,545

Cash Flows from Financing Activities

The Company’s financing activities provided $240.4 million in cash for the six-month period ended June 30, 2011 compared to $152.0 million in the comparable period in 2010. Cash provided by financing activities during the six months ended June 30, 2011 was primarily comprised of $880.7 million of net proceeds from the issuance of the 7.5% Senior Notes and $336.9 million of net proceeds from the issuance of units by the Mississippian Trust, offset by the purchase and redemption of $650.0 million aggregate principal amount of the 8.625% Senior Notes, the premium of $30.3 million paid in connection with the purchase and redemption of the 8.625% Senior Notes, $260.0 million of net repayments under the senior credit facility and $29.0 million of dividends paid on the 8.5%, 6.0% and 7.0% convertible perpetual preferred stock.

Indebtedness

Senior Credit Facility. The amount the Company may borrow under its senior credit facility is limited to a borrowing base, and is subject to periodic redeterminations. Effective March 15, 2011, the borrowing base was reduced to $790.0 million due to the issuance of the Company’s 7.5% Senior Notes. The borrowing base is determined based upon the discounted present value of future cash flows attributable to the Company’s proved reserves. Because the value of the Company’s proved reserves is a key factor in determining the amount of the borrowing base, changing commodity prices and the Company’s success in developing reserves may affect the borrowing base. Outstanding letters of credit affect the availability under the senior credit facility on a dollar-for-dollar basis.

On February 23, 2011, the Company’s senior credit facility was amended to, among other things, (a) exclude from the calculation of Consolidated Net Income the net income (or loss) of a Royalty Trust, except to the extent of cash distributions received by the Company, (b) establish that an investment in a Royalty Trust and dispositions to, and of interests in, Royalty Trusts are permitted, (c) clarify that a Royalty Trust is not a Subsidiary, (d) allow the Company to net against its calculation of Consolidated Funded Indebtedness cash

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balances exceeding $10.0 million in the event no loans are outstanding under the senior credit facility at that time, and (e) establish that, for any fiscal quarter ending prior to March 31, 2012, if the ratio of the Company’s secured indebtedness to EBITDA is less than 1.5:1.0 then compliance with the Company’s Consolidated Leverage Ratio covenant is not required. Terms capitalized in the preceding sentence have the meaning given to them in the senior credit facility, as amended.

On April 20, 2011, the senior credit facility was amended. The amendment permits the Company to pay cash dividends on its 7.0% convertible perpetual preferred stock and reaffirmed the borrowing base at $790.0 million.

As of June 30, 2011, the senior credit facility contained financial covenants, including maintaining agreed levels for the (i) ratio of total funded debt to EBITDA, which may not exceed 4.5:1.0 at each quarter end calculated using the last four completed fiscal quarters, unless, for any quarter ending prior to March 31, 2012, the ratio of the Company’s secured indebtedness to EBITDA is less than 1.5:1.0, calculated using the last four completed fiscal quarters (in each case through the second quarter of 2011, adjusted for annualized amounts of the post-acquisition results of operations of Arena), (ii) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at each quarter end (in the current ratio calculation (as defined in the senior credit facility), any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on the Company’s derivative contracts are disregarded) and (iii) ratio of the Company’s secured indebtedness to EBITDA, which may not exceed 2.0:1.0 at each quarter end calculated using the last four completed fiscal quarters (in each case through the second quarter of 2011, adjusted for annualized amounts of the post-acquisition results of operations of Arena). The Company remains in compliance with all financial covenants under the senior credit facility.

Senior Notes. On March 1, 2011 the Company announced a cash tender offer to purchase any and all of the outstanding $650.0 million aggregate principal amount of its 8.625% Senior Notes. As of March 31, 2011, the Company had purchased approximately 94.5%, or $614.2 million of these notes. On April 1, 2011, the Company redeemed the remaining outstanding $35.8 million aggregate principal amount of its 8.625% Senior Notes. Additionally in March 2011, the Company issued $900.0 million of its 7.5% Senior Notes. Net proceeds were used to fund the tender offer for the 8.625% Senior Notes and to repay amounts outstanding under the Company’s senior credit facility. See Note 11 to the Company’s condensed consolidated financial statements included in this Quarterly Report for further information.

Long-term obligations under the senior credit facility and other long-term debt consist of the following at June 30, 2011 (in thousands):

Senior credit facility	$	80,000
Other notes payable		16,527
Senior Floating Rate Notes due 2014		350,000
9.875% Senior Notes due 2016, net of $11,881 discount		353,619
8.0% Senior Notes due 2018		750,000
8.75% Senior Notes due 2020, net of $6,693 discount		443,307
7.5% Senior Notes due 2021		900,000
Total debt	$	2,893,453

The indentures governing the senior notes referred to above contain limitations on the incurrence of indebtedness, payment of dividends, investments, asset sales, certain asset purchases, transactions with related parties and consolidations or mergers.

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Maturities of Long-Term Debt. Aggregate maturities of long-term debt, excluding discounts, for the next five fiscal years are as follows (in thousands):

2011	$	499
2012		1,051
2013		1,120
2014		431,191
2015		1,266
Thereafter		2,476,900
Total debt	$	2,912,027

For more information about the senior credit facility, the senior notes and the Company’s other long-term debt obligations, see Note 11 to the condensed consolidated financial statements included in this Quarterly Report.

Outlook

On August 4, 2011, the Company increased its budget for capital expenditures, including expenditures related to its drilling obligation under the development agreement with the Mississippian Trust and excluding acquisitions to $1.8 billion. The majority of the Company’s capital expenditures are discretionary and could be curtailed if the Company’s cash flows decline from expected levels or if the Company is unable to obtain capital on attractive terms. The Company may increase or decrease planned capital expenditures depending on oil and natural gas prices, the availability of capital through asset sales and the issuance of additional equity or long-term debt.

The Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, each of which depend on numerous factors beyond the Company’s control such as economic conditions, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile and may be subject to significant fluctuations in the future. The Company’s derivative arrangements serve to mitigate a portion of the effect of this price volatility on its cash flows, and while derivative contracts are in place for the majority of expected oil production for 2011 through 2013, fixed price swap contracts are in place for only a portion of expected natural gas production in 2011 and 2012 and oil production for 2014 and 2015. No fixed price swap contracts are in place for the Company’s natural gas production beyond 2012 or oil production beyond 2015. The Company has natural gas collars in place for a portion of expected natural gas production through 2015. See Item 3 “Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding the Company’s derivative contracts.

The Company has incurred, and will have to continue to incur, capital expenditures to achieve production targets contained in certain gathering and treating arrangements. The Company is dependent on the availability of borrowings under its senior credit facility, along with cash flows from operating activities and proceeds from planned asset sales and other asset monetizations, to fund those capital expenditures. Based on anticipated oil and natural gas prices, availability under the Company’s senior credit facility, potential access to the capital markets and anticipated proceeds from the sales or other monetizations of assets, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for 2011. However, a substantial or extended decline in oil or natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced, which could adversely impact the Company’s ability to comply with the financial covenants under its senior credit facility, which in turn would limit further borrowings to fund capital expenditures. The Company has the ability to reduce its capital expenditures budget if cash flows are not available.

The Company may choose to refinance borrowings outstanding under its senior credit facility by issuing long-term debt or equity in the public or private markets, or both. In addition, the Company may from time to time seek to retire or purchase its outstanding securities through cash purchases and/or exchanges in open market

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purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions and other factors.

As of June 30, 2011, the Company’s cash and cash equivalents were $4.6 million and the Company had approximately $2.9 billion in total debt outstanding with $80.0 million outstanding under its senior credit facility. As of and for the three and six-month periods ended June 30, 2011, the Company was in compliance with all of the covenants under all of its senior notes and its senior credit facility. As of August 1, 2011, the Company’s cash and cash equivalents were approximately $2.2 million and the Company had $195.0 million outstanding under its senior credit facility with $24.5 million outstanding in letters of credit.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

General

The discussion in this section provides information about the financial instruments the Company uses to manage commodity prices and interest rate volatility. All contracts are settled in cash and do not require the actual delivery of a commodity at settlement.

Commodity Price Risk. The Company’s most significant market risk relates to the prices it receives for its oil and natural gas production. Due to the historical volatility of these commodities, the Company periodically has entered into, and expects in the future to enter into, derivative arrangements for the purpose of reducing the variability of oil and natural gas prices the Company receives for its production. From time to time, the Company enters into commodity pricing derivative contracts for a portion of its anticipated production volumes depending upon management’s view of opportunities under the then prevailing current market conditions. The Company’s senior credit facility limits its ability to enter into derivative transactions to 85% of expected production volumes from estimated proved reserves. The Company does not intend to enter into derivative contracts that would exceed its expected production volumes for the period covered by the derivative arrangement. Future credit facilities could require a minimum level of commodity price hedging.

The Company uses, and may continue to use, a variety of commodity-based derivative contracts, including fixed price swaps, collars and basis protection swaps. The Company’s oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period. The Company’s natural gas fixed price swap transactions are settled based upon New York Mercantile Exchange prices, and the Company’s natural gas basis protection swap transactions are settled based upon the index price of natural gas at the Waha hub, a West Texas gas marketing and delivery center, and the Houston Ship Channel. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts are settled in the production month. The Company’s natural gas collars are settled based upon the New York Mercantile Exchange prices on the penultimate commodity business day for the relevant contract. Natural gas collars only result in a cash settlement when the settlement price exceeds the fixed-price ceiling or falls below the fixed-price floor.

The Company has not designated any of its derivative contracts as hedges for accounting purposes. The Company records all derivative contracts on the balance sheet at fair value, which reflects changes in oil and natural gas prices. The Company establishes fair value of its derivative contracts by price quotations obtained from counterparties to the derivative contracts. Changes in fair values of the Company’s derivative contracts are recognized as unrealized gains and losses in current period earnings. As a result, the Company’s current period earnings may be significantly affected by changes in the fair value of its commodity derivative contracts. Changes in fair value are principally measured based on period-end prices compared to the contract price.

See Note 12 to the Company’s condensed consolidated financial statements included in this Quarterly Report for a summary of open oil and natural gas derivative contracts.

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The following table summarizes the cash settlements and valuation gains and losses on the Company’s commodity derivative contracts for the three and six-month periods ended June 30, 2011 and 2010 (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011		2010
Realized loss (gain)(1)	$	18,273		$	(117,955	)	$	26,881	$	(160,548	)
Unrealized (gain) loss		(188,261	)		(1,666	)		80,759		(21,025	)
(Gain) loss on commodity derivative contracts	$	(169,988	)	$	(119,621	)	$	107,640	$	(181,573	)

(1) Includes $25.8 million and $38.2 million of realized gains for the three and six-month periods ended June 30, 2011, respectively, related to settlements of commodity derivative contracts with contractual maturities after the quarterly period in which they were settled. Includes $62.4 million of realized gains for the three and six-month periods ended June 30, 2010, related to settlements of commodity derivative contracts with contractual maturities after June 30, 2010.

Credit Risk. The use of derivative contracts involves the risk that the counterparties will be unable to meet their obligations under the contracts. The Company’s derivative contracts are with multiple counterparties to minimize its exposure to any individual counterparty. As of June 30, 2011, the Company had 19 approved derivative counterparties, all of which are lenders under its senior credit facility. The Company currently has derivative contracts outstanding with 15 of these counterparties. The Company periodically reviews the credit quality of each counterparty to its derivative contracts and the level of overall financial exposure the Company has to each counterparty to limit its credit risk exposure with respect to these contracts. Additionally, the Company applies a credit default risk rating factor for its counterparties or gives effect to its credit risk, as applicable, in determining the fair value of its derivative contracts. The counterparties for all of the Company’s derivative transactions have an “investment grade” credit rating.

The Company’s ability to fund its capital expenditure budget is partially dependent upon the availability of funds under its senior credit facility. In order to mitigate the credit risk associated with individual financial institutions committed to participate in the senior credit facility, the Company’s bank group currently consists of 26 financial institutions with commitments ranging from 0.57% to 5.41%.

Interest Rate Risk. The Company is subject to interest rate risk on its long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes the Company to (i) changes in market interest rates reflected in the fair value of the debt and (ii) the risk that the Company may need to refinance maturing debt with new debt at a higher rate. Variable rate debt, where the interest rate fluctuates, exposes the Company to short-term changes in market interest rates as its interest obligations on these instruments are periodically redetermined based on prevailing market interest rates, primarily LIBOR and the federal funds rate.

In addition to commodity price derivative arrangements, the Company may enter into derivative transactions to fix the interest the Company pays on a portion of the amount outstanding on its variable rate debt. At June 30, 2011, the Company had a $350.0 million notional interest rate swap agreement. The interest rate swap agreement effectively serves to fix the rate on the Senior Floating Rate Notes at an annual rate of 6.69% for the period from April 1, 2011 to April 1, 2013. This swap has not been designated as a hedge.

The Company’s interest rate swap reduces its market risk on its Senior Floating Rate Notes. The Company uses sensitivity analyses to determine the impact that market risk exposures could have on the Company’s variable interest rate borrowings if not for its interest rate swap. Based on the $350.0 million outstanding balance of the Company’s Senior Floating Rate Notes at June 30, 2011, a one percent change in the applicable rates, with

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all other variables held constant, would have resulted in a change in the Company’s interest expense of approximately $0.9 million and $1.8 million for the three and six-month periods ended June 30, 2011, respectively.

The following table summarizes the cash settlements and valuation gains and losses on the Company’s interest rate swaps for the three and six-month periods ended June 30, 2011 and 2010 (in thousands):

	Three Months Ended June  30,				Six Months Ended June 30,
	2011		2010		2011			2010
Realized loss	$	2,442	$	2,076	$	4,485		$	4,163
Unrealized loss (gain)		356		4,401		(1,409	)		8,249
Loss on interest rate swaps	$	2,798	$	6,477	$	3,076		$	12,412

ITEM 4. Controls and Procedures

Under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, the Company performed an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15 as of the end of the period covered by this Quarterly Report. Based on that evaluation, the Company’s Chief Executive Officer and the Company’s Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2011 to provide reasonable assurance that the information required to be disclosed by the Company in its reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and such information is accumulated and communicated to management, as appropriate to allow timely decisions regarding required disclosure.

There was no change in the Company’s internal control over financial reporting during the quarter ended June 30, 2011 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II. Other Information

ITEM 1. Legal Proceedings

On February 14, 2011, Aspen Pipeline, II, L.P. (“Aspen”) filed a complaint in the District Court of Harris County, Texas, against Arena Resources, Inc. and SandRidge Energy, Inc. claiming damages based upon alleged representations by Arena in connection with the construction by Aspen of a natural gas pipeline in West Texas. The plaintiff seeks damages that include the construction cost of the pipeline, which it claims approach $90.0 million. The Company intends to defend this lawsuit vigorously and believes the plaintiff’s claims are without merit. This case is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this claim cannot be made at this time. The Company has not established any reserves relating to this claim.

On April 5, 2011, Wesley West Minerals, Ltd. and Longfellow Ranch Partners, LP (collectively, the “plaintiffs”), filed suit against SandRidge Energy, Inc. and SandRidge Exploration and Production, LLC (collectively, the “SandRidge Entities”), in the 83^rd District Court of Pecos County, Texas. The plaintiffs, who have leased mineral rights to the SandRidge Entities in Pecos County, allege that the SandRidge Entities have not properly paid royalties on all volumes of natural gas (including carbon dioxide, or “CO₂“) produced from the acreage leased from the plaintiffs. The plaintiffs also allege that the SandRidge Entities have inappropriately failed to pay royalties on CO₂ produced from plaintiffs’ acreage that results from the treatment of natural gas at the Century Plant. The plaintiffs seek unspecified actual damages, punitive damages and a declaration that the SandRidge Entities must pay royalties on CO₂ produced from plaintiffs’ acreage that results from treatment of natural gas at the Century Plant. The Company intends to defend this lawsuit vigorously. An estimate of reasonably possible losses, if any, associated with these claims cannot be made at this time. Accordingly, the Company has not established any reserves relating to these claims.

In addition, SandRidge is a defendant in lawsuits from time to time in the normal course of business. In management’s opinion, the Company is not currently involved in any legal proceedings that, individually or in the aggregate, could have a material effect on the Company’s financial condition, operations or cash flows.

ITEM 1A. Risk Factors

We describe one of our business risk factors below. This description includes a material change to the risk factors previously disclosed in Part I, Item 1A of the 2010 Form 10-K.

Production of oil, natural gas and natural gas liquids could be materially and adversely affected by severe or unseasonable weather.

Production of oil, natural gas and natural gas liquids could be materially and adversely affected by severe weather. Repercussions of severe weather conditions may include:

• evacuation of personnel and curtailment of operations;

• weather-related damage to drilling rigs or other facilities, resulting in suspension of operations;

• inability to deliver materials to worksites; and

• weather-related damage to pipelines and other transportation facilities.

67

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

As part of the Company’s restricted stock program, the Company makes required tax payments on behalf of employees when their stock awards vest and then withholds a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. The shares withheld are initially recorded as treasury shares, then immediately retired. During the quarter ended June 30, 2011, the following shares were withheld in satisfaction of tax withholding obligations arising from the vesting of restricted stock:

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares  Purchased as Part of Publicly Announced Plans or Programs		Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
April 1, 2011 — April 30, 2011		12,910	$	12.95		N/A		N/A
May 1, 2011 — May 31, 2011		461	$	11.73		N/A		N/A
June 1, 2011 — June 30, 2011		228	$	10.93		N/A		N/A

ITEM 6. Exhibits

See the Exhibit Index accompanying this Quarterly Report.

68

SIGNATURE

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

SandRidge Energy, Inc.
By:	/S/    JAMES D. BENNETT
	James D. Bennett Executive Vice President and Chief Financial Officer

Date: August 8, 2011

69

EXHIBIT INDEX

		Incorporated by Reference
Exhibit No.	Exhibit Description	Form		SEC File No.		Exhibit		Filing Date		Filed Herewith
3.1	Certificate of Incorporation of SandRidge Energy, Inc.		S-1		333-148956		3.1		01/30/2008
3.2	Certificate of Amendment to the Certificate of Incorporation of SandRidge Energy, Inc., dated July 16, 2010		10-Q		001-33784		3.2		08/09/2010
3.3	Amended and Restated Bylaws of SandRidge Energy, Inc.		8-K		001-33784		3.1		03/09/2009
10.1	Amendment No. 3 to the Amended and Restated Credit Agreement, dated April 20, 2011, among SandRidge Energy, Inc., each Lender party thereto, and Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer		10-Q		001-33784		10.4		05/09/2011
31.1	Section 302 Certification — Chief Executive Officer										*
31.2	Section 302 Certification — Chief Financial Officer										*
32.1	Section 906 Certifications of Chief Executive Officer and Chief Financial Officer										*
101.INS	XBRL Instance Document										*
101.SCH	XBRL Taxonomy Extension Schema Document										*
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document										*
101.DEF	XBRL Taxonomy Extension Definition Document										*
101.LAB	XBRL Taxonomy Extension Label Linkbase Document										*
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document										*

70

EX-31.1

Exhibit 31.1

Certification of the Company’s Chief Executive Officer Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)

I, Tom L. Ward, certify that:

1. I have reviewed this quarterly report on Form 10-Q of SandRidge Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Tom L. Ward

Tom L. Ward

Chief Executive Officer and Chairman of the Board

Date: August 8, 2011

EX-31.2

Exhibit 31.2

Certification of the Company’s Chief Financial Officer Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)

I, James D. Bennett, certify that:

1. I have reviewed this quarterly report on Form 10-Q of SandRidge Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ James D. Bennett

James D. Bennett

Executive Vice President and Chief Financial Officer

Date: August 8, 2011

EX-32.1

Exhibit 32.1

Certification of the Company’s Chief Executive Officer and Chief Financial Officer Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)

Pursuant to 18 U.S.C. § 1350, the undersigned officers of SandRidge Energy, Inc. (the “Company”), hereby certify that the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 (the “Report”), fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934 and that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Tom L. Ward

Tom L. Ward

Chief Executive Officer and Chairman of the Board

August 8, 2011

/s/ James D. Bennett

James D. Bennett

Executive Vice President and Chief Financial Officer

August 8, 2011

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Summarized Financial Information Concerning the Company's Segments (Detail) (USD $) In Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2011		Jun. 30, 2010		Jun. 30, 2011		Jun. 30, 2010		Dec. 31, 2010
Segment Reporting Information [Line Items]
Revenues	$ 465,375		$ 281,669		$ 859,358		$ 630,917
Inter-segment revenue	(100,601)		(99,230)		(181,737)		(237,483)
Total revenues	364,774		182,439		677,621		393,434
Operating income (loss)	279,716		119,452		71,887		208,623
Interest income (expense), net	(61,687)		(64,161)		(121,124)		(126,181)
Loss on extinguishment of debt	(2,051)				(38,232)
Other income (expense), net	138		(530)		1,335		706
Income (loss) before income taxes	216,116		54,761		(86,134)		83,148
Capital expenditures	454,092	[1]	248,964	[1]	874,252	[1]	477,545	[1]
Depreciation, depletion and amortization	89,461		66,139		176,440		130,720
Total assets	5,596,674				5,596,674				5,231,448
Exploration and Production
Segment Reporting Information [Line Items]
Revenues	317,768		150,571		585,004		320,755
Inter-segment revenue	(66)		(66)		(133)		(131)
Total revenues	317,702		150,505		584,871		320,624
Operating income (loss)	301,197		136,465		116,990		246,488
Interest income (expense), net	15		121		120		200
Other income (expense), net	3		13		1,679		781
Income (loss) before income taxes	301,215		136,599		118,789		247,469
Capital expenditures	423,725	[1]	218,973	[1]	826,813	[1]	411,050	[1]
Depreciation, depletion and amortization	76,734		55,041		151,206		108,034
Total assets	4,951,934				4,951,934				4,612,295
Drilling and Oil Field Services
Segment Reporting Information [Line Items]
Revenues	96,443		55,975		163,992		142,049
Inter-segment revenue	(67,906)		(52,063)		(114,421)		(132,377)
Total revenues	28,537		3,912		49,571		9,672
Operating income (loss)	4,098		(294)		3,990		(4,594)
Interest income (expense), net	4		(254)		(101)		(567)
Income (loss) before income taxes	4,102		(548)		3,889		(5,161)
Capital expenditures	8,030	[1]	8,195	[1]	14,793	[1]	17,612	[1]
Depreciation, depletion and amortization	7,998		6,833		15,727		14,163
Total assets	232,165				232,165				224,784
Midstream Gas Services
Segment Reporting Information [Line Items]
Revenues	48,278		66,379		104,256		148,916
Inter-segment revenue	(32,473)		(44,223)		(66,511)		(99,233)
Total revenues	15,805		22,156		37,745		49,683
Operating income (loss)	(2,570)		902		(5,098)		2,156
Interest income (expense), net	(141)		(161)		(313)		(299)
Other income (expense), net	216		56		(485)		56
Income (loss) before income taxes	(2,495)		797		(5,896)		1,913
Capital expenditures	4,462	[1]	16,337	[1]	8,635	[1]	36,759	[1]
Depreciation, depletion and amortization	1,291		927		2,388		1,803
Total assets	153,516				153,516				151,598
All Other
Segment Reporting Information [Line Items]
Revenues	2,886		8,744		6,106		19,197
Inter-segment revenue	(156)		(2,878)		(672)		(5,742)
Total revenues	2,730		5,866		5,434		13,455
Operating income (loss)	(23,009)		(17,621)		(43,995)		(35,427)
Interest income (expense), net	(61,565)		(63,867)		(120,830)		(125,515)
Loss on extinguishment of debt	(2,051)				(38,232)
Other income (expense), net	(81)		(599)		141		(131)
Income (loss) before income taxes	(86,706)		(82,087)		(202,916)		(161,073)
Capital expenditures	17,875	[1]	5,459	[1]	24,011	[1]	12,124	[1]
Depreciation, depletion and amortization	3,438		3,338		7,119		6,720
Total assets	$ 259,059				$ 259,059				$ 242,771

[1] On an accrual basis.

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Property, Plant and Equipment (Detail) (USD $) In Thousands	Jun. 30, 2011		Dec. 31, 2010
Oil and natural gas properties
Proved	$ 8,552,148		$ 8,159,924
Unproved	624,668		547,953
Total oil and natural gas properties	9,176,816		8,707,877
Less: accumulated depreciation, depletion and impairment	(4,625,330)		(4,483,736)
Net oil and natural gas properties capitalized costs	4,551,486		4,224,141
Land	14,192		14,418
Non oil and natural gas equipment	674,211	[1]	666,233	[1]
Buildings and structures	106,711		89,813
Total	795,114		770,464
Less: accumulated depreciation and amortization	(275,750)		(260,740)
Net capitalized costs	519,364		509,724
Total property, plant and equipment, net	$ 5,070,850		$ 4,733,865

[1] Includes capitalized interest of approximately $5.2 million and $4.7 million at June 30, 2011 and December 31, 2010, respectively.

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CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Thousands, except Share data	Jun. 30, 2011	Dec. 31, 2010
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, shares authorized	50,000,000	50,000,000
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	800,000,000	800,000,000
Common stock, issued	410,498,000	406,830,000
Common stock, outstanding	409,918,000	406,360,000
Preferred stock, shares outstanding	7,650,000	7,650,000
8.5% Convertible perpetual preferred stock
Preferred stock, shares issued	2,650,000	2,650,000
Preferred stock, shares outstanding	2,650,000	2,650,000
Preferred stock, aggregate liquidation preference	$ 265,000	$ 265,000
6.0% Convertible perpetual preferred stock
Preferred stock, shares issued	2,000,000	2,000,000
Preferred stock, shares outstanding	2,000,000	2,000,000
Preferred stock, aggregate liquidation preference	200,000	200,000
7.0% Convertible perpetual preferred stock
Preferred stock, shares issued	3,000,000	3,000,000
Preferred stock, shares outstanding	3,000,000	3,000,000
Preferred stock, aggregate liquidation preference	$ 300,000	$ 300,000

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Thousands, except Per Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Revenues
Oil and natural gas	$ 312,111	$ 149,995	$ 579,053	$ 319,580
Drilling and services	28,537	3,901	49,571	9,661
Midstream and marketing	16,313	22,598	38,570	50,587
Other	7,813	5,945	10,427	13,606
Total revenues	364,774	182,439	677,621	393,434
Expenses
Production	81,834	56,009	155,791	106,281
Production taxes	12,666	5,404	23,242	10,242
Drilling and services	18,058	1,024	33,099	8,233
Midstream and marketing	15,873	19,779	38,156	45,285
Depreciation and depletion - oil and natural gas	76,186	54,319	150,072	106,597
Depreciation and amortization - other	13,275	11,820	26,368	24,123
General and administrative	37,678	33,865	72,091	65,539
(Gain) loss on derivative contracts	(169,988)	(119,621)	107,640	(181,573)
(Gain) loss on sale of assets	(524)	388	(725)	84
Total expenses	85,058	62,987	605,734	184,811
Operating income (loss)	279,716	119,452	71,887	208,623
Other income (expense)
Interest income	38	98	43	167
Interest expense	(61,725)	(64,259)	(121,167)	(126,348)
Loss on extinguishment of debt	(2,051)		(38,232)
Other income (expense), net	138	(530)	1,335	706
Total other expense	(63,600)	(64,691)	(158,021)	(125,475)
Income (loss) before income taxes	216,116	54,761	(86,134)	83,148
Income tax (benefit) expense	(7,054)	150	(6,967)	162
Net income (loss)	223,170	54,611	(79,167)	82,986
Less: net income attributable to noncontrolling interest	13,154	1,096	13,161	2,234
Net income (loss) attributable to SandRidge Energy, Inc.	210,016	53,515	(92,328)	80,752
Preferred stock dividends	13,881	8,631	27,821	17,263
Income available (loss applicable) to SandRidge Energy, Inc. common stockholders	$ 196,135	$ 44,884	$ (120,149)	$ 63,489
Earnings (loss) per share
Basic	$ 0.49	$ 0.22	$ (0.30)	$ 0.31
Diluted	$ 0.42	$ 0.21	$ (0.30)	$ 0.31
Weighted average number of common shares outstanding
Basic	398,435	203,839	398,343	203,831
Diluted	495,982	259,566	398,343	226,406

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Provisions (Benefits) for Income Taxes (Detail) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Current
Federal	$ (137)		$ (116)
State	69	150	135	162
Current Income Tax Expense (Benefit)	(68)	150	19	162
Deferred
Federal	(6,385)		(6,385)
State	(601)		(601)
Deferred Income Tax Expense (Benefit)	(6,986)		(6,986)
Total (benefit) provision	(7,054)	150	(6,967)	162
Less: income tax provision attributable to noncontrolling interest		89	2	89
Total (benefit) provision attributable to SandRidge Energy, Inc.	$ (7,054)	$ 61	$ (6,969)	$ 73

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Goodwill - Additional Information (Detail) (USD $)	3 Months Ended
	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010
Goodwill [Line Items]
Goodwill	$ 235,396,000		$ 234,356,000
Goodwill, purchase price adjustment	$ 200,000	$ 800,000

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Condensed Consolidating Statements of Operations of SandRidge Energy, Inc. and Wholly Owned Subsidiary Guarantors and Non-Guarantors (Detail) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Schedule of Condensed Consolidating Statement of Operations [Line Items]
Total revenues	$ 364,774	$ 182,439	$ 677,621	$ 393,434
Expenses
Direct operating expenses	127,907	82,604	249,563	170,125
General and administrative	37,678	33,865	72,091	65,539
Depreciation, depletion, amortization and impairment	89,461	66,139	176,440	130,720
(Gain) loss on derivative contracts	(169,988)	(119,621)	107,640	(181,573)
Total expenses	85,058	62,987	605,734	184,811
Operating income (loss)	279,716	119,452	71,887	208,623
Interest expense, net	(61,687)	(64,161)	(121,124)	(126,181)
Loss on extinguishment of debt	(2,051)		(38,232)
Other expense (income), net	138	(530)	1,335	706
Income (loss) before income taxes	216,116	54,761	(86,134)	83,148
Income tax (benefit) expense	(7,054)	150	(6,967)	162
Net income (loss)	223,170	54,611	(79,167)	82,986
Less: net income attributable to noncontrolling interest	13,154	1,096	13,161	2,234
Net income (loss) attributable to SandRidge Energy, Inc.	210,016	53,515	(92,328)	80,752
Parent Company
Expenses
General and administrative	104	86	189	163
Total expenses	104	86	189	163
Operating income (loss)	(104)	(86)	(189)	(163)
Equity earnings from subsidiaries	266,425	117,094	59,437	205,795
Interest expense, net	(61,308)	(63,594)	(120,315)	(124,970)
Loss on extinguishment of debt	(2,051)		(38,232)
Other expense (income), net		73		74
Income (loss) before income taxes	202,962	53,487	(99,299)	80,736
Income tax (benefit) expense	(7,054)	(28)	(6,971)	(16)
Net income (loss)	210,016	53,515	(92,328)	80,752
Net income (loss) attributable to SandRidge Energy, Inc.	210,016	53,515	(92,328)	80,752
Guarantor Subsidiaries
Schedule of Condensed Consolidating Statement of Operations [Line Items]
Total revenues	341,481	174,404	650,777	373,688
Expenses
Direct operating expenses	122,389	80,214	241,617	162,856
General and administrative	36,608	32,861	70,342	63,830
Depreciation, depletion, amortization and impairment	83,413	64,444	168,652	127,369
(Gain) loss on derivative contracts	(160,387)	(119,621)	117,241	(181,573)
Total expenses	82,023	57,898	597,852	172,482
Operating income (loss)	259,458	116,506	52,925	201,206
Equity earnings from subsidiaries	6,950	1,544	5,712	4,679
Interest expense, net	(121)	(295)	(293)	(666)
Other expense (income), net	138	(661)	1,093	576
Income (loss) before income taxes	266,425	117,094	59,437	205,795
Net income (loss)	266,425	117,094	59,437	205,795
Net income (loss) attributable to SandRidge Energy, Inc.	266,425	117,094	59,437	205,795
Non-Guarantors
Schedule of Condensed Consolidating Statement of Operations [Line Items]
Total revenues	56,289	27,357	70,770	90,633
Expenses
Direct operating expenses	38,260	21,506	51,472	77,744
General and administrative	1,220	1,124	1,960	1,958
Depreciation, depletion, amortization and impairment	6,048	1,695	7,788	3,351
(Gain) loss on derivative contracts	(9,601)		(9,601)
Total expenses	35,927	24,325	51,619	83,053
Operating income (loss)	20,362	3,032	19,151	7,580
Interest expense, net	(258)	(272)	(516)	(545)
Other expense (income), net		58	242	56
Income (loss) before income taxes	20,104	2,818	18,877	7,091
Income tax (benefit) expense		178	4	178
Net income (loss)	20,104	2,640	18,873	6,913
Less: net income attributable to noncontrolling interest	13,154	1,096	13,161	2,234
Net income (loss) attributable to SandRidge Energy, Inc.	6,950	1,544	5,712	4,679
Eliminations
Schedule of Condensed Consolidating Statement of Operations [Line Items]
Total revenues	(32,996)	(19,322)	(43,926)	(70,887)
Expenses
Direct operating expenses	(32,742)	(19,116)	(43,526)	(70,475)
General and administrative	(254)	(206)	(400)	(412)
Total expenses	(32,996)	(19,322)	(43,926)	(70,887)
Equity earnings from subsidiaries	(273,375)	(118,638)	(65,149)	(210,474)
Income (loss) before income taxes	(273,375)	(118,638)	(65,149)	(210,474)
Net income (loss)	(273,375)	(118,638)	(65,149)	(210,474)
Net income (loss) attributable to SandRidge Energy, Inc.	$ (273,375)	$ (118,638)	$ (65,149)	$ (210,474)

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Related Party Transactions

6 Months Ended

Jun. 30, 2011

Related Party Transactions

17. Related Party Transactions

The Company enters into transactions in the ordinary course of business with certain related parties. These transactions primarily consist of purchases related to drilling and completion activities, gas treating services and drilling equipment and sales of oil field services, equipment and natural gas. Following is a summary of significant transactions with such related parties (in thousands):

	Three Months Ended June  30,				Six Months Ended June 30,
	2011		2010		2011		2010
Sales to and reimbursements from related parties	$	6,947	$	4,166	$	11,735	$	6,823
					June 30, 2011		December 31, 2010
Accounts receivable due from related parties					$	2,153	$	1,702

Oklahoma City Thunder Agreements. The Company’s Chairman and Chief Executive Officer owns a minority interest in a limited liability company that owns and operates the Oklahoma City Thunder, a National Basketball Association team playing in Oklahoma City, where the Company is headquartered. The Company is party to a sponsorship agreement, through the 2013 season, whereby it pays approximately $3.3 million per year for advertising and promotional activities related to the Oklahoma City Thunder. Additionally, the Company entered into an agreement to license a suite at the arena where the Oklahoma City Thunder plays its home games. Under this four-year agreement, the Company pays an annual license fee of $0.2 million through 2013. Amounts related to these agreements are not included in the tables above. At June 30, 2011 the Company had no amounts due under these agreements. At December 31, 2010, the amount due under these agreements was $0.8 million.

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Related Party Transactions - Additional Information (Detail) (USD $) In Millions	12 Months Ended
	Dec. 31, 2010	Jun. 30, 2011
Related Party Transaction [Line Items]
Annual sponsorship for OKC Thunder	$ 3.3
Annual license fee	0.2
Accounts Payable due	$ 0.8	$ 0

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Document and Entity Information	6 Months Ended
	Jun. 30, 2011	Jul. 29, 2011
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q2
Trading Symbol	SD
Entity Registrant Name	SANDRIDGE ENERGY INC
Entity Central Index Key	0001349436
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		412,428,752

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Estimated Fair Value, Based on Quoted Market Prices, and the Carrying Value of Senior Notes (Detail) (USD $) In Thousands	Jun. 30, 2011		Dec. 31, 2010
Senior Floating Rate Notes due 2014
Fair Value	$ 349,127		$ 334,751
Carrying Value	350,000		350,000
8.625% Senior Notes due 2015
Fair Value			663,181
Carrying Value			650,000
9.875% Senior Notes due 2016
Fair Value	406,146	[1]	394,527	[1]
Carrying Value	353,619	[1]	352,707	[1]
8.0% Senior Notes due 2018
Fair Value	763,636		762,849
Carrying Value	750,000		750,000
8.75% Senior Notes due 2020
Fair Value	479,767	[2]	472,968	[2]
Carrying Value	443,307	[2]	443,057	[2]
Senior Notes 7.5 Percent Due 2021
Fair Value	909,203
Carrying Value	$ 900,000

[1] Carrying value is net of $11,881 and $12,793 discount at June 30, 2011 and December 31, 2010, respectively.

[2] Carrying value is net of $6,693 and $6,943 discount at June 30, 2011 and December 31, 2010, respectively.

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Condensed Consolidating Financial Information

6 Months Ended

Jun. 30, 2011

Condensed Consolidating Financial Information

20. Condensed Consolidating Financial Information

The Company provides condensed consolidating financial information for its subsidiaries that are guarantors of its registered debt. The subsidiary guarantors are wholly owned and have jointly and severally guaranteed unconditionally on an unsecured basis the Company’s Senior Floating Rate Notes and 8.75% Senior Notes as of June 30, 2011. Prior to their purchase and redemption, the 8.625% Senior Notes were also jointly and severally guaranteed unconditionally on an unsecured basis by the wholly owned subsidiary guarantors. The subsidiary guarantees (i) rank equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) rank senior to all of the existing and future subordinated debt of the subsidiary guarantors; (iii) are effectively subordinated in right of payment to any existing or future secured obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; and (iv) are structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors who are not themselves guarantors. The Company’s subsidiary guarantors guarantee payments of principal and interest under the Company’s registered notes. The Company has not presented separate financial and narrative information for each of the subsidiary guarantors because it believes that such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the guarantees.

The following condensed consolidating financial information represents the financial information of SandRidge Energy, Inc., its wholly owned subsidiary guarantors and its non-guarantor subsidiaries, prepared on the equity basis of accounting. The non-guarantor subsidiaries and three variable interest entities are included in the non-guarantor column in the tables below. The financial information may not necessarily be indicative of the financial position, results of operations or cash flows had the subsidiary guarantors operated as independent entities.

Condensed Consolidating Balance Sheets

	June 30, 2011
	Parent		Guarantors		Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	806	$	217	$	3,592	$	—		$	4,615
Accounts and notes receivable, net		1,107,468		155,236		474,528		(1,574,256	)		162,976
Derivative contracts		—		2,513		3,261		(3,261	)		2,513
Other current assets		—		12,686		7,782		—			20,468
Total current assets		1,108,274		170,652		489,163		(1,577,517	)		190,572
Property, plant and equipment, net		—		4,670,983		399,867		—			5,070,850
Investment in subsidiaries		3,289,504		50,925		—		(3,340,429	)		—
Goodwill		—		235,396		—		—			235,396
Other assets		56,662		43,194		1,562		(1,562	)		99,856
Total assets	$	4,454,440	$	5,171,150	$	890,592	$	(4,919,508	)	$	5,596,674
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	123,862	$	1,411,142	$	463,223	$	(1,574,256	)	$	423,971
Derivative contracts		9,552		143,083		—		(3,261	)		149,374
Asset retirement obligation		—		25,360		—		—			25,360
Other current liabilities		—		41,232		1,019		—			42,251
Total current liabilities		133,414		1,620,817		464,242		(1,577,517	)		640,956
Long-term debt		2,876,925		—		15,509		—			2,892,434
Derivative contracts		5,734		157,885		—		(1,562	)		162,057
Asset retirement obligation		—		93,606		174		—			93,780
Other liabilities		1,523		9,239		—		—			10,762
Total liabilities		3,017,596		1,881,547		479,925		(1,579,079	)		3,799,989
Equity		1,436,844		3,289,603		410,667		(3,340,429	)		1,796,685
Total liabilities and equity	$	4,454,440	$	5,171,150	$	890,592	$	(4,919,508	)	$	5,596,674

	December 31, 2010
	Parent		Guarantors		Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	1,441	$	564	$	3,858	$	—		$	5,863
Accounts and notes receivable, net		1,224,500		141,530		408,015		(1,627,927	)		146,118
Derivative contracts		—		5,028		—		—			5,028
Other current assets		—		13,890		4,691		—			18,581
Total current assets		1,225,941		161,012		416,564		(1,627,927	)		175,590
Property, plant and equipment, net		—		4,635,747		98,118		—			4,733,865
Investment in subsidiaries		3,230,067		69,995		—		(3,300,062	)		—
Goodwill		—		234,356		—		—			234,356
Other assets		50,637		37,000		—		—			87,637
Total assets	$	4,506,645	$	5,138,110	$	514,682	$	(4,927,989	)	$	5,231,448
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	66,539	$	1,510,827	$	427,483	$	(1,627,927	)	$	376,922
Derivative contracts		9,007		94,402		—		—			103,409
Asset retirement obligation		—		25,360		—		—			25,360
Other current liabilities		—		37,776		991		—			38,767
Total current liabilities		75,546		1,668,365		428,474		(1,627,927	)		544,458
Long-term debt		2,885,764		—		16,029		—			2,901,793
Derivative contracts		7,687		116,486		—		—			124,173
Asset retirement obligation		—		94,350		167		—			94,517
Other liabilities		1,454		17,570		—		—			19,024
Total liabilities		2,970,451		1,896,771		444,670		(1,627,927	)		3,683,965
Equity		1,536,194		3,241,339		70,012		(3,300,062	)		1,547,483
Total liabilities and equity	$	4,506,645	$	5,138,110	$	514,682	$	(4,927,989	)	$	5,231,448

Condensed Consolidating Statements of Operations

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Three Months Ended June 30, 2011
Total revenues	$	—		$	341,481		$	56,289		$	(32,996	)	$	364,774
Expenses
Direct operating expenses		—			122,389			38,260			(32,742	)		127,907
General and administrative		104			36,608			1,220			(254	)		37,678
Depreciation, depletion, amortization and impairment		—			83,413			6,048			—			89,461
Gain on derivative contracts		—			(160,387	)		(9,601	)		—			(169,988	)
Total expenses		104			82,023			35,927			(32,996	)		85,058
(Loss) income from operations		(104	)		259,458			20,362			—			279,716
Equity earnings from subsidiaries		266,425			6,950			—			(273,375	)		—
Interest expense, net		(61,308	)		(121	)		(258	)		—			(61,687	)
Loss on extinguishment of debt		(2,051	)		—			—			—			(2,051	)
Other income, net		—			138			—			—			138
Income before income taxes		202,962			266,425			20,104			(273,375	)		216,116
Income tax benefit		(7,054	)		—			—			—			(7,054	)
Net income		210,016			266,425			20,104			(273,375	)		223,170
Less: net income attributable to noncontrolling interest		—			—			13,154			—			13,154
Net income attributable to SandRidge Energy, Inc.	$	210,016		$	266,425		$	6,950		$	(273,375	)	$	210,016
Three Months Ended June 30, 2010
Total revenues	$	—		$	174,404		$	27,357		$	(19,322	)	$	182,439
Expenses
Direct operating expenses		—			80,214			21,506			(19,116	)		82,604
General and administrative		86			32,861			1,124			(206	)		33,865
Depreciation, depletion, amortization and impairment		—			64,444			1,695			—			66,139
Gain on derivative contracts		—			(119,621	)		—			—			(119,621	)
Total expenses		86			57,898			24,325			(19,322	)		62,987
(Loss) income from operations		(86	)		116,506			3,032			—			119,452
Equity earnings from subsidiaries		117,094			1,544			—			(118,638	)		—
Interest expense, net		(63,594	)		(295	)		(272	)		—			(64,161	)
Other expense (income), net		73			(661	)		58			—			(530	)
Income before income taxes		53,487			117,094			2,818			(118,638	)		54,761
Income tax (benefit) expense		(28	)		—			178			—			150
Net income		53,515			117,094			2,640			(118,638	)		54,611
Less: net income attributable to noncontrolling interest		—			—			1,096			—			1,096
Net income attributable to SandRidge Energy, Inc.	$	53,515		$	117,094		$	1,544		$	(118,638	)	$	53,515

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Six Months Ended June 30, 2011
Total revenues	$	—		$	650,777		$	70,770		$	(43,926	)	$	677,621
Expenses
Direct operating expenses		—			241,617			51,472			(43,526	)		249,563
General and administrative		189			70,342			1,960			(400	)		72,091
Depreciation, depletion, amortization and impairment		—			168,652			7,788			—			176,440
(Loss) gain on derivative contracts		—			117,241			(9,601	)		—			107,640
Total expenses		189			597,852			51,619			(43,926	)		605,734
(Loss) income from operations		(189	)		52,925			19,151			—			71,887
Equity earnings from subsidiaries		59,437			5,712			—			(65,149	)		—
Interest expense, net		(120,315	)		(293	)		(516	)		—			(121,124	)
Loss on extinguishment of debt		(38,232	)		—			—			—			(38,232	)
Other income, net		—			1,093			242			—			1,335
(Loss) income before income taxes		(99,299	)		59,437			18,877			(65,149	)		(86,134	)
Income tax (benefit) expense		(6,971	)		—			4			—			(6,967	)
Net (loss) income		(92,328	)		59,437			18,873			(65,149	)		(79,167	)
Less: net income attributable to noncontrolling interest		—			—			13,161			—			13,161
Net (loss) income attributable to SandRidge Energy, Inc.	$	(92,328	)	$	59,437		$	5,712		$	(65,149	)	$	(92,328	)
Six Months Ended June 30, 2010
Total revenues	$	—		$	373,688		$	90,633		$	(70,887	)	$	393,434
Expenses
Direct operating expenses		—			162,856			77,744			(70,475	)		170,125
General and administrative		163			63,830			1,958			(412	)		65,539
Depreciation, depletion, amortization and impairment		—			127,369			3,351			—			130,720
Gain on derivative contracts		—			(181,573	)		—			—			(181,573	)
Total expenses		163			172,482			83,053			(70,887	)		184,811
(Loss) income from operations		(163	)		201,206			7,580			—			208,623
Equity earnings from subsidiaries		205,795			4,679			—			(210,474	)		—
Interest expense, net		(124,970	)		(666	)		(545	)		—			(126,181	)
Other income, net		74			576			56			—			706
Income before income taxes		80,736			205,795			7,091			(210,474	)		83,148
Income tax (benefit) expense		(16	)		—			178			—			162
Net income		80,752			205,795			6,913			(210,474	)		82,986
Less: net income attributable to noncontrolling interest		—			—			2,234			—			2,234
Net income attributable to SandRidge Energy, Inc.	$	80,752		$	205,795		$	4,679		$	(210,474	)	$	80,752

Condensed Consolidating Statements of Cash Flows

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Six Months Ended June 30, 2011
Net cash provided by (used in) operating activities	$	94,579		$	162,726		$	3,699		$	—		$	261,004
Net cash used in investing activities		—			(163,785	)		(340,366	)		1,501			(502,650	)
Net cash (used in) provided by financing activities		(95,214	)		712			336,401			(1,501	)		240,398
Net (decrease) increase in cash and cash equivalents		(635	)		(347	)		(266	)		—			(1,248	)
Cash and cash equivalents at beginning of year		1,441			564			3,858			—			5,863
Cash and cash equivalents at end of period	$	806		$	217		$	3,592		$	—		$	4,615
Six Months Ended June 30, 2010
Net cash (used in) provided by operating activities	$	(160,436	)	$	417,020		$	1,875		$	—		$	258,459
Net cash used in investing activities		—			(413,221	)		(4,484	)		1,506			(416,199	)
Net cash provided by (used in) financing activities		160,266			(6,492	)		(306	)		(1,506	)		151,962
Net decrease in cash and cash equivalents		(170	)		(2,693	)		(2,915	)		—			(5,778	)
Cash and cash equivalents at beginning of year		339			2,841			4,681			—			7,861
Cash and cash equivalents at end of period	$	169		$	148		$	1,766		$	—		$	2,083

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Reconciliation of Financial Assets and Liabilities Measured at Fair Value on a Recurring Basis using Significant Unobservable Inputs (Level 3) (Detail) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance of Level 3, Beginning Balance	$ (493,470)	$ 53,365	$ (222,554)	$ 37,854
Total realized and unrealized (losses) gains	167,190	113,144	(110,716)	169,161
Purchases	(3,353)		(7,014)
Settlements	20,715	(115,879)	31,366	(156,385)
Balance of Level 3, Ending Balance	(308,918)	50,630	(308,918)	50,630
Commodity derivative contracts
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance of Level 3, Beginning Balance	(478,541)	65,512	(205,860)	46,153
Total realized and unrealized (losses) gains	169,988	119,621	(107,640)	181,573
Purchases	(3,353)		(7,014)
Settlements	18,273	(117,955)	26,881	(160,548)
Balance of Level 3, Ending Balance	(293,633)	67,178	(293,633)	67,178
Interest rate swaps
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance of Level 3, Beginning Balance	(14,929)	(12,147)	(16,694)	(8,299)
Total realized and unrealized (losses) gains	(2,798)	(6,477)	(3,076)	(12,412)
Settlements	2,442	2,076	4,485	4,163
Balance of Level 3, Ending Balance	$ (15,285)	$ (16,548)	$ (15,285)	$ (16,548)

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Equity - Additional Information (Detail) (USD $)	3 Months Ended		6 Months Ended			3 Months Ended		6 Months Ended		12 Months Ended		3 Months Ended		6 Months Ended		12 Months Ended		3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010	Jun. 30, 2011 8.5% Convertible perpetual preferred stock	Jun. 30, 2010 8.5% Convertible perpetual preferred stock	Jun. 30, 2011 8.5% Convertible perpetual preferred stock	Jun. 30, 2010 8.5% Convertible perpetual preferred stock	Dec. 31, 2009 8.5% Convertible perpetual preferred stock	Dec. 31, 2010 8.5% Convertible perpetual preferred stock	Jun. 30, 2011 6.0% Convertible perpetual preferred stock	Jun. 30, 2010 6.0% Convertible perpetual preferred stock	Jun. 30, 2011 6.0% Convertible perpetual preferred stock	Jun. 30, 2010 6.0% Convertible perpetual preferred stock	Dec. 31, 2009 6.0% Convertible perpetual preferred stock	Dec. 31, 2010 6.0% Convertible perpetual preferred stock	Jun. 30, 2011 7.0% Convertible perpetual preferred stock	Jun. 30, 2011 7.0% Convertible perpetual preferred stock	Dec. 31, 2010 7.0% Convertible perpetual preferred stock	Feb. 15, 2011 7.0% Convertible perpetual preferred stock
Stockholders Equity Note [Line Items]
Preferred stock, shares authorized	50,000,000		50,000,000		50,000,000
Preferred stock, par value	$ 0.001		$ 0.001		$ 0.001
Shares designated as convertible perpetual preferred stock	7,650,000		7,650,000		7,650,000	2,650,000		2,650,000			2,650,000	2,000,000		2,000,000			2,000,000	3,000,000	3,000,000	3,000,000
Preferred stock, liquidation preference per share										$ 100.00						$ 100.00				$ 100.00
Preferred stock, number of common stocks shares issuable upon the conversion										12.4805						9.2115					12.8791
Preferred stock, conversion price										$ 8.01						$ 10.86					$ 7.76
Preferred stock, dividend not paid						$ 5,600,000	$ 5,600,000	$ 8,500,000	$ 8,500,000			$ 3,000,000	$ 3,000,000	$ 5,500,000	$ 6,000,000			$ 2,600,000	$ 2,600,000
Preferred stock, dividend paid			28,980,000	11,263,000				2,800,000	2,800,000					500,000				2,700,000	8,000,000
Preferred stock dividends	13,881,000	8,631,000	27,821,000	17,263,000		5,600,000	5,600,000	11,300,000	11,300,000			3,000,000		6,000,000				5,300,000	10,600,000
Preferred stock, annual dividend per share										$ 8.50									$ 7.00
Preferred stock, conversion term										The 8.5% convertible perpetual preferred stock is not redeemable by the Company at any time. After February 20, 2014, the Company may cause all outstanding shares of the convertible perpetual preferred stock to automatically convert into common stock at the then-prevailing conversion rate if certain conditions are met.						The 6.0% convertible perpetual preferred stock is not redeemable by the Company at any time. Each share is initially convertible into approximately 9.2115 shares of the Company’s common stock, at the holder’s option based on an initial conversion price of $10.86 and subject to customary adjustments in certain circumstances. Five years after their issuance, all outstanding shares of the convertible preferred stock will be converted automatically into shares of the Company’s common stock at the then-prevailing conversion price as long as all dividends accrued at that time have been paid.				The 7.0% convertible perpetual preferred stock is not redeemable by the Company at any time. After November 20, 2015, the Company may cause all outstanding shares of the 7.0% convertible perpetual preferred stock to convert automatically into common stock at the then-prevailing conversion rate if certain conditions are met.
Preferred stock, annual dividend per share																$ 6.00
Purchase of treasury stock, shares			617,000	274,000
Purchase of treasury stock			4,984,000	2,900,000
Restricted common stock under incentive compensation plans, vesting period			4
Stock-based compensation	8,900,000	7,300,000	17,100,000	14,200,000
Stock-based compensation, capitalized related to restricted common stock	$ 1,900,000	$ 1,300,000	$ 3,700,000	$ 2,600,000

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Goodwill

6 Months Ended

Jun. 30, 2011

Goodwill

6. Goodwill

At June 30, 2011, the Company had $235.4 million of goodwill, including the effects of the $0.8 million and $0.2 million purchase price adjustments recorded in the first and second quarters of 2011, respectively, as a result of the excess consideration over the fair value of net assets acquired in the Arena Acquisition. Goodwill recorded in the Arena Acquisition is primarily attributable to operational and cost synergies expected to be realized from the acquisition by using the Company’s current presence in the Permian Basin, its Fort Stockton, Texas service base and its existing rig ownership to efficiently increase its drilling and oil production from Arena assets acquired in the Central Basin Platform, as these assets have a proven production history. See Note 3 for additional discussion of the Arena Acquisition. The Company assigned all of the goodwill related to the Arena Acquisition to its exploration and production segment, which will be the reporting unit for impairment testing purposes. The Company will test goodwill for impairment annually on July 1, beginning in 2011. The Company monitors the existence of potential impairment indicators throughout the year. As of June 30, 2011, no such indicators were noted. Goodwill recognized is not deductible for tax purposes.

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Acquisitions and Divestitures (Tables)

6 Months Ended

Jun. 30, 2011

Valuation of Assets Acquired and Liabilities Assumed in Connection with Acquisition

The following table summarizes the final valuation of assets acquired and liabilities assumed in connection with the Arena Acquisition (in thousands):

Current assets	$	83,563
Oil and natural gas properties(1)		1,587,630
Other property, plant and equipment		5,963
Deferred tax assets		48,997
Other long-term assets		16,181
Goodwill(2)		235,396
Total assets acquired		1,977,730
Current liabilities		38,964
Long-term deferred tax liability(2)		503,483
Other long-term liabilities		8,851
Total liabilities assumed		551,298
Net assets acquired	$	1,426,432

(1) Weighted average commodity prices utilized in the preliminary determination of the fair value of oil and natural gas properties were $105.58 per barrel of oil and $8.56 per Mcf of natural gas, after adjustment for transportation fees and regional price differentials. The prices utilized were based upon forward commodity strip prices, as of July 16, 2010, for the first four years and escalated for inflation at a rate of 2.5% annually beginning with the fifth year through the end of production, which was more than 50 years. Approximately 91.0% of the fair value allocated to oil and natural gas properties is attributed to oil reserves.

(2) The Company received carryover tax basis in Arena’s assets and liabilities because the merger was not a taxable transaction under the Internal Revenue Code (“IRC”). Based upon the final purchase price allocation, a step-up in basis related to the property acquired from Arena resulted in a net deferred tax liability of approximately $454.5 million, which in turn contributed to an excess of the consideration transferred to acquire Arena over the estimated fair value on the acquisition date of the net assets acquired, or goodwill. See Note 6 for further discussion of goodwill and Note 13 for further discussion of the net deferred tax liability.

Pro forma Results of Operations as though the Acquisition had been Completed as of the Beginning of the Period

Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors.

	Three Months Ended June 30, 2010				Six Months Ended June 30, 2010
	Actual		Pro Forma		Actual		Pro Forma
	(in thousands, except per share data)
Revenues	$	182,439	$	236,751	$	393,434	$	499,544
Income available to SandRidge Energy, Inc. common stockholders(1)	$	44,884	$	503,597	$	63,489	$	536,985
Earnings per common share
Basic	$	0.22	$	1.28	$	0.31	$	1.36
Diluted	$	0.21	$	1.14	$	0.31	$	1.23

(1) Pro forma columns reflect a $454.5 million reduction in tax expense related to the release of a portion of the Company’s valuation allowance on existing deferred tax assets.

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Final Valuation of Assets Acquired and Liabilities Assumed in Connection with Arena Acquisition (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified		1 Months Ended
	Jun. 30, 2011	Jul. 16, 2010 Oil	Jul. 16, 2010 Natural Gas	Jul. 16, 2010 Oil and Natural Gas
Business Acquisition, Contingent Consideration [Line Items]
Weighted average commodity prices utilized in the preliminary determination of the fair value of oil and natural gas properties		105.58	8.56
Weighted average commodity prices, basis of price determination				The prices utilized were based upon forward commodity strip prices, as of July 16, 2010, for the first four years and escalated for inflation at a rate of 2.5% annually beginning with the fifth year through the end of production, which was more than 50 years. Approximately 91.0% of the fair value allocated to oil and natural gas properties is attributed to oil reserves.
Purchase price allocation, net deferred tax liability	$ 454.5

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Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2011

Significant Transactions with Related Parties

Following is a summary of significant transactions with such related parties (in thousands):

	Three Months Ended June  30,				Six Months Ended June 30,
	2011		2010		2011		2010
Sales to and reimbursements from related parties	$	6,947	$	4,166	$	11,735	$	6,823
					June 30, 2011		December 31, 2010
Accounts receivable due from related parties					$	2,153	$	1,702

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Business Segment Information

6 Months Ended

Jun. 30, 2011

Business Segment Information

19. Business Segment Information

The Company has three business segments: exploration and production, drilling and oil field services and midstream gas services. These segments represent the Company’s three main business units, each offering different products and services. The exploration and production segment is engaged in the acquisition, development and production of oil and natural gas properties. The drilling and oil field services segment is engaged in the contract drilling of oil and natural gas wells. The midstream gas services segment is engaged in the purchasing, gathering, treating and selling of natural gas. The All Other column in the tables below includes items not related to the Company’s reportable segments, including the Company’s CO₂ gathering and sales operations and corporate operations.

Management evaluates the performance of the Company’s business segments based on operating income (loss), which is defined as segment operating revenues less operating expenses and depreciation, depletion and amortization. Summarized financial information concerning the Company’s segments is shown in the following tables (in thousands):

	Exploration  and Production			Drilling and Oil Field Services			Midstream  Gas Services			All Other			Consolidated Total
Three Months Ended June 30, 2011
Revenues	$	317,768		$	96,443		$	48,278		$	2,886		$	465,375
Inter-segment revenue		(66	)		(67,906	)		(32,473	)		(156	)		(100,601	)
Total revenues	$	317,702		$	28,537		$	15,805		$	2,730		$	364,774
Operating income (loss)	$	301,197		$	4,098		$	(2,570	)	$	(23,009	)	$	279,716
Interest income (expense), net		15			4			(141	)		(61,565	)		(61,687	)
Loss on extinguishment of debt		—			—			—			(2,051	)		(2,051	)
Other income (expense), net		3			—			216			(81	)		138
Income (loss) before income taxes	$	301,215		$	4,102		$	(2,495	)	$	(86,706	)	$	216,116
Capital expenditures(1)	$	423,725		$	8,030		$	4,462		$	17,875		$	454,092
Depreciation, depletion and amortization	$	76,734		$	7,998		$	1,291		$	3,438		$	89,461
Three Months Ended June 30, 2010
Revenues	$	150,571		$	55,975		$	66,379		$	8,744		$	281,669
Inter-segment revenue		(66	)		(52,063	)		(44,223	)		(2,878	)		(99,230	)
Total revenues	$	150,505		$	3,912		$	22,156		$	5,866		$	182,439
Operating income (loss)	$	136,465		$	(294	)	$	902		$	(17,621	)	$	119,452
Interest income (expense), net		121			(254	)		(161	)		(63,867	)		(64,161	)
Other income (expense), net		13			—			56			(599	)		(530	)
Income (loss) before income taxes	$	136,599		$	(548	)	$	797		$	(82,087	)	$	54,761
Capital expenditures(1)	$	218,973		$	8,195		$	16,337		$	5,459		$	248,964
Depreciation, depletion and amortization	$	55,041		$	6,833		$	927		$	3,338		$	66,139
Six Months Ended June 30, 2011
Revenues	$	585,004		$	163,992		$	104,256		$	6,106		$	859,358
Inter-segment revenue		(133	)		(114,421	)		(66,511	)		(672	)		(181,737	)
Total revenues	$	584,871		$	49,571		$	37,745		$	5,434		$	677,621
Operating income (loss)	$	116,990		$	3,990		$	(5,098	)	$	(43,995	)	$	71,887
Interest income (expense), net		120			(101	)		(313	)		(120,830	)		(121,124	)
Loss on extinguishment of debt		—			—			—			(38,232	)		(38,232	)
Other income (expense), net		1,679			—			(485	)		141			1,335
Income (loss) before income taxes	$	118,789		$	3,889		$	(5,896	)	$	(202,916	)	$	(86,134	)
Capital expenditures(1)	$	826,813		$	14,793		$	8,635		$	24,011		$	874,252
Depreciation, depletion and amortization	$	151,206		$	15,727		$	2,388		$	7,119		$	176,440
At June 30, 2011
Total assets	$	4,951,934		$	232,165		$	153,516		$	259,059		$	5,596,674
Six Months Ended June 30, 2010
Revenues	$	320,755		$	142,049		$	148,916		$	19,197		$	630,917
Inter-segment revenue		(131	)		(132,377	)		(99,233	)		(5,742	)		(237,483	)
Total revenues	$	320,624		$	9,672		$	49,683		$	13,455		$	393,434
Operating income (loss)	$	246,488		$	(4,594	)	$	2,156		$	(35,427	)	$	208,623
Interest expense (expense), net		200			(567	)		(299	)		(125,515	)		(126,181	)
Other income (expense), net		781			—			56			(131	)		706
Income (loss) before income taxes	$	247,469		$	(5,161	)	$	1,913		$	(161,073	)	$	83,148
Capital expenditures(1)	$	411,050		$	17,612		$	36,759		$	12,124		$	477,545
Depreciation, depletion and amortization	$	108,034		$	14,163		$	1,803		$	6,720		$	130,720
At December 31, 2010
Total assets	$	4,612,295		$	224,784		$	151,598		$	242,771		$	5,231,448

(1) On an accrual basis.

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Long-Term Debt

6 Months Ended

Jun. 30, 2011

Long-Term Debt

11. Long-Term Debt

Long-term debt consists of the following (in thousands):

	June 30, 2011		December 31, 2010
Senior credit facility	$	80,000	$	340,000
Other notes payable
Drilling rig fleet and related oil field services equipment		—		6,302
Mortgage		16,527		17,020
Senior Floating Rate Notes due 2014		350,000		350,000
8.625% Senior Notes due 2015		—		650,000
9.875% Senior Notes due 2016, net of $11,881 and $12,793 discount, respectively		353,619		352,707
8.0% Senior Notes due 2018		750,000		750,000
8.75% Senior Notes due 2020, net of $6,693 and $6,943 discount, respectively		443,307		443,057
7.5% Senior Notes due 2021		900,000		—
Total debt		2,893,453		2,909,086
Less: current maturities of long-term debt		1,019		7,293
Long-term debt	$	2,892,434	$	2,901,793

For the three-month periods ended June 30, 2011 and 2010, interest payments were approximately $56.9 million and $83.3 million, respectively. For the six-month periods ended June 30, 2011 and 2010, interest payments were approximately $110.3 million and $92.3 million, respectively. Interest paid for the three and six-month periods ended June 30, 2011 included $1.5 million and $25.7 million, respectively, of accrued interest paid in connection with the purchase and redemption of the 8.625% Senior Notes due 2015. See discussion of redemption below.

Senior Credit Facility. The senior credit facility is available to be drawn on subject to limitations based on its terms and certain financial covenants, as described below. The senior credit facility matures on April 15, 2014.

On February 23, 2011, the senior credit facility was amended to, among other things, (a) exclude from the calculation of Consolidated Net Income the net income (or loss) of a Royalty Trust, except to the extent of cash distributions received by the Company, (b) establish that an investment in a Royalty Trust and dispositions to, and of interests in, Royalty Trusts are permitted, (c) clarify that a Royalty Trust is not a Subsidiary, (d) allow the Company to net against its calculation of Consolidated Funded Indebtedness cash balances exceeding $10.0 million in the event no loans are outstanding under the senior credit facility at that time, and (e) establish that, for any fiscal quarter ending prior to March 31, 2012, if the ratio of the Company’s secured indebtedness to EBITDA is less than 1.5:1.0 then compliance with the Company’s Consolidated Leverage Ratio covenant is not required. Terms capitalized in the preceding sentence have the meaning given to them in the senior credit facility, as amended.

On April 20, 2011, the senior credit facility was amended. The amendment permits the Company to pay cash dividends on its 7.0% convertible perpetual preferred stock and reaffirms the borrowing base at $790.0 million.

As of June 30, 2011, the senior credit facility contained financial covenants, including maintaining agreed levels for the (i) ratio of total funded debt to EBITDA, which may not exceed 4.5:1.0 at each quarter end, calculated using the last four completed fiscal quarters, unless, for any quarter ending prior to March 31, 2012, the ratio of the Company’s secured indebtedness to EBITDA is less than 1.5:1.0, calculated using the last four completed fiscal quarters (in each case through the second quarter of 2011, adjusted for annualized amounts of the post-acquisition results of operations of Arena), (ii) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at each quarter end (in the current ratio calculation (as defined in the senior credit facility), any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on the Company’s derivative contracts are disregarded) and (iii) ratio of the Company’s secured indebtedness to EBITDA, which may not exceed 2.0:1.0 at each quarter end, calculated using the last four completed fiscal quarters (in each case through the second quarter of 2011, adjusted for annualized amounts of the post-acquisition results of operations of Arena). As of and during the three and six-month periods ended June 30, 2011, the Company was in compliance with all of the financial covenants under the senior credit facility.

Additionally, the senior credit facility contains various covenants that limit the ability of the Company and certain of its subsidiaries to grant certain liens; make certain loans and investments; make distributions; redeem stock; redeem or prepay debt; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets. Additionally, the senior credit facility limits the ability of the Company and certain of its subsidiaries to incur additional indebtedness with certain exceptions.

The obligations under the senior credit facility are guaranteed by certain Company subsidiaries and are secured by first priority liens on all shares of capital stock of each of the Company’s material present and future subsidiaries; all intercompany debt of the Company; and substantially all of the Company’s assets, including proved oil and natural gas reserves representing at least 80% of the discounted present value (as defined in the senior credit facility) of proved oil and natural gas reserves considered by the lenders in determining the borrowing base for the senior credit facility.

At the Company’s election, interest under the senior credit facility is determined by reference to (a) the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 2.00% and 3.00% per annum or (b) the “base rate,” which is the highest of (i) the federal funds rate plus 0.5%, (ii) the prime rate published by Bank of America or (iii) the Eurodollar rate (as defined in the senior credit facility) plus 1.00% per annum, plus, in each case under scenario (b), an applicable margin between 1.00% and 2.00% per annum. Interest is payable quarterly for base rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest is paid at the end of each three-month period. The average annual interest rate paid on amounts outstanding under the senior credit facility was 2.51% and 2.65% for the three-month periods ended June 30, 2011 and 2010, respectively, and 2.70% and 2.52% for the six-month periods ended June 30, 2011 and 2010, respectively.

Borrowings under the senior credit facility may not exceed the lower of the borrowing base or the committed amount. On March 15, 2011, the borrowing base was reduced from $850.0 million to $790.0 million as a result of the issuance of the 7.5% Senior Notes due 2021, discussed below. The Company’s borrowing base is redetermined in April and October of each year. With respect to each redetermination, the administrative agent and the lenders under the senior credit facility consider several factors, including the Company’s proved reserves and projected cash requirements, and make assumptions regarding, among other things, oil and natural gas prices and production. Because the value of the Company’s proved reserves is a key factor in determining the amount of the borrowing base, changing commodity prices and the Company’s success in developing reserves may affect the borrowing base. At the April 2011 redetermination, the borrowing base remained $790.0 million. The Company at times incurs additional costs related to the senior credit facility as a result of amendments to the credit agreement and changes to the borrowing base. During the first six months of 2011, additional costs of approximately $0.3 million were incurred. These costs have been deferred and are included in other assets in the accompanying condensed consolidated balance sheets.

At June 30, 2011, the Company had $80.0 million outstanding under the senior credit facility and $24.5 million in outstanding letters of credit, which affect the availability under the senior credit facility on a dollar-for-dollar basis.

Other Notes Payable. The Company financed a portion of its drilling rig fleet and related oil field services equipment through the issuance of notes secured by such equipment. In March 2011, the Company paid the outstanding $4.3 million principal balance on these notes.

The debt incurred to purchase the downtown Oklahoma City property that serves as the Company’s corporate headquarters is fully secured by a mortgage on one of the buildings located on the property. The note underlying the mortgage bears interest at 6.08% annually and matures on November 15, 2022. Payments of principal and interest in the amount of approximately $0.5 million are due on a quarterly basis through the maturity date.

Senior Floating Rate Notes Due 2014 and 8.625% Senior Notes Due 2015. The Company’s Senior Floating Rate Notes due 2014 (the “Senior Floating Rate Notes”) and 8.625% Senior Notes due 2015 (the “8.625% Senior Notes”) were issued in May 2008. The Senior Floating Rate Notes are jointly and severally guaranteed unconditionally on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable. See Note 20 for condensed financial information of the subsidiary guarantors. As discussed below, on April 1, 2011, the Company redeemed the 8.625% Senior Notes that remained outstanding following the completion of its tender offer in respect of such notes.

The Senior Floating Rate Notes bear interest at LIBOR plus 3.625% (3.93% at June 30, 2011). Interest is payable quarterly with the principal due on April 1, 2014. The average interest rate paid on the outstanding Senior Floating Rate Notes was 3.93% and 3.92% for the three-month periods ended June 30, 2011 and 2010, respectively, and 3.93% and 3.90% for the six-month periods ended June 30, 2011 and 2010, respectively, without consideration of the interest rate swap discussed below. The Company may redeem, at specified redemption prices, some or all of the Senior Floating Rate Notes at any time.

As of June 30, 2011, the Company had a $350.0 million notional interest rate swap agreement to fix the variable interest rate on the Senior Floating Rate Notes through April 1, 2013. The swap agreement effectively serves to fix the rate on the Senior Floating Rate Notes at an annual rate of 6.69% for the period from April 1, 2011 to April 1, 2013. This swap has not been designated as a hedge.

On March 1, 2011, the Company announced a cash tender offer to purchase any and all of the outstanding $650.0 million aggregate principal amount of its 8.625% Senior Notes for total consideration of $1,046.88 per $1,000 principal amount of such notes tendered by March 14, 2011. Holders tendering after March 14, 2011 were eligible to receive $1,016.88 per $1,000 principal amount of notes tendered. All holders whose notes were purchased received accrued and unpaid interest from the last interest payment date. As of March 31, 2011, the Company had purchased approximately 94.5%, or $614.2 million, of the aggregate principal amount of its 8.625% Senior Notes pursuant to the tender offer, which expired on March 28, 2011. On April 1, 2011, the Company redeemed the remaining outstanding $35.8 million aggregate principal amount of its 8.625% Senior Notes for $1,043.13 per $1,000 principal amount outstanding, plus accrued interest. All holders whose notes were redeemed received accrued and unpaid interest from October 1, 2010. The premium paid to purchase these notes and the unamortized debt issuance costs associated with the notes, totaling $2.0 million and $38.2 million for the three and six-month periods ended June 30, 2011, respectively, were recorded as a loss on extinguishment of debt and are included in the accompanying condensed consolidated statements of operations.

The $9.4 million of debt issuance costs associated with the Senior Floating Rate Notes is included in other assets in the accompanying condensed consolidated balance sheets and is being amortized over the term of the notes.

9.875% Senior Notes Due 2016. The Company’s unsecured 9.875% Senior Notes due 2016 (the “9.875% Senior Notes”) were issued in May 2009 and bear interest at a fixed rate of 9.875% per annum, payable semi-annually, with the principal due on May 15, 2016. The 9.875% Senior Notes were issued at a discount, which is amortized into interest expense over the term of the notes. The 9.875% Senior Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally guaranteed unconditionally on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable.

Debt issuance costs of $7.9 million incurred in connection with the offering of the 9.875% Senior Notes are included in other assets in the accompanying condensed consolidated balance sheets and are being amortized over the term of the notes.

8.0% Senior Notes Due 2018. The Company’s unsecured 8.0% Senior Notes due 2018 (the “8.0% Senior Notes”) were issued in May 2008 and bear interest at a fixed rate of 8.0% per annum, payable semi-annually, with the principal due on June 1, 2018. The notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally guaranteed unconditionally on an unsecured basis, by certain of the Company’s wholly owned subsidiaries and are freely tradable.

The Company incurred $16.0 million of debt issuance costs in connection with the offering of the 8.0% Senior Notes. These costs are included in other assets in the accompanying condensed consolidated balance sheets and are being amortized over the term of the notes.

8.75% Senior Notes Due 2020. The Company’s unsecured 8.75% Senior Notes due 2020 (the “8.75% Senior Notes”) were issued in December 2009 and bear interest at a fixed rate of 8.75% per annum, payable semi-annually, with the principal due on January 15, 2020. The 8.75% Senior Notes were issued at a discount which is amortized into interest expense over the term of the notes. The 8.75% Senior Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally, guaranteed unconditionally on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable. See Note 20 for condensed financial information of the subsidiary guarantors.

Debt issuance costs of $9.7 million incurred in connection with the offering of and subsequent registered exchange of the 8.75% Senior Notes are included in other assets in the accompanying condensed consolidated balance sheets and are being amortized over the term of the notes.

7.5% Senior Notes Due 2021. In March 2011, the Company issued $900.0 million of unsecured 7.5% Senior Notes due 2021 (the “7.5% Senior Notes”) to qualified institutional buyers eligible under Rule 144A of the Securities Act and to persons outside the United States under Regulation S under the Securities Act. Net proceeds from the offering were approximately $880.7 million after deducting offering expenses, and were used to fund the tender offer for the 8.625% Senior Notes, including any accrued and unpaid interest, the redemption of the 8.625% Senior Notes that remained outstanding following the conclusion of the tender offer, including accrued and unpaid interest (each as described above) and to repay borrowings under the Company’s senior credit facility. The 7.5% Senior Notes bear interest at a fixed rate of 7.5% per annum, payable semi-annually, with the principal due on March 15, 2021. Prior to March 15, 2016, the 7.5% Senior Notes are redeemable, in whole or in part, at a specified redemption price plus accrued and unpaid interest. On or after March 15, 2016, the 7.5% Senior Notes are redeemable, in whole or in part, prior to their maturity at other various specified redemption prices. The notes are jointly and severally guaranteed unconditionally on an unsecured basis by certain of the Company’s wholly owned subsidiaries.

In conjunction with the issuance of the 7.5% Senior Notes, the Company entered into a Registration Rights Agreement requiring the Company to conduct a registered exchange offer for or register the resale of these notes before March 14, 2012. The Company is required to pay additional interest if it fails to fulfill its obligations under the agreement within the specified time periods.

Debt issuance costs of $19.3 million incurred in connection with the offering of the 7.5% Senior Notes are included in other assets in the accompanying condensed consolidated balance sheets and are being amortized over the term of the notes.

Indentures. The indentures governing the Company’s senior notes contain limitations on the incurrence of indebtedness, payment of dividends, investments, asset sales, certain asset purchases, transactions with related parties and consolidations or mergers. As of and for the three and six-month periods ended June 30, 2011, the Company was in compliance with all of the covenants contained in the indentures governing the senior notes.

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Recent Accounting Pronouncements

6 Months Ended

Jun. 30, 2011

Recent Accounting Pronouncements

2. Recent Accounting Pronouncements

For a description of the Company’s significant accounting policies, refer to Note 1 of the consolidated financial statements included in the 2010 Form 10-K.

Recently Adopted Accounting Pronouncements. In January 2010, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update 2010-06, “Fair Value Measurements and Disclosures: Improving Disclosures about Fair Value Measurements” (“ASU 2010-06”). ASU 2010-06 requires additional disclosures and clarifies existing disclosure requirements about fair value measurement as set forth in Accounting Standards Codification (“ASC”) Topic 820, Fair Value Measurements and Disclosures. The new disclosure requirements regarding activity in Level 3 fair value measurements, which are effective for fiscal years beginning after December 15, 2010, were implemented in the first quarter of 2011 by the Company. The implementation of ASU 2010-06 had no impact on the Company’s financial position or results of operations. See Note 4.

Recent Accounting Pronouncement Not Yet Adopted. In May 2011, the FASB issued Accounting Standards Update 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS” (“ASU 2011-04”). ASU 2011-04 clarifies the FASB’s intent about the application of existing fair value measurements as set forth in ASC Topic 820 and requires additional disclosure information regarding valuation processes and inputs used. The new disclosure requirements are effective for interim and annual reporting periods beginning after December 15, 2011. As the additional requirements under ASU 2011-04, which will be implemented January 1, 2012, pertain to fair value measurement disclosures, no effect to the Company’s financial position or results of operations is expected.

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Income Taxes (Tables)

6 Months Ended

Jun. 30, 2011

Provisions (Benefits) for Income Taxes

income taxes on a current year-to-date basis. The (benefit) provision for income taxes consisted of the following components for the three and six-month periods ended June 30, 2011 and 2010 (in thousands).

	Three Months Ended June  30,					Six Months Ended June  30,
	2011			2010		2011			2010
Current
Federal	$	(137	)	$	—	$	(116	)	$	—
State		69			150		135			162
		(68	)		150		19			162
Deferred
Federal		(6,385	)		—		(6,385	)		—
State		(601	)		—		(601	)		—
		(6,986	)		—		(6,986	)		—
Total (benefit) provision		(7,054	)		150		(6,967	)		162
Less: income tax provision attributable to noncontrolling interest		—			89		2			89
Total (benefit) provision attributable to SandRidge Energy, Inc.	$	(7,054	)	$	61	$	(6,969	)	$	73

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Variable Interest Entities

6 Months Ended

Jun. 30, 2011

Variable Interest Entities

8. Variable Interest Entities

In accordance with the guidance in ASC Topic 810, Consolidation, including the guidance in Accounting Standards Update 2009-17, “Consolidations—Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities” (“ASU 2009-17”), the Company consolidates the activities of variable interest entities (“VIEs”) of which it is the primary beneficiary. The primary beneficiary of a VIE is that variable interest holder possessing a controlling financial interest through (i) its power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE, the Company performs a qualitative analysis of the entity’s design, organizational structure, primary decision makers and related financial agreements.

The Company’s significant associated VIEs, including those for which the Company has determined it is the primary beneficiary and those for which it has determined it is not, are described below.

SandRidge Mississippian Trust I. On April 12, 2011, SandRidge Mississippian Trust I (the “Mississippian Trust”), a newly formed Delaware statutory trust, completed its initial public offering of 17,250,000 common units representing beneficial interests in the Mississippian Trust. Net proceeds to the Mississippian Trust, after certain offering expenses, were approximately $336.9 million. In conjunction with the closing, the Company conveyed certain royalty interests to the Mississippian Trust in exchange for the net proceeds of the Mississippian Trust’s initial public offering and 10,750,000 units (3,750,000 common units and 7,000,000 subordinated units) representing approximately 38.4% of the beneficial interest in the Mississippian Trust. The royalty interests conveyed to the Mississippian Trust are in certain oil and natural gas properties leased by the Company in the Mississippian formation in five counties in Northern Oklahoma. The conveyance of the royalty interests to the Mississippian Trust was recorded in April 2011 at the historical cost to the Company, or $309.0 million, and was determined by allocating the historical net book value of the Company’s full cost pool based on the fair value of the conveyed royalty interests relative to the fair value of the Company’s total full cost pool.

In order to provide support for cash distributions on the Mississippian Trust’s common units, SandRidge agreed to subordinate a portion of the Mississippian Trust units it owns (the “subordinated units”), which constitute 25% of the total outstanding Mississippian Trust units. The subordinated units are entitled to receive pro rata distributions from the Mississippian Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is no less than the applicable quarterly subordination threshold. If there is not sufficient cash to fund such a distribution on all common units, the distribution to be made with respect to the subordinated units will be reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on all common units, including common units held by the Company.

SandRidge and one of its wholly owned subsidiaries entered into a development agreement with the Mississippian Trust that obligates the Company to drill, or cause to be drilled, a specified number of wells, which are also subject to the royalty interest, by December 31, 2014. In the event of delays, the Company will have until December 31, 2015 to fulfill its drilling obligation. At the end of the fourth full calendar quarter following satisfaction of the Company’s drilling obligation (the “subordination period”), the Company’s subordinated units will automatically convert into common units on a one-for-one basis and the Company’s right to receive incentive distributions will terminate. Incentive distributions are equal to 50% of the amount by which the cash available for distribution on all of the Mississippian Trust units for any quarter is 20% or greater than the target distribution for such quarter. One of the Company’s wholly owned subsidiaries also granted to the Mississippian Trust a lien in the Company’s interests in the properties where the development wells will be drilled, in order to secure the estimated amount of the drilling costs for the wells. As the Company fulfills its drilling obligation, the total amount that may be recovered by the Mississippian Trust will be proportionately reduced and completed development wells will be released from the lien. As of June 30, 2011, the maximum amount recoverable by the Mississippian Trust under the lien was $136.4 million. Additionally, the Company and the Mississippian Trust entered into an administrative services agreement, pursuant to which the Company provides certain administrative services to the Mississippian Trust, and a derivatives agreement, pursuant to which the Company passes to the Mississippian Trust the benefits and obligations of certain of the Company’s derivative contracts. The tables below present open oil and natural gas commodity derivative contracts at June 30, 2011, the benefits and obligations of which will be passed to the Mississippian Trust under the derivatives agreement. See Note 12 for further discussion of the derivatives agreement between the Company and the Mississippian Trust and a complete listing of the Company’s open commodity derivative contracts at June 30, 2011, including the derivative contracts the effects of which have been conveyed to the Mississippian Trust.

Oil

Period and Type of Contract	Notional (MBbl)		Weighted Avg. Fixed Price
July 2011 — December 2011
Price swap contracts		241	$	103.60
January 2012 — December 2012
Price swap contracts		454	$	104.15
January 2013 — December 2013
Price swap contracts		488	$	102.07
January 2014 — December 2014
Price swap contracts		541	$	100.94
January 2015 — December 2015
Price swap contracts		468	$	101.07

Natural Gas

Period and Type of Contract	Notional (MMcf)(1)		Weighted Avg. Fixed Price		Collar Range
July 2011 — December 2011
Price swap contracts		2,086	$	4.61		—
January 2012 — June 2012
Price swap contracts		2,190	$	4.90		—
July 2012 — December 2012
Collars		402		—	$	4.00 - $6.20
January 2013 — December 2013
Collars		858		—	$	4.00 - $7.15
January 2014 — December 2014
Collars		937		—	$	4.00 - $7.78
January 2015 — December 2015
Collars		1,010		—	$	4.00 - $8.55

(1) Assumes ratio of 1:1 for Mcf to MMBtu.

The Mississippian Trust is considered a VIE due to the lack of voting or similar decision-making rights by its equity holders regarding activities that have a significant effect on the success of the Mississippian Trust. The Company’s ownership in the Mississippian Trust constitutes a variable interest. The Company has determined it is the primary beneficiary of the Mississippian Trust as it has (a) the power to direct the activities that most significantly impact the economic performance of the Mississippian Trust through (i) its participation in the creation and structure of the Mississippian Trust, (ii) the manner in which it fulfills its drilling obligation to the Mississippian Trust, and (iii) the manner in which it operates the Underlying Properties, and (b) through the end of the subordination period, the obligation to absorb losses and right to receive residual returns, through its ownership of the subordinated units, that could potentially be significant to the Mississippian Trust. As a result, the Company began consolidating the activities of the Mississippian Trust into its results of operations in April 2011. In consolidation, the common units of the Mississippian Trust owned by third parties are reflected as noncontrolling interest. As discussed above, the Company’s subordinated Mississippian Trust units will automatically convert to common Mississippian Trust units at the end of the subordination period.

The Mississippian Trust’s assets can be used to settle its own obligations and not other obligations of the Company. The Mississippian Trust’s creditors have no contractual recourse to the general credit of the Company. Although the Mississippian Trust is included in the Company’s consolidated financial statements, the Company’s legal interest in the Mississippian Trust’s assets is limited to its ownership of the Mississippian Trust units. At June 30, 2011, $350.2 million of noncontrolling interest in the accompanying condensed consolidated balance sheets was attributable to the Mississippian Trust. The Mississippian Trust’s assets and liabilities included in the accompanying condensed consolidated balance sheet at June 30, 2011 consisted of the following (in thousands):

Current assets	$	6,570
Investment in royalty interests, net(1)		304,656
Total assets	$	311,226
Current liabilities	$	651
Total liabilities	$	651

(1) Included in oil and natural gas properties on the condensed consolidated balance sheet.

Grey Ranch, L.P. Primarily engaged in treating and transportation of natural gas, Grey Ranch Plant, L.P. (“GRLP”) is a limited partnership that operates the Company’s Grey Ranch plant (the “Plant”) located in Pecos County, Texas. The Company has long-term operating and gathering agreements with GRLP and also owns a 50% interest in GRLP. Income or losses of GRLP are allocated to the partners based on ownership percentage and any operating or cash shortfalls require contributions from the partners. The Company has determined that GRLP qualifies as a VIE under the provisions of ASC Topic 810. Agreements related to the ownership and operation of GRLP provide for GRLP to pay management fees to the Company to operate the Plant and lease payments for the Plant. Under the operating agreements, lease payments are reduced if throughput volumes are below those expected. The Company has determined that it is the primary beneficiary of GRLP as it has both (i) the power to direct the activities of GRLP that most significantly impact its economic performance as operator of the Plant and (ii) the obligation to absorb losses, as a result of the operating and gathering agreements, that could potentially be significant to GRLP.

GRLP’s assets can be used to settle its own obligations and not other obligations of the Company. GRLP’s creditors have no recourse to the general credit of the Company. Although GRLP is included in the Company’s consolidated financial statements, the Company’s legal interest in GRLP’s assets is limited to its 50% ownership. At June 30, 2011 and December 31, 2010, $9.6 million and $11.3 million, respectively, of noncontrolling interest in the accompanying condensed consolidated balance sheets were related to GRLP. GRLP’s assets and liabilities included in the accompanying condensed consolidated balance sheets at June 30, 2011 and December 31, 2010 consisted of the following (in thousands):

	June 30,		December 31,
	2011		2010
Current assets	$	3,719	$	8,215
Other property, plant and equipment, net		15,560		16,079
Total assets	$	19,279	$	24,294
Current liabilities	$	318	$	1,751
Total liabilities	$	318	$	1,751

Grey Ranch Plant Genpar, LLC. The Company owns a 50% interest in Grey Ranch Plant Genpar, LLC (“Genpar”), the managing partner and 1% owner of GRLP. Additionally, the Company serves as Genpar’s administrative manager. Genpar’s ownership interest in GRLP is its only asset.

As managing partner of GRLP, Genpar has the sole right to manage, control and conduct the business of GRLP. However, Genpar is restricted from making certain major decisions, including the decision to remove the Company as operator of the Plant. The rights afforded the Company under the Plant operating agreement and the restrictions on Genpar serve to limit Genpar’s ability to make decisions on behalf of GRLP. Therefore, Genpar is considered a VIE. Although both the Company and Genpar’s other equity owner share equally in Genpar’s economic losses and benefits and also have agreements that may be considered variable interests, the Company determined it was the primary beneficiary due to (i) its ability, as administrative manager, to direct the activities of Genpar that most significantly impact its performance and (ii) its obligation or right, as operator of the Plant, to absorb the losses of or receive benefits from Genpar that could potentially be significant to Genpar. As the primary beneficiary, the Company consolidates Genpar’s activity. However, its sole asset, the investment in GRLP, is eliminated in consolidation. Genpar has no liabilities.

Piñon Gathering Company, LLC. The Company has 20-year gas gathering and operations and maintenance agreements with Piñon Gathering Company, LLC (“PGC”). Under the gas gathering agreement, the Company is required to compensate PGC for any throughput shortfalls below a required minimum volume. By guaranteeing a minimum throughput, the Company absorbs the risk that lower than projected volumes will be gathered by the gathering system. Therefore, PGC is a VIE. While the Company operates the assets of PGC as directed under the operations and management agreement, the member and managers of PGC have the authority to directly control PGC and make substantive decisions regarding PGC’s activities including terminating the Company as operator without cause. As the Company does not have the ability to control the activities of PGC that most significantly impact PGC’s economic performance, the Company is not the primary beneficiary of PGC. Therefore, the results of PGC’s activities are not consolidated into the Company’s financial statements.

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Income Taxes

6 Months Ended

Jun. 30, 2011

Income Taxes

13. Income Taxes

The Company estimates for each interim reporting period the effective tax rate expected for the full fiscal year and uses that estimated rate in providing for income taxes on a current year-to-date basis. The (benefit) provision for income taxes consisted of the following components for the three and six-month periods ended June 30, 2011 and 2010 (in thousands).

	Three Months Ended June  30,					Six Months Ended June  30,
	2011			2010		2011			2010
Current
Federal	$	(137	)	$	—	$	(116	)	$	—
State		69			150		135			162
		(68	)		150		19			162
Deferred
Federal		(6,385	)		—		(6,385	)		—
State		(601	)		—		(601	)		—
		(6,986	)		—		(6,986	)		—
Total (benefit) provision		(7,054	)		150		(6,967	)		162
Less: income tax provision attributable to noncontrolling interest		—			89		2			89
Total (benefit) provision attributable to SandRidge Energy, Inc.	$	(7,054	)	$	61	$	(6,969	)	$	73

Deferred income taxes are provided to reflect the future tax consequences of temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. Deferred tax assets are reduced by a valuation allowance as necessary when a determination is made that it is more likely than not that some or all of the deferred tax assets will not be realized based on the weight of all available evidence. As of December 31, 2008, the Company determined it was appropriate to record a full valuation allowance against its net deferred tax asset. In the second quarter of 2011, the Company completed its valuation of assets acquired and liabilities assumed related to the Arena Acquisition in order to finalize the purchase price allocation. In connection therewith, the Company adjusted the previously recorded net deferred tax liability associated with the Arena Acquisition by recording an additional net deferred tax liability of $7.0 million. The adjustment resulted in the Company releasing a corresponding portion of its previously recorded valuation allowance. This release of valuation allowance is in addition to the $447.5 million released in 2010. The 2010 and 2011 partial releases of the valuation allowance were based on management’s assessment that it is more likely than not that the Company will realize a benefit from more of its existing deferred tax assets as the Arena deferred tax liabilities are available to offset the reversal of the Company’s deferred tax assets. Although the Company continued to have a full valuation allowance against its net deferred tax asset at June 30, 2011, the additional release of the valuation allowance resulted in an income tax benefit of $7.0 million for the three and six-month periods ended June 30, 2011.

IRC Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. The Company experienced an ownership change within the meaning of IRC Section 382 on December 31, 2008. The ownership change subjected certain of the Company’s tax attributes, including $302.8 million of federal net operating loss carryforwards, to the IRC Section 382 limitation. The Company experienced a subsequent ownership change within the meaning of IRC Section 382 on July 16, 2010 as a result of the Arena Acquisition. The Company expects a more restrictive limitation on certain of its tax attributes as a result of the July 16, 2010 ownership change than with the December 31, 2008 ownership change. The more restrictive limitation would apply not only to the $302.8 million of federal net operating loss carryforwards and certain other tax attributes existing at December 31, 2008 but also to the net operating losses of approximately $491.4 million and certain other attributes generated during the period from January 1, 2009 through July 16, 2010. The subsequent limitation could result in a material amount of the loss carryforwards existing at July 16, 2010 expiring unused. Arena also experienced an ownership change on July 16, 2010 as a result of its acquisition by the Company. This ownership change is expected to result in a limitation on Arena’s net operating loss carryforwards and certain other carryforwards available to the Company on an annual basis. None of the limitations discussed above resulted in a current federal tax liability at June 30, 2011 or December 31, 2010.

As of June 30, 2011, the Company had a liability of approximately $1.52 million for unrecognized tax benefits. If recognized, approximately $1.0 million, net of federal tax expense, would be recorded as a reduction of income tax expense and would affect the effective tax rate. The liability for unrecognized tax benefits as of December 31, 2010 was $1.45 million.

Consistent with the Company’s policy to record interest and penalties on income taxes as a component of the income tax provision, the Company has included $0.02 million and $0.07 million of accrued gross interest with respect to unrecognized tax benefits in its condensed consolidated statements of operations for the three and six-month periods ended June 30, 2011, respectively. The Company did not recognize any interest and penalties related to unrecognized tax benefits during the three and six-month periods ended June 30, 2010.

The Company’s only taxing jurisdiction is the United States (federal and state). The Company’s tax years 2007 to present remain open for federal examination. Additionally, various tax years remain open for certain acquired entities beginning with tax year 2003 due to federal net operating loss carryforwards. The number of years open for state tax audits varies, depending on the state, but are generally from three to five years. Currently, several examinations are in progress. The Company does not anticipate that any federal or state audits will have a significant impact on the Company’s results of operations or financial position. In addition, the Company does not expect resolution of any uncertain tax positions that would result in a significant increase or decrease to the amount of unrecognized tax benefits during the next twelve months.

For the three-month period ended June 30, 2011, income tax refunds, net of payments, were $0.04 million. For the six-month period ended June 30, 2011, income tax payments, net of refunds, were $0.94 million. For the three and six-month periods ended June 30, 2010, income tax refunds, net of payments, were $0.1 million and $3.5 million, respectively.

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Calculation of Weighted Average Common Shares Outstanding Used in the Computation of Diluted Earnings Per Share (Detail) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Earnings Per Share Disclosure [Line Items]
Weighted average basic common shares outstanding	398,435	203,839	398,343	203,831
Effect of dilutive securities:
Restricted stock	7,414	4,231		4,152
Convertible preferred stock outstanding	90,133	51,496		18,423
Weighted average diluted common and potential common shares outstanding	495,982	259,566	398,343	226,406

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Century Plant Contract

6 Months Ended

Jun. 30, 2011

Century Plant Contract

9. Century Plant Contract

The Company is constructing the Century Plant, a CO₂ treatment plant in Pecos County, Texas (the “Century Plant”), and associated compression and pipeline facilities pursuant to an agreement with Occidental Petroleum Corporation (“Occidental”). Under the terms of the agreement, the Company will construct the Century Plant and Occidental will pay the Company a minimum of 100% of the contract price, or $800.0 million, plus any subsequently agreed-upon revisions, through periodic cost reimbursements based upon the percentage of the project completed by the Company. The Company expects to complete the Century Plant in two phases. Upon completion of each phase of the Century Plant, Occidental will take ownership of the related assets and will operate the Century Plant for the purpose of separating and removing CO₂ from delivered natural gas. Phase I is in the commissioning process with completion and transfer of title to Occidental expected in the third quarter of 2011, and Phase II is under construction and expected to be completed in mid 2012. Pursuant to a 30-year treating agreement executed simultaneously with the construction agreement, Occidental will remove CO₂ from the Company’s delivered production volumes. The Company will retain all methane gas from the natural gas it delivers to the Century Plant.

The Company accounts for construction of the Century Plant using the completed-contract method, under which contract revenues and costs are recognized when work under both phases of the contract is completed and assets have been transferred to Occidental. In the interim, costs incurred on and billings related to contracts in process are accumulated on the balance sheet. Contract gains or losses will be recorded, as development costs within the Company’s oil and natural gas properties as part of the full cost pool, when it is determined that a gain or loss will be incurred. The Company recorded an addition of $124.0 million ($105.0 million in 2010 and $19.0 million in the first quarter of 2011) to its oil and natural gas properties for the estimated loss identified based on projections of the costs to be incurred in excess of contract amounts. Billings and estimated contract loss in excess of costs incurred of $41.2 million and $31.5 million at June 30, 2011 and December 31, 2010, respectively, are reported as current liabilities in the accompanying condensed consolidated balance sheets.

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Condensed Consolidating Statements of Cash Flows of SandRidge Energy, Inc. and Wholly Owned Subsidiary Guarantors and Non-Guarantors (Detail) (USD $) In Thousands	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Schedule of Condensed Consolidating Statement of Cash Flows [Line Items]
Net cash (used in) provided by operating activities	$ 261,004	$ 258,459
Net cash used in investing activities	(502,650)	(416,199)
Net cash provided by (used in) financing activities	240,398	151,962
NET DECREASE IN CASH AND CASH EQUIVALENTS	(1,248)	(5,778)
CASH AND CASH EQUIVALENTS, beginning of year	5,863	7,861
CASH AND CASH EQUIVALENTS, end of period	4,615	2,083
Parent Company
Schedule of Condensed Consolidating Statement of Cash Flows [Line Items]
Net cash (used in) provided by operating activities	94,579	(160,436)
Net cash provided by (used in) financing activities	(95,214)	160,266
NET DECREASE IN CASH AND CASH EQUIVALENTS	(635)	(170)
CASH AND CASH EQUIVALENTS, beginning of year	1,441	339
CASH AND CASH EQUIVALENTS, end of period	806	169
Guarantor Subsidiaries
Schedule of Condensed Consolidating Statement of Cash Flows [Line Items]
Net cash (used in) provided by operating activities	162,726	417,020
Net cash used in investing activities	(163,785)	(413,221)
Net cash provided by (used in) financing activities	712	(6,492)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(347)	(2,693)
CASH AND CASH EQUIVALENTS, beginning of year	564	2,841
CASH AND CASH EQUIVALENTS, end of period	217	148
Non-Guarantors
Schedule of Condensed Consolidating Statement of Cash Flows [Line Items]
Net cash (used in) provided by operating activities	3,699	1,875
Net cash used in investing activities	(340,366)	(4,484)
Net cash provided by (used in) financing activities	336,401	(306)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(266)	(2,915)
CASH AND CASH EQUIVALENTS, beginning of year	3,858	4,681
CASH AND CASH EQUIVALENTS, end of period	3,592	1,766
Eliminations
Schedule of Condensed Consolidating Statement of Cash Flows [Line Items]
Net cash used in investing activities	1,501	1,506
Net cash provided by (used in) financing activities	$ (1,501)	$ (1,506)

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Asset Retirement Obligation (Tables)

6 Months Ended

Jun. 30, 2011

Reconciliation of Carrying Amounts of Asset Retirement Obligation

A reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligation for the period from December 31, 2010 to June 30, 2011 is as follows (in thousands):

Asset retirement obligation, December 31, 2010	$	119,877
Liability incurred upon acquiring and drilling wells		2,702
Sales of reserves in place		(6,855	)
Liability settled in current period		(1,370	)
Accretion of discount expense		4,786
Asset retirement obligation, June 30, 2011		119,140
Less: current portion		25,360
Asset retirement obligation, net of current	$	93,780

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Other Assets

6 Months Ended

Jun. 30, 2011

Other Assets

7. Other Assets

Other assets consist of the following (in thousands):

	June 30, 2011		December 31, 2010
Debt issuance costs, net of amortization	$	56,662	$	50,637
Investments		4,908		4,826
Other		10,384		4,288
Total other assets	$	71,954	$	59,751

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Property, Plant and Equipment - Additional Information (Detail) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Property, Plant and Equipment [Line Items]
Cumulative full cost ceiling limitation impairment charges	$ 3,548.3	$ 3,548.3

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income	$ (79,167)	$ 82,986
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Provision for doubtful accounts	1,596	84
Inventory obsolescence	20	124
Depreciation, depletion and amortization	176,440	130,720
Debt issuance costs amortization	5,748	5,121
Discount amortization on long-term debt	1,162	1,049
Loss on extinguishment of debt	38,232
Deferred income taxes	(6,986)
Unrealized loss (gain) on derivative contracts	79,350	(12,776)
(Gain) loss on sale of assets	(725)	84
Investment (income) loss	(67)	261
Stock-based compensation	18,301	14,218
Changes in operating assets and liabilities	27,100	36,588
Net cash provided by operating activities	261,004	258,459
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment	(871,901)	(427,336)
Proceeds from sale of assets	369,251	6,042
Refunds of restricted deposits		5,095
Net cash used in investing activities	(502,650)	(416,199)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings	1,725,000	841,914
Repayments of borrowings	(1,741,795)	(662,869)
Premium on debt redemption	(30,338)
Debt issuance costs	(19,640)	(11,546)
Proceeds from issuance of units by SandRidge Mississippian Trust I	336,892
Noncontrolling interest distributions	(1,501)	(1,506)
Noncontrolling interest contributions		157
Stock issuance expense	(231)	(87)
Stock-based compensation excess tax benefit	7	14
Purchase of treasury stock	(6,030)	(2,852)
Dividends paid - preferred	(28,980)	(11,263)
Derivative settlements	7,014
Net cash provided by financing activities	240,398	151,962
NET DECREASE IN CASH AND CASH EQUIVALENTS	(1,248)	(5,778)
CASH AND CASH EQUIVALENTS, beginning of year	5,863	7,861
CASH AND CASH EQUIVALENTS, end of period	4,615	2,083
Supplemental Disclosure of Noncash Investing and Financing Activities
Change in accrued capital expenditures	2,351	50,209
Convertible perpetual preferred stock dividends payable	16,572	14,447
Adjustment to oil and natural gas properties for estimated contract loss	$ 19,000

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Condensed Consolidating Balance Sheets of SandRidge Energy, Inc. and Wholly Owned Subsidiary Guarantors and Non-Guarantors (Detail) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010	Jun. 30, 2010	Dec. 31, 2009
Current assets
Cash and cash equivalents	$ 4,615	$ 5,863	$ 2,083	$ 7,861
Accounts and notes receivable, net	162,976	146,118
Derivative contracts	2,513	5,028
Other current assets	20,468	18,581
Total current assets	190,572	175,590
Property, plant and equipment, net	5,070,850	4,733,865
Goodwill	235,396	234,356
Other assets	99,856	87,637
Total assets	5,596,674	5,231,448
Current liabilities
Accounts payable and accrued expenses	423,971	376,922
Derivative contracts	149,374	103,409
Asset retirement obligation	25,360	25,360
Other current liabilities	42,251	38,767
Total current liabilities	640,956	544,458
Long-term debt	2,892,434	2,901,793
Derivative contracts	162,057	124,173
Asset retirement obligation	93,780	94,517
Other liabilities	10,762	19,024
Total liabilities	3,799,989	3,683,965
Equity	1,796,685	1,547,483
Total liabilities and equity	5,596,674	5,231,448
Parent Company
Current assets
Cash and cash equivalents	806	1,441	169	339
Accounts and notes receivable, net	1,107,468	1,224,500
Total current assets	1,108,274	1,225,941
Investment in subsidiaries	3,289,504	3,230,067
Other assets	56,662	50,637
Total assets	4,454,440	4,506,645
Current liabilities
Accounts payable and accrued expenses	123,862	66,539
Derivative contracts	9,552	9,007
Total current liabilities	133,414	75,546
Long-term debt	2,876,925	2,885,764
Derivative contracts	5,734	7,687
Other liabilities	1,523	1,454
Total liabilities	3,017,596	2,970,451
Equity	1,436,844	1,536,194
Total liabilities and equity	4,454,440	4,506,645
Guarantor Subsidiaries
Current assets
Cash and cash equivalents	217	564	148	2,841
Accounts and notes receivable, net	155,236	141,530
Derivative contracts	2,513	5,028
Other current assets	12,686	13,890
Total current assets	170,652	161,012
Property, plant and equipment, net	4,670,983	4,635,747
Investment in subsidiaries	50,925	69,995
Goodwill	235,396	234,356
Other assets	43,194	37,000
Total assets	5,171,150	5,138,110
Current liabilities
Accounts payable and accrued expenses	1,411,142	1,510,827
Derivative contracts	143,083	94,402
Asset retirement obligation	25,360	25,360
Other current liabilities	41,232	37,776
Total current liabilities	1,620,817	1,668,365
Derivative contracts	157,885	116,486
Asset retirement obligation	93,606	94,350
Other liabilities	9,239	17,570
Total liabilities	1,881,547	1,896,771
Equity	3,289,603	3,241,339
Total liabilities and equity	5,171,150	5,138,110
Non-Guarantors
Current assets
Cash and cash equivalents	3,592	3,858	1,766	4,681
Accounts and notes receivable, net	474,528	408,015
Derivative contracts	3,261
Other current assets	7,782	4,691
Total current assets	489,163	416,564
Property, plant and equipment, net	399,867	98,118
Other assets	1,562
Total assets	890,592	514,682
Current liabilities
Accounts payable and accrued expenses	463,223	427,483
Other current liabilities	1,019	991
Total current liabilities	464,242	428,474
Long-term debt	15,509	16,029
Asset retirement obligation	174	167
Total liabilities	479,925	444,670
Equity	410,667	70,012
Total liabilities and equity	890,592	514,682
Eliminations
Current assets
Accounts and notes receivable, net	(1,574,256)	(1,627,927)
Derivative contracts	(3,261)
Total current assets	(1,577,517)	(1,627,927)
Investment in subsidiaries	(3,340,429)	(3,300,062)
Other assets	(1,562)
Total assets	(4,919,508)	(4,927,989)
Current liabilities
Accounts payable and accrued expenses	(1,574,256)	(1,627,927)
Derivative contracts	(3,261)
Total current liabilities	(1,577,517)	(1,627,927)
Derivative contracts	(1,562)
Total liabilities	(1,579,079)	(1,627,927)
Equity	(3,340,429)	(3,300,062)
Total liabilities and equity	$ (4,919,508)	$ (4,927,989)

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Acquisitions and Divestitures

6 Months Ended

Jun. 30, 2011

Acquisitions and Divestitures

3. Acquisitions and Divestitures

Arena Acquisition. On July 16, 2010, the Company acquired all of the outstanding common stock of Arena Resources, Inc. (“Arena”). In connection with the acquisition (the “Arena Acquisition”), the Company issued 4.7771 shares of its common stock and paid $4.50 in cash to Arena stockholders for each outstanding share of Arena unrestricted common stock. This resulted in the issuance of approximately 190.3 million shares of Company common stock and payment of approximately $177.9 million in cash for an aggregate estimated purchase price to stockholders of Arena equal to approximately $1.4 billion. The Company incurred approximately $0.2 million and $3.8 million in fees related to the acquisition during the three-month periods ended June 30, 2011 and 2010, respectively, and $0.6 million and $4.8 million in fees during the six-month periods ended June 30, 2011 and 2010, respectively, which have been included in general and administrative expenses in the accompanying condensed consolidated statements of operations.

In the second quarter of 2011, the Company completed its valuation of assets acquired and liabilities assumed related to the Arena Acquisition. Upon receipt of final confirmatory information for certain accruals in the second quarter of 2011 and completion of the 2010 Arena federal income tax return, the Company increased current assets, the net deferred tax liability and the value assigned to goodwill and reduced current liabilities. The accompanying condensed consolidated balance sheet at December 31, 2010 included certain preliminary allocations of the purchase price for the Arena Acquisition. During the first quarter of 2011, the Company updated certain estimates used in the purchase price allocation, primarily with respect to accruals, resulting in adjustments of $0.8 million to goodwill. Additional adjustments in the second quarter of 2011, primarily with respect to deferred taxes and other accruals, resulted in adjustments of $0.2 million to goodwill.

The following table summarizes the final valuation of assets acquired and liabilities assumed in connection with the Arena Acquisition (in thousands):

Current assets	$	83,563
Oil and natural gas properties(1)		1,587,630
Other property, plant and equipment		5,963
Deferred tax assets		48,997
Other long-term assets		16,181
Goodwill(2)		235,396
Total assets acquired		1,977,730
Current liabilities		38,964
Long-term deferred tax liability(2)		503,483
Other long-term liabilities		8,851
Total liabilities assumed		551,298
Net assets acquired	$	1,426,432

(1) Weighted average commodity prices utilized in the preliminary determination of the fair value of oil and natural gas properties were $105.58 per barrel of oil and $8.56 per Mcf of natural gas, after adjustment for transportation fees and regional price differentials. The prices utilized were based upon forward commodity strip prices, as of July 16, 2010, for the first four years and escalated for inflation at a rate of 2.5% annually beginning with the fifth year through the end of production, which was more than 50 years. Approximately 91.0% of the fair value allocated to oil and natural gas properties is attributed to oil reserves.

(2) The Company received carryover tax basis in Arena’s assets and liabilities because the merger was not a taxable transaction under the Internal Revenue Code (“IRC”). Based upon the final purchase price allocation, a step-up in basis related to the property acquired from Arena resulted in a net deferred tax liability of approximately $454.5 million, which in turn contributed to an excess of the consideration transferred to acquire Arena over the estimated fair value on the acquisition date of the net assets acquired, or goodwill. See Note 6 for further discussion of goodwill and Note 13 for further discussion of the net deferred tax liability.

The following unaudited pro forma results of operations are provided for the three and six-month periods ended June 30, 2010 as though the Arena Acquisition had been completed as of the beginning of each respective period. The pro forma information is based on the Company’s consolidated results of operations for the three and six-month periods ended June 30, 2010, Arena’s historical results of operations and estimates of the effect of the transaction on the combined results. The pro forma combined results of operations for the three and six-month periods ended June 30, 2010 have been prepared by adjusting the historical results of the Company to include the historical results of Arena, certain reclassifications to conform Arena’s presentation to the Company’s accounting policies and the impact of the purchase price allocation. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted from the acquisition or any estimated costs that have been incurred by the Company to integrate Arena. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors.

	Three Months Ended June 30, 2010				Six Months Ended June 30, 2010
	Actual		Pro Forma		Actual		Pro Forma
	(in thousands, except per share data)
Revenues	$	182,439	$	236,751	$	393,434	$	499,544
Income available to SandRidge Energy, Inc. common stockholders(1)	$	44,884	$	503,597	$	63,489	$	536,985
Earnings per common share
Basic	$	0.22	$	1.28	$	0.31	$	1.36
Diluted	$	0.21	$	1.14	$	0.31	$	1.23

(1) Pro forma columns reflect a $454.5 million reduction in tax expense related to the release of a portion of the Company’s valuation allowance on existing deferred tax assets.

Sale of Wolfberry Assets. In January 2011, the Company sold its Wolfberry assets in the Permian Basin for $153.8 million, net of fees and subject to post-closing adjustments. This asset sale was accounted for as an adjustment to the full cost pool with no gain or loss recognized.

Sale of New Mexico Assets. In April 2011, the Company sold certain oil and natural gas properties in Lea County and Eddy County, New Mexico, for approximately $198.5 million, net of fees and subject to post-closing adjustments. This asset sale was accounted for as an adjustment to the full cost pool with no gain or loss recognized.

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Condensed Consolidating Financial Information (Tables)

6 Months Ended

Jun. 30, 2011

Condensed Consolidating Balance Sheets of SandRidge Energy, Inc. and Wholly Owned Subsidiary Guarantors

The following condensed consolidating financial information represents the financial information of SandRidge Energy, Inc., its wholly owned subsidiary guarantors and its non-guarantor subsidiaries, prepared on the equity basis of accounting. The non-guarantor subsidiaries and three variable interest entities are included in the non-guarantor column in the tables below. The financial information may not necessarily be indicative of the financial position, results of operations or cash flows had the subsidiary guarantors operated as independent entities.

Condensed Consolidating Balance Sheets

	June 30, 2011
	Parent		Guarantors		Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	806	$	217	$	3,592	$	—		$	4,615
Accounts and notes receivable, net		1,107,468		155,236		474,528		(1,574,256	)		162,976
Derivative contracts		—		2,513		3,261		(3,261	)		2,513
Other current assets		—		12,686		7,782		—			20,468
Total current assets		1,108,274		170,652		489,163		(1,577,517	)		190,572
Property, plant and equipment, net		—		4,670,983		399,867		—			5,070,850
Investment in subsidiaries		3,289,504		50,925		—		(3,340,429	)		—
Goodwill		—		235,396		—		—			235,396
Other assets		56,662		43,194		1,562		(1,562	)		99,856
Total assets	$	4,454,440	$	5,171,150	$	890,592	$	(4,919,508	)	$	5,596,674
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	123,862	$	1,411,142	$	463,223	$	(1,574,256	)	$	423,971
Derivative contracts		9,552		143,083		—		(3,261	)		149,374
Asset retirement obligation		—		25,360		—		—			25,360
Other current liabilities		—		41,232		1,019		—			42,251
Total current liabilities		133,414		1,620,817		464,242		(1,577,517	)		640,956
Long-term debt		2,876,925		—		15,509		—			2,892,434
Derivative contracts		5,734		157,885		—		(1,562	)		162,057
Asset retirement obligation		—		93,606		174		—			93,780
Other liabilities		1,523		9,239		—		—			10,762
Total liabilities		3,017,596		1,881,547		479,925		(1,579,079	)		3,799,989
Equity		1,436,844		3,289,603		410,667		(3,340,429	)		1,796,685
Total liabilities and equity	$	4,454,440	$	5,171,150	$	890,592	$	(4,919,508	)	$	5,596,674

	December 31, 2010
	Parent		Guarantors		Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	1,441	$	564	$	3,858	$	—		$	5,863
Accounts and notes receivable, net		1,224,500		141,530		408,015		(1,627,927	)		146,118
Derivative contracts		—		5,028		—		—			5,028
Other current assets		—		13,890		4,691		—			18,581
Total current assets		1,225,941		161,012		416,564		(1,627,927	)		175,590
Property, plant and equipment, net		—		4,635,747		98,118		—			4,733,865
Investment in subsidiaries		3,230,067		69,995		—		(3,300,062	)		—
Goodwill		—		234,356		—		—			234,356
Other assets		50,637		37,000		—		—			87,637
Total assets	$	4,506,645	$	5,138,110	$	514,682	$	(4,927,989	)	$	5,231,448
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	66,539	$	1,510,827	$	427,483	$	(1,627,927	)	$	376,922
Derivative contracts		9,007		94,402		—		—			103,409
Asset retirement obligation		—		25,360		—		—			25,360
Other current liabilities		—		37,776		991		—			38,767
Total current liabilities		75,546		1,668,365		428,474		(1,627,927	)		544,458
Long-term debt		2,885,764		—		16,029		—			2,901,793
Derivative contracts		7,687		116,486		—		—			124,173
Asset retirement obligation		—		94,350		167		—			94,517
Other liabilities		1,454		17,570		—		—			19,024
Total liabilities		2,970,451		1,896,771		444,670		(1,627,927	)		3,683,965
Equity		1,536,194		3,241,339		70,012		(3,300,062	)		1,547,483
Total liabilities and equity	$	4,506,645	$	5,138,110	$	514,682	$	(4,927,989	)	$	5,231,448

Condensed Consolidating Statements of Operations of SandRidge Energy, Inc. and Wholly Owned Subsidiary Guarantors

Condensed Consolidating Statements of Operations

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Three Months Ended June 30, 2011
Total revenues	$	—		$	341,481		$	56,289		$	(32,996	)	$	364,774
Expenses
Direct operating expenses		—			122,389			38,260			(32,742	)		127,907
General and administrative		104			36,608			1,220			(254	)		37,678
Depreciation, depletion, amortization and impairment		—			83,413			6,048			—			89,461
Gain on derivative contracts		—			(160,387	)		(9,601	)		—			(169,988	)
Total expenses		104			82,023			35,927			(32,996	)		85,058
(Loss) income from operations		(104	)		259,458			20,362			—			279,716
Equity earnings from subsidiaries		266,425			6,950			—			(273,375	)		—
Interest expense, net		(61,308	)		(121	)		(258	)		—			(61,687	)
Loss on extinguishment of debt		(2,051	)		—			—			—			(2,051	)
Other income, net		—			138			—			—			138
Income before income taxes		202,962			266,425			20,104			(273,375	)		216,116
Income tax benefit		(7,054	)		—			—			—			(7,054	)
Net income		210,016			266,425			20,104			(273,375	)		223,170
Less: net income attributable to noncontrolling interest		—			—			13,154			—			13,154
Net income attributable to SandRidge Energy, Inc.	$	210,016		$	266,425		$	6,950		$	(273,375	)	$	210,016
Three Months Ended June 30, 2010
Total revenues	$	—		$	174,404		$	27,357		$	(19,322	)	$	182,439
Expenses
Direct operating expenses		—			80,214			21,506			(19,116	)		82,604
General and administrative		86			32,861			1,124			(206	)		33,865
Depreciation, depletion, amortization and impairment		—			64,444			1,695			—			66,139
Gain on derivative contracts		—			(119,621	)		—			—			(119,621	)
Total expenses		86			57,898			24,325			(19,322	)		62,987
(Loss) income from operations		(86	)		116,506			3,032			—			119,452
Equity earnings from subsidiaries		117,094			1,544			—			(118,638	)		—
Interest expense, net		(63,594	)		(295	)		(272	)		—			(64,161	)
Other expense (income), net		73			(661	)		58			—			(530	)
Income before income taxes		53,487			117,094			2,818			(118,638	)		54,761
Income tax (benefit) expense		(28	)		—			178			—			150
Net income		53,515			117,094			2,640			(118,638	)		54,611
Less: net income attributable to noncontrolling interest		—			—			1,096			—			1,096
Net income attributable to SandRidge Energy, Inc.	$	53,515		$	117,094		$	1,544		$	(118,638	)	$	53,515

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Six Months Ended June 30, 2011
Total revenues	$	—		$	650,777		$	70,770		$	(43,926	)	$	677,621
Expenses
Direct operating expenses		—			241,617			51,472			(43,526	)		249,563
General and administrative		189			70,342			1,960			(400	)		72,091
Depreciation, depletion, amortization and impairment		—			168,652			7,788			—			176,440
(Loss) gain on derivative contracts		—			117,241			(9,601	)		—			107,640
Total expenses		189			597,852			51,619			(43,926	)		605,734
(Loss) income from operations		(189	)		52,925			19,151			—			71,887
Equity earnings from subsidiaries		59,437			5,712			—			(65,149	)		—
Interest expense, net		(120,315	)		(293	)		(516	)		—			(121,124	)
Loss on extinguishment of debt		(38,232	)		—			—			—			(38,232	)
Other income, net		—			1,093			242			—			1,335
(Loss) income before income taxes		(99,299	)		59,437			18,877			(65,149	)		(86,134	)
Income tax (benefit) expense		(6,971	)		—			4			—			(6,967	)
Net (loss) income		(92,328	)		59,437			18,873			(65,149	)		(79,167	)
Less: net income attributable to noncontrolling interest		—			—			13,161			—			13,161
Net (loss) income attributable to SandRidge Energy, Inc.	$	(92,328	)	$	59,437		$	5,712		$	(65,149	)	$	(92,328	)
Six Months Ended June 30, 2010
Total revenues	$	—		$	373,688		$	90,633		$	(70,887	)	$	393,434
Expenses
Direct operating expenses		—			162,856			77,744			(70,475	)		170,125
General and administrative		163			63,830			1,958			(412	)		65,539
Depreciation, depletion, amortization and impairment		—			127,369			3,351			—			130,720
Gain on derivative contracts		—			(181,573	)		—			—			(181,573	)
Total expenses		163			172,482			83,053			(70,887	)		184,811
(Loss) income from operations		(163	)		201,206			7,580			—			208,623
Equity earnings from subsidiaries		205,795			4,679			—			(210,474	)		—
Interest expense, net		(124,970	)		(666	)		(545	)		—			(126,181	)
Other income, net		74			576			56			—			706
Income before income taxes		80,736			205,795			7,091			(210,474	)		83,148
Income tax (benefit) expense		(16	)		—			178			—			162
Net income		80,752			205,795			6,913			(210,474	)		82,986
Less: net income attributable to noncontrolling interest		—			—			2,234			—			2,234
Net income attributable to SandRidge Energy, Inc.	$	80,752		$	205,795		$	4,679		$	(210,474	)	$	80,752

Condensed Consolidating Statements of Cash Flows of SandRidge Energy, Inc. and Wholly Owned Subsidiary Guarantors

Condensed Consolidating Statements of Cash Flows

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Six Months Ended June 30, 2011
Net cash provided by (used in) operating activities	$	94,579		$	162,726		$	3,699		$	—		$	261,004
Net cash used in investing activities		—			(163,785	)		(340,366	)		1,501			(502,650	)
Net cash (used in) provided by financing activities		(95,214	)		712			336,401			(1,501	)		240,398
Net (decrease) increase in cash and cash equivalents		(635	)		(347	)		(266	)		—			(1,248	)
Cash and cash equivalents at beginning of year		1,441			564			3,858			—			5,863
Cash and cash equivalents at end of period	$	806		$	217		$	3,592		$	—		$	4,615
Six Months Ended June 30, 2010
Net cash (used in) provided by operating activities	$	(160,436	)	$	417,020		$	1,875		$	—		$	258,459
Net cash used in investing activities		—			(413,221	)		(4,484	)		1,506			(416,199	)
Net cash provided by (used in) financing activities		160,266			(6,492	)		(306	)		(1,506	)		151,962
Net decrease in cash and cash equivalents		(170	)		(2,693	)		(2,915	)		—			(5,778	)
Cash and cash equivalents at beginning of year		339			2,841			4,681			—			7,861
Cash and cash equivalents at end of period	$	169		$	148		$	1,766		$	—		$	2,083

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Variable Interest Entities (Tables)

6 Months Ended

Jun. 30, 2011

Open Oil and Natural Gas Commodity Derivative Contracts - Sand Ridge Mississippian Trust I

The tables below present open oil and natural gas commodity derivative contracts at June 30, 2011, the benefits and obligations of which will be passed to the Mississippian Trust under the derivatives agreement. See Note 12 for further discussion of the derivatives agreement between the Company and the Mississippian Trust and a complete listing of the Company’s open commodity derivative contracts at June 30, 2011, including the derivative contracts the effects of which have been conveyed to the Mississippian Trust.

Oil

Period and Type of Contract	Notional (MBbl)		Weighted Avg. Fixed Price
July 2011 — December 2011
Price swap contracts		241	$	103.60
January 2012 — December 2012
Price swap contracts		454	$	104.15
January 2013 — December 2013
Price swap contracts		488	$	102.07
January 2014 — December 2014
Price swap contracts		541	$	100.94
January 2015 — December 2015
Price swap contracts		468	$	101.07

Natural Gas

Period and Type of Contract	Notional (MMcf)(1)		Weighted Avg. Fixed Price		Collar Range
July 2011 — December 2011
Price swap contracts		2,086	$	4.61		—
January 2012 — June 2012
Price swap contracts		2,190	$	4.90		—
July 2012 — December 2012
Collars		402		—	$	4.00 - $6.20
January 2013 — December 2013
Collars		858		—	$	4.00 - $7.15
January 2014 — December 2014
Collars		937		—	$	4.00 - $7.78
January 2015 — December 2015
Collars		1,010		—	$	4.00 - $8.55

(1) Assumes ratio of 1:1 for Mcf to MMBtu.

Sand Ridge Mississippian Trust I

Assets and Liabilities Included in the Condensed Consolidated Balance Sheet

The Mississippian Trust’s assets and liabilities included in the accompanying condensed consolidated balance sheet at June 30, 2011 consisted of the following (in thousands):

Current assets	$	6,570
Investment in royalty interests, net(1)		304,656
Total assets	$	311,226
Current liabilities	$	651
Total liabilities	$	651

(1) Included in oil and natural gas properties on the condensed consolidated balance sheet.

Grey Ranch, L.P.

Assets and Liabilities Included in the Condensed Consolidated Balance Sheet

GRLP’s assets and liabilities included in the accompanying condensed consolidated balance sheets at June 30, 2011 and December 31, 2010 consisted of the following (in thousands):

	June 30,		December 31,
	2011		2010
Current assets	$	3,719	$	8,215
Other property, plant and equipment, net		15,560		16,079
Total assets	$	19,279	$	24,294
Current liabilities	$	318	$	1,751
Total liabilities	$	318	$	1,751

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Assets and Liabilities Included in the Condensed Consolidated Balance Sheet, SandRidge Mississippian Trust I (Detail) (Sand Ridge Mississippian Trust I, USD $) In Thousands	Jun. 30, 2011
Variable Interest Entity [Line Items]
Assets of Trust	$ 311,226
Liabilities of Trust	651
Current Assets
Variable Interest Entity [Line Items]
Assets of Trust	6,570
Investment in royalty interests, net
Variable Interest Entity [Line Items]
Assets of Trust	304,656	[1]
Current Liabilities
Variable Interest Entity [Line Items]
Liabilities of Trust	$ 651

[1] Included in oil and natural gas properties on the condensed consolidated balance sheet.

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Century Plant Contract - Additional Information (Detail) (USD $)	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2011	Jun. 30, 2011	Dec. 31, 2010
Construction Agreement		The Company is constructing the Century Plant, a CO2 treatment plant in Pecos County, Texas (the “Century Plant”), and associated compression and pipeline facilities pursuant to an agreement with Occidental Petroleum Corporation (“Occidental”). Under the terms of the agreement, the Company will construct the Century Plant and Occidental will pay the Company a minimum of 100% of the contract price, or $800.0 million, plus any subsequently agreed-upon revisions, through periodic cost reimbursements based upon the percentage of the project completed by the Company. The Company expects to complete the Century Plant in two phases. Upon completion of each phase of the Century Plant, Occidental will take ownership of the related assets and will operate the Century Plant for the purpose of separating and removing CO2 from delivered natural gas. Phase I is in the commissioning process with completion and transfer of title to Occidental expected in mid 2011, and Phase II is under construction and expected to be completed in mid 2012. Pursuant to a 30-year treating agreement executed simultaneously with the construction agreement, Occidental will remove CO2 from the Company’s delivered production volumes. The Company will retain all methane gas from the natural gas it delivers to the Century Plant.
Construction of Century Plant, contract price		$ 800,000,000
Estimated loss identified based on projections of the costs to be incurred in excess of contract amounts, total		124,000,000
Estimated loss identified based on projections of the costs to be incurred in excess of contract amounts, during period	19,000,000		105,000,000
Billings and estimated contract loss in excess of costs incurred		$ 41,232,000	$ 31,474,000

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Property, Plant and Equipment (Parenthetical) (Detail) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Property, Plant and Equipment [Line Items]
Non oil and natural gas equipment, Capitalized Interest	$ 5.2	$ 4.7

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Long-Term Debt - Additional Information (Detail) (USD $)	3 Months Ended		6 Months Ended			3 Months Ended	6 Months Ended							3 Months Ended		6 Months Ended										1 Months Ended		3 Months Ended	6 Months Ended		3 Months Ended		6 Months Ended				6 Months Ended		6 Months Ended		6 Months Ended		1 Months Ended	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010	Jun. 30, 2011 8.625% Senior Notes due 2015	Jun. 30, 2011 8.625% Senior Notes due 2015	Mar. 31, 2011 8.625% Senior Notes due 2015	Mar. 01, 2011 8.625% Senior Notes due 2015	Dec. 31, 2010 8.625% Senior Notes due 2015	Mar. 31, 2011 8.625% Senior Notes due 2015 Tendered by March 14, 2011	Mar. 31, 2011 8.625% Senior Notes due 2015 Tendered After March 14, 2011	Jun. 30, 2011 8.625% Senior Notes due 2015 Note Redeemed On April 1, 2011	Jun. 30, 2011 Senior credit facility	Jun. 30, 2010 Senior credit facility	Jun. 30, 2011 Senior credit facility	Jun. 30, 2010 Senior credit facility	Mar. 15, 2011 Senior credit facility	Dec. 31, 2010 Senior credit facility	Jun. 30, 2011 Senior credit facility LIBOR	Jun. 30, 2011 Senior credit facility Euro Dollar Rate	Jun. 30, 2011 Senior credit facility Secured Debt	Jun. 30, 2011 Senior credit facility Secured Debt Lower Limit	Feb. 23, 2011 Senior credit facility Upper Limit	Jun. 30, 2011 Senior credit facility Lower Limit	Mar. 31, 2011 Other notes payable Drilling Rig Fleet and Related Oil Field Services Equipment Note	Dec. 31, 2010 Other notes payable Drilling Rig Fleet and Related Oil Field Services Equipment Note	Jun. 30, 2011 Other notes payable Mortgage	Jun. 30, 2011 Other notes payable Mortgage	Dec. 31, 2010 Other notes payable Mortgage	Jun. 30, 2011 Senior Floating Rate Notes due 2014	Jun. 30, 2010 Senior Floating Rate Notes due 2014	Jun. 30, 2011 Senior Floating Rate Notes due 2014	Jun. 30, 2010 Senior Floating Rate Notes due 2014	Dec. 31, 2010 Senior Floating Rate Notes due 2014	Jun. 30, 2011 Senior Floating Rate Notes due 2014 Fixed to Floating Interest Rate Swap Through April 1st 2013	Jun. 30, 2011 9.875% Senior Notes due 2016	Dec. 31, 2010 9.875% Senior Notes due 2016	Jun. 30, 2011 8.0% Senior Notes due 2018	Dec. 31, 2010 8.0% Senior Notes due 2018	Jun. 30, 2011 8.75% Senior Notes due 2020	Dec. 31, 2010 8.75% Senior Notes due 2020	Mar. 31, 2011 Senior Notes 7.5 Percent Due 2021	Jun. 30, 2011 Senior Notes 7.5 Percent Due 2021
Debt Disclosure [Line Items]
Accrued interest paid in connection with redemption of notes	$ 56,900,000	$ 83,300,000	$ 110,300,000	$ 92,300,000		$ 1,500,000	$ 25,700,000
Long-term debt, maturity date																2014-04-15
Long-term debt, amendment description																On February 23, 2011, the senior credit facility was amended to, among other things, (a) exclude from the calculation of Consolidated Net Income the net income (or loss) of a Royalty Trust, except to the extent of cash distributions received by the Company, (b) establish that an investment in a Royalty Trust and dispositions to, and of interests in, Royalty Trusts are permitted, (c) clarify that a Royalty Trust is not a Subsidiary, (d) allow the Company to net against its calculation of Consolidated Funded Indebtedness cash balances exceeding $10.0 million in the event no loans are outstanding under the senior credit facility at that time, and (e) establish that, for any fiscal quarter ending prior to March 31, 2012, if the ratio of the Company’s secured indebtedness to EBITDA is less than 1.5:1.0 then compliance with the Company’s Consolidated Leverage Ratio covenant is not required. Terms capitalized in the preceding sentence have the meaning given to them in the senior credit facility, as amended.
Long-term debt, interest rate determination reference																(a) the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 2.00% and 3.00% per annum or (b) the “base rate,” which is the highest of (i) the federal funds rate plus 0.5%, (ii) the prime rate published by Bank of America or (iii) the Eurodollar rate (as defined in the senior credit facility) plus 1.00% per annum, plus, in each case under scenario (b), an applicable margin between 1.00% and 2.00% per annum. Interest is payable quarterly for base rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest is paid at the end of each three-month period.
Long-term debt, interest rate in addition to federal funds rate																0.50%
Long-term debt, senior secured leverage ratio																								1.5
Long-term debt, financial covenants			As of June 30, 2011, the senior credit facility contained financial covenants, including maintaining agreed levels for the (i) ratio of total funded debt to EBITDA, which may not exceed 4.5:1.0 at each quarter end, calculated using the last four completed fiscal quarters, unless, for any quarter ending prior to March 31, 2012, the ratio of the Company’s secured indebtedness to EBITDA is less than 1.5:1.0, calculated using the last four completed fiscal quarters (in each case through the second quarter of 2011, adjusted for annualized amounts of the post-acquisition results of operations of Arena), (ii) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at each quarter end (in the current ratio calculation (as defined in the senior credit facility), any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on the Company’s derivative contracts are disregarded) and (iii) ratio of the Company’s secured indebtedness to EBITDA, which may not exceed 2.0:1.0 at each quarter end, calculated using the last four completed fiscal quarters (in each case through the second quarter of 2011, adjusted for annualized amounts of the post-acquisition results of operations of Arena).
Long-term debt, financial covenants compliance																As of and during the three and six-month periods ended June 30, 2011, the Company was in compliance with all of the financial covenants under the senior credit facility.
Long-term debt, debt to EBITDA ratio maximum														4.5		4.5						2.0
Long-term debt, debt to EBITDA ratio minimum																							1.5
Long-term debt, ratio of current assets to current liabilities																									1
Long-term debt, guarantee																	The obligations under the senior credit facility are guaranteed by certain Company subsidiaries and are secured by first priority liens on all shares of capital stock of each of the Company’s material present and future subsidiaries; all intercompany debt of the Company; and substantially all of the Company’s assets, including proved oil and natural gas reserves representing at least 80% of the discounted present value (as defined in the senior credit facility) of proved oil and natural gas reserves considered by the lenders in determining the borrowing base for the senior credit facility.
Long-term debt, interest rate, minimum applicable margin														1.00%		1.00%				2.00%
Long-term debt, interest rate, maximum applicable margin														2.00%		2.00%				3.00%
Long-term debt, interest rate, applicable margin																					1.00%
Long-term debt, issuance date							May, 2008																										May, 2008				May, 2009		May, 2008		December, 2009
Senior Notes issued																																											900,000,000
Long-term debt, annual interest rates																												6.08%	6.08%
Long-term debt, interest rate																																	LIBOR plus 3.625%
Net proceeds from Senior Notes issued																																											880,700,000
Long-term debt, maturity date																													Nov. 15, 2022				Apr. 01, 2014				May 15, 2016		Jun. 01, 2018		Jan. 15, 2020			Mar. 15, 2021
Long-term debt, average annual interest rate														2.51%	2.65%	2.70%	2.52%														3.93%	3.92%	3.93%	3.90%
Long-term debt, borrowing base																		850,000,000
Long-term debt, amended borrowing base																		790,000,000
Long-term debt, additional costs as a result of amendments to the credit agreement and changes to the borrowing base														300,000		300,000
Debt	2,893,453,000		2,893,453,000		2,909,086,000					650,000,000				80,000,000		80,000,000			340,000,000								6,302,000	16,527,000	16,527,000	17,020,000	350,000,000		350,000,000		350,000,000		353,619,000	352,707,000	750,000,000	750,000,000	443,307,000	443,057,000		900,000,000
Letters of credit, outstanding	24,500,000		24,500,000
Other Notes Payable, principal balance paid																										4,300,000
Long-term debt, installment of principal and interest																												500,000
Long-term debt, notional interest rate swap to fix variable interest rate																															350,000,000		350,000,000
Long-term debt, notional interest rate swap to fix variable interest rate																																				6.69%
Aggregate senior notes outstanding principal amount									650,000,000
Cash tender to purchase outstanding aggregate principal amount, total consideration per $1,000 principal amount											1,046.88	1,016.88	1,043.13
Aggregate senior notes outstanding principal amount purchased								614,200,000					35,800,000
Aggregate senior notes outstanding principal amount, redemption date													Apr. 01, 2011
Loss on extinguishment of debt	(2,051,000)		(38,232,000)			2,000,000	38,200,000
Debt issuance costs																															$ 9,400,000		$ 9,400,000				$ 7,900,000		$ 16,000,000		$ 9,700,000		$ 19,300,000

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Fair Value Measurements

6 Months Ended

Jun. 30, 2011

Fair Value Measurements

4. Fair Value Measurements

The Company applies the guidance provided under ASC Topic 820 to its financial assets and liabilities and nonfinancial liabilities that are measured and reported on a fair value basis. Pursuant to this guidance, the Company has classified and disclosed its fair value measurements using the following levels of the fair value hierarchy:

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.

Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3: Measurement based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable for objective sources (i.e., supported by little or no market activity).

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels as described in ASC Topic 820. The determination of the fair values, stated below, takes into account the market for the Company’s financial assets and liabilities, the associated credit risk and other factors as required by ASC Topic 820. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company has assets and liabilities it has classified as Level 1 and Level 3, as described below. The Company did not have any assets or liabilities classified as Level 2 at June 30, 2011 or December 31, 2010.

Level 1 Fair Value Measurements

Restricted deposits. The fair value of restricted deposits invested in mutual funds or municipal bonds is based on quoted market prices. For restricted deposits held in savings accounts, carrying value is deemed to approximate fair value.

Other long-term assets. The fair value of other long-term assets, consisting of assets attributable to the Company’s deferred compensation plan, is based on quoted market prices.

Level 3 Fair Value Measurements

Derivative Contracts. The fair values of the Company’s oil and natural gas fixed price swaps, natural gas basis swaps, natural gas collars and interest rate swap are based upon quotes obtained from counterparties to the derivative contracts. The Company reviews other readily available market prices for its derivative contracts as there is an active market for these contracts. However, the Company does not have access to the specific valuation models used by its counterparties or other market participants. Included in these models are discount factors that the Company must estimate in its calculation. Additionally, the Company applies a weighted average credit default risk rating factor for its counterparties or gives effect to its credit risk, as applicable, in determining the fair value of its derivative contracts. Based on the inputs for the fair value measurement, the Company has classified its derivative contract assets and liabilities as Level 3.

The following tables summarize the Company’s financial assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy (in thousands):

June 30, 2011

	Fair Value Measurements						Netting(1)			Assets / Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Restricted deposits	$	27,902	$	—	$	—	$	—		$	27,902
Other long-term assets		4,908		—		—		—			4,908
Commodity derivative contracts		—		—		12,246		(9,733	)		2,513
	$	32,810	$	—	$	12,246	$	(9,733	)	$	35,323
Liabilities
Commodity derivative contracts	$	—	$	—	$	305,879	$	(9,733	)	$	296,146
Interest rate swap		—		—		15,285		—			15,285
	$	—	$	—	$	321,164	$	(9,733	)	$	311,431
December 31, 2010
	Fair Value Measurements						Netting(1)			Assets / Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Restricted deposits	$	27,886	$	—	$	—	$	—		$	27,886
Other long-term assets		4,826		—		—		—			4,826
Commodity derivative contracts		—		—		10,576		(5,548	)		5,028
	$	32,712	$	—	$	10,576	$	(5,548	)	$	37,740
Liabilities
Commodity derivative contracts	$	—	$	—	$	216,436	$	(5,548	)	$	210,888
Interest rate swaps		—		—		16,694		—			16,694
	$	—	$	—	$	233,130	$	(5,548	)	$	227,582

(1) Represents the impact of netting assets and liabilities with counterparties with which the right of offset exists.

The tables below set forth a reconciliation of the Company’s financial assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three and six-month periods ended June 30, 2011 and 2010 (in thousands):

	Three Months Ended June 30,
	2011									2010
	Commodity Derivative Contracts			Interest Rate Swaps			Total			Commodity Derivative Contracts			Interest Rate Swaps			Total
Balance of Level 3, March 31	$	(478,541	)	$	(14,929	)	$	(493,470	)	$	65,512		$	(12,147	)	$	53,365
Total realized and unrealized gains (losses)		169,988			(2,798	)		167,190			119,621			(6,477	)		113,144
Purchases		(3,353	)		—			(3,353	)		—			—			—
Settlements		18,273			2,442			20,715			(117,955	)		2,076			(115,879	)
Balance of Level 3, June 30	$	(293,633	)	$	(15,285	)	$	(308,918	)	$	67,178		$	(16,548	)	$	50,630

	Six Months Ended June 30,
	2011									2010
	Commodity Derivative Contracts			Interest Rate Swaps			Total			Commodity Derivative Contracts			Interest Rate Swaps			Total
Balance of Level 3, December 31	$	(205,860	)	$	(16,694	)	$	(222,554	)	$	46,153		$	(8,299	)	$	37,854
Total realized and unrealized (losses) gains		(107,640	)		(3,076	)		(110,716	)		181,573			(12,412	)		169,161
Purchases		(7,014	)		—			(7,014	)		—			—			—
Settlements		26,881			4,485			31,366			(160,548	)		4,163			(156,385	)
Balance of Level 3, June 30	$	(293,633	)	$	(15,285	)	$	(308,918	)	$	67,178		$	(16,548	)	$	50,630

During the three and six-month periods ended June 30, 2011 and 2010, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements.

See Note 12 for further discussion of the Company’s derivative contracts.

Fair Value of Debt

The Company measures the fair value of its long-term debt based on quoted market prices and also considers the effect of the Company’s credit risk. The estimated fair values of the Company’s senior notes and the carrying value at June 30, 2011 and December 31, 2010 were as follows (in thousands):

	June 30, 2011				December 31, 2010
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Floating Rate Notes due 2014	$	349,127	$	350,000	$	334,751	$	350,000
8.625% Senior Notes due 2015		—		—		663,181		650,000
9.875% Senior Notes due 2016(1)		406,146		353,619		394,527		352,707
8.0% Senior Notes due 2018		763,636		750,000		762,849		750,000
8.75% Senior Notes due 2020(2)		479,767		443,307		472,968		443,057
7.5% Senior Notes due 2021		909,203		900,000		—		—

(1) Carrying value is net of $11,881 and $12,793 discount at June 30, 2011 and December 31, 2010, respectively.

(2) Carrying value is net of $6,693 and $6,943 discount at June 30, 2011 and December 31, 2010, respectively.

The carrying values of the Company’s senior credit facility and remaining fixed rate debt instruments approximate fair value based on current rates applicable to similar instruments. See Note 11 for discussion of the Company’s long-term debt, including the purchase and redemption of all outstanding 8.625% Senior Notes due 2015 and the issuance of the 7.5% Senior Notes due 2021, which both occurred during 2011.

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Preferred Stock (Detail)	Jun. 30, 2011	Dec. 31, 2010
Stockholders Equity Note [Line Items]
Preferred stock, shares authorized	50,000,000	50,000,000
Preferred stock, shares outstanding	7,650,000	7,650,000
8.5% Convertible perpetual preferred stock
Stockholders Equity Note [Line Items]
Preferred stock, shares outstanding	2,650,000	2,650,000
6.0% Convertible perpetual preferred stock
Stockholders Equity Note [Line Items]
Preferred stock, shares outstanding	2,000,000	2,000,000
7.0% Convertible perpetual preferred stock
Stockholders Equity Note [Line Items]
Preferred stock, shares outstanding	3,000,000	3,000,000

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Final Valuation of Assets Acquired and Liabilities Assumed in Connection with Arena Acquisition (Detail) (USD $) In Thousands	Jun. 30, 2011
Business Acquisition, Contingent Consideration [Line Items]
Current assets	$ 83,563
Oil and natural gas properties	1,587,630	[1]
Other property, plant and equipment	5,963
Deferred tax assets	48,997
Other long-term assets	16,181
Goodwill	235,396	[2]
Total assets acquired	1,977,730
Current liabilities	38,964
Long-term deferred tax liability	503,483	[2]
Other long-term liabilities	8,851
Total liabilities assumed	551,298
Net assets acquired	$ 1,426,432

[1] Weighted average commodity prices utilized in the preliminary determination of the fair value of oil and natural gas properties were $105.58 per barrel of oil and $8.56 per Mcf of natural gas, after adjustment for transportation fees and regional price differentials. The prices utilized were based upon forward commodity strip prices, as of July 16, 2010, for the first four years and escalated for inflation at a rate of 2.5% annually beginning with the fifth year through the end of production, which was more than 50 years. Approximately 91.0% of the fair value allocated to oil and natural gas properties is attributed to oil reserves.

[2] The Company received carryover tax basis in Arena's assets and liabilities because the merger was not a taxable transaction under the Internal Revenue Code ("IRC"). Based upon the final purchase price allocation, a step-up in basis related to the property acquired from Arena resulted in a net deferred tax liability of approximately $454.5 million, which in turn contributed to an excess of the consideration transferred to acquire Arena over the estimated fair value on the acquisition date of the net assets acquired, or goodwill. See Note 6 for further discussion of goodwill and Note 13 for further discussion of the net deferred tax liability.

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2011

Financial Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables summarize the Company’s financial assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy (in thousands):

June 30, 2011

	Fair Value Measurements						Netting(1)			Assets / Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Restricted deposits	$	27,902	$	—	$	—	$	—		$	27,902
Other long-term assets		4,908		—		—		—			4,908
Commodity derivative contracts		—		—		12,246		(9,733	)		2,513
	$	32,810	$	—	$	12,246	$	(9,733	)	$	35,323
Liabilities
Commodity derivative contracts	$	—	$	—	$	305,879	$	(9,733	)	$	296,146
Interest rate swap		—		—		15,285		—			15,285
	$	—	$	—	$	321,164	$	(9,733	)	$	311,431
December 31, 2010
	Fair Value Measurements						Netting(1)			Assets / Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Restricted deposits	$	27,886	$	—	$	—	$	—		$	27,886
Other long-term assets		4,826		—		—		—			4,826
Commodity derivative contracts		—		—		10,576		(5,548	)		5,028
	$	32,712	$	—	$	10,576	$	(5,548	)	$	37,740
Liabilities
Commodity derivative contracts	$	—	$	—	$	216,436	$	(5,548	)	$	210,888
Interest rate swaps		—		—		16,694		—			16,694
	$	—	$	—	$	233,130	$	(5,548	)	$	227,582

(1) Represents the impact of netting assets and liabilities with counterparties with which the right of offset exists.

Reconciliation of Financial Assets and Liabilities Measured at Fair Value on a Recurring Basis using Significant Unobservable Inputs (Level 3)

The tables below set forth a reconciliation of the Company’s financial assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three and six-month periods ended June 30, 2011 and 2010 (in thousands):

	Three Months Ended June 30,
	2011									2010
	Commodity Derivative Contracts			Interest Rate Swaps			Total			Commodity Derivative Contracts			Interest Rate Swaps			Total
Balance of Level 3, March 31	$	(478,541	)	$	(14,929	)	$	(493,470	)	$	65,512		$	(12,147	)	$	53,365
Total realized and unrealized gains (losses)		169,988			(2,798	)		167,190			119,621			(6,477	)		113,144
Purchases		(3,353	)		—			(3,353	)		—			—			—
Settlements		18,273			2,442			20,715			(117,955	)		2,076			(115,879	)
Balance of Level 3, June 30	$	(293,633	)	$	(15,285	)	$	(308,918	)	$	67,178		$	(16,548	)	$	50,630

	Six Months Ended June 30,
	2011									2010
	Commodity Derivative Contracts			Interest Rate Swaps			Total			Commodity Derivative Contracts			Interest Rate Swaps			Total
Balance of Level 3, December 31	$	(205,860	)	$	(16,694	)	$	(222,554	)	$	46,153		$	(8,299	)	$	37,854
Total realized and unrealized (losses) gains		(107,640	)		(3,076	)		(110,716	)		181,573			(12,412	)		169,161
Purchases		(7,014	)		—			(7,014	)		—			—			—
Settlements		26,881			4,485			31,366			(160,548	)		4,163			(156,385	)
Balance of Level 3, June 30	$	(293,633	)	$	(15,285	)	$	(308,918	)	$	67,178		$	(16,548	)	$	50,630

Estimated Fair Value, Based on Quoted Market Prices, and the Carrying Value of Senior Notes

The Company measures the fair value of its long-term debt based on quoted market prices and also considers the effect of the Company’s credit risk. The estimated fair values of the Company’s senior notes and the carrying value at June 30, 2011 and December 31, 2010 were as follows (in thousands):

	June 30, 2011				December 31, 2010
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Floating Rate Notes due 2014	$	349,127	$	350,000	$	334,751	$	350,000
8.625% Senior Notes due 2015		—		—		663,181		650,000
9.875% Senior Notes due 2016(1)		406,146		353,619		394,527		352,707
8.0% Senior Notes due 2018		763,636		750,000		762,849		750,000
8.75% Senior Notes due 2020(2)		479,767		443,307		472,968		443,057
7.5% Senior Notes due 2021		909,203		900,000		—		—

(1) Carrying value is net of $11,881 and $12,793 discount at June 30, 2011 and December 31, 2010, respectively.

(2) Carrying value is net of $6,693 and $6,943 discount at June 30, 2011 and December 31, 2010, respectively.

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Effect of Derivative Contracts on Condensed Consolidated Statements of Operations (Detail) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) Loss Recognized in Income	$ (167,190)	$ (113,144)	$ 110,716	$ (169,161)
Oil and natural gas derivatives | (Gain) loss on derivative contracts
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) Loss Recognized in Income	(169,988)	(119,621)	107,640	(181,573)
Interest rate swaps | Interest expense
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) Loss Recognized in Income	$ 2,798	$ 6,477	$ 3,076	$ 12,412

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Common Stock (Detail) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Stockholders Equity Note [Line Items]
Common stock, shares authorized	800,000	800,000
Common stock, outstanding	409,918	406,360
Shares held in treasury	580	470

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Long-Term Debt (Detail) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Debt Disclosure [Line Items]
Debt	$ 2,893,453	$ 2,909,086
Less: current maturities of long-term debt	1,019	7,293
Long-term debt	2,892,434	2,901,793
Senior credit facility
Debt Disclosure [Line Items]
Debt	80,000	340,000
Other notes payable | Drilling Rig Fleet and Related Oil Field Services Equipment Note
Debt Disclosure [Line Items]
Debt		6,302
Other notes payable | Mortgage
Debt Disclosure [Line Items]
Debt	16,527	17,020
Senior Floating Rate Notes due 2014
Debt Disclosure [Line Items]
Debt	350,000	350,000
8.625% Senior Notes due 2015
Debt Disclosure [Line Items]
Debt		650,000
9.875% Senior Notes due 2016
Debt Disclosure [Line Items]
Debt	353,619	352,707
8.0% Senior Notes due 2018
Debt Disclosure [Line Items]
Debt	750,000	750,000
8.75% Senior Notes due 2020
Debt Disclosure [Line Items]
Debt	443,307	443,057
Senior Notes 7.5 Percent Due 2021
Debt Disclosure [Line Items]
Debt	$ 900,000

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Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2011

Long-term debt

Long-term debt consists of the following (in thousands):

	June 30, 2011		December 31, 2010
Senior credit facility	$	80,000	$	340,000
Other notes payable
Drilling rig fleet and related oil field services equipment		—		6,302
Mortgage		16,527		17,020
Senior Floating Rate Notes due 2014		350,000		350,000
8.625% Senior Notes due 2015		—		650,000
9.875% Senior Notes due 2016, net of $11,881 and $12,793 discount, respectively		353,619		352,707
8.0% Senior Notes due 2018		750,000		750,000
8.75% Senior Notes due 2020, net of $6,693 and $6,943 discount, respectively		443,307		443,057
7.5% Senior Notes due 2021		900,000		—
Total debt		2,893,453		2,909,086
Less: current maturities of long-term debt		1,019		7,293
Long-term debt	$	2,892,434	$	2,901,793

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Acquisitions and Divestitures - Additional Information (Detail) (USD $)	1 Months Ended	3 Months Ended			6 Months Ended			1 Months Ended
	Jul. 31, 2010	Jun. 30, 2011	Mar. 31, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Jul. 16, 2010	Jan. 31, 2011 Assets of Wolfberry	Apr. 30, 2011 Assets of New Mexico
Business Acquisition, Contingent Consideration [Line Items]
Shares of common stock issued to Arena stockholders in connection with acquisition for each outstanding share							4.7771
Cash paid to Arena stockholders in connection with acquisition for each outstanding share							$ 4.50
Common stock, issued in connection with Arena acquisition	190,300,000
Total Cash paid to Arena stockholders in connection with the acquisition							$ 177,900,000
Aggregate purchase price for Arena acquisition							1,400,000,000
Fees related to Arena acquisition		200,000		3,800,000	600,000	4,800,000
Goodwill, purchase price allocation adjustment			800,000		200,000
Sale of oil and natural gas properties								$ 153,800,000	$ 198,500,000

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Other Assets (Tables)

6 Months Ended

Jun. 30, 2011

Other Asset

Other assets consist of the following (in thousands):

	June 30, 2011		December 31, 2010
Debt issuance costs, net of amortization	$	56,662	$	50,637
Investments		4,908		4,826
Other		10,384		4,288
Total other assets	$	71,954	$	59,751

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Derivatives

6 Months Ended

Jun. 30, 2011

Derivatives

12. Derivatives

None of the Company’s derivative contracts have been designated as hedges. The Company records all derivative contracts, which include commodity derivatives and an interest rate swap, at fair value. Changes in derivative contract fair values are recognized in earnings. Cash settlements and valuation gains and losses are included in (gain) loss on derivative contracts for the commodity derivative contracts and in interest expense for interest rate swaps in the consolidated statement of operations. Commodity derivative contracts are settled on a monthly basis. Settlements on interest rate swaps occur quarterly. Derivative assets and liabilities arising from the Company’s derivative contracts with the same counterparty that provide for net settlement are reported on a net basis in the consolidated balance sheet.

Commodity Derivatives. The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil and natural gas. The Company seeks to manage this risk through the use of commodity derivative contracts. These derivative contracts allow the Company to limit its exposure to a portion of its projected oil and natural gas sales. None of the Company’s derivative contracts may be terminated early as a result of a party to the contract having its credit rating downgraded. At June 30, 2011, the Company’s commodity derivative contracts consisted of fixed price swaps, collars and basis swaps, which are described below:

Fixed price swaps:	The Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.
Collars:	Collars contain a fixed floor price (put) and a fixed ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.
Basis swaps:	The Company receives a payment from the counterparty if the settled price differential is greater than the stated terms of the contract and pays the counterparty if the settled price differential is less than the stated terms of the contract, which guarantees the Company a price differential for natural gas from a specified delivery point.

On April 12, 2011, the Company entered into a derivatives agreement with the Mississippian Trust, effective April 1, 2011, that provides the Mississippian Trust with the benefit of certain oil and natural gas derivative contracts previously entered into by the Company with third parties. The underlying commodity derivative contracts cover volumes of oil and natural gas production through December 31, 2015. Under this arrangement, the Company will pay the Mississippian Trust amounts it receives from its counterparties in accordance with the underlying contracts, and the Mississippian Trust will pay the Company any amounts that it is required to pay its counterparties under such contracts. These commodity derivative contracts are included in the open oil and natural gas derivative contracts tables below. See Note 8 for additional discussion of the Mississippian Trust and a listing of the derivative contracts, the benefits and obligations of which will be passed to the Mississippian Trust.

Interest Rate Swaps. The Company is exposed to interest rate risk on its long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes the Company to (i) changes in market interest rates reflected in the fair value of the debt and (ii) the risk that the Company may need to refinance maturing debt with new debt at a higher rate. Variable rate debt, where the interest rate fluctuates, exposes the Company to short-term changes in market interest rates as the Company’s interest obligations on these instruments are periodically redetermined based on prevailing market interest rates, primarily LIBOR and the federal funds rate.

The Company has an interest rate swap agreement to manage the interest rate risk on a portion of its floating rate debt by effectively fixing the variable interest rate on its Senior Floating Rate Notes through April 1, 2013. See Note 11 for further discussion of the Company’s interest rate swap.

Fair Value of Derivatives. In accordance with ASC Topic 815, Derivatives and Hedging, the following table presents the fair value of the Company’s derivative contracts at June 30, 2011 and December 31, 2010 on a gross basis without regard to same-counterparty netting (in thousands):

Type of Contract	Balance Sheet Classification	June 30, 2011			December 31, 2010
Derivative assets
Oil price swaps	Derivative contracts-current	$	2,674		$	—
Natural gas price swaps	Derivative contracts-current		6,157			8,500
Oil price swaps	Derivative contracts-noncurrent		3,415			—
Natural gas price swaps	Derivative contracts-noncurrent		—			3,518
Derivative liabilities
Oil price swaps	Derivative contracts-current		(104,129	)		(63,123	)
Natural gas price swaps	Derivative contracts-current		(38	)		(640	)
Natural gas basis swaps	Derivative contracts-current		(41,973	)		(34,112	)
Interest rate swaps	Derivative contracts-current		(9,552	)		(9,007	)
Oil price swaps	Derivative contracts-noncurrent		(135,069	)		(84,055	)
Natural gas price swaps	Derivative contracts-noncurrent		—			(802	)
Natural gas basis swaps	Derivative contracts-noncurrent		(24,446	)		(34,908	)
Natural gas collars	Derivative contracts-noncurrent		(224	)		(238	)
Interest rate swap	Derivative contracts-noncurrent		(5,733	)		(7,687	)
Total derivative contracts, net		$	(308,918	)	$	(222,554	)

Refer to Note 4 for additional discussion on the fair value measurement of the Company’s derivative contracts.

The following table summarizes the effects of the Company’s derivative contracts on the accompanying condensed consolidated statements of operations for the three and six-month periods ended June 30, 2011 and 2010 (in thousands):

Type of Contract	Location of (Gain) Loss Recognized in Income	Amount of (Gain) Loss Recognized in Income
		Three Months Ended June 30,						Six Months Ended June 30,
		2011			2010			2011		2010
Oil and natural gas derivatives	(Gain) loss on derivative contracts	$	(169,988	)	$	(119,621	)	$	107,640	$	(181,573	)
Interest rate swaps	Interest expense		2,798			6,477			3,076		12,412
Total		$	(167,190	)	$	(113,144	)	$	110,716	$	(169,161	)

The following tables summarize the cash settlements and valuation gains and losses on our commodity derivative contracts and interest rate swaps for the three and six-month periods ended June 30, 2011 and 2010 (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
Oil and Natural Gas Derivatives	2011			2010			2011			2010
Realized loss (gain)(1)	$	18,273		$	(117,955	)	$	26,881		$	(160,548	)
Unrealized (gain) loss		(188,261	)		(1,666	)		80,759			(21,025	)
(Gain) loss on commodity derivative contracts	$	(169,988	)	$	(119,621	)	$	107,640		$	(181,573	)
	Three Months Ended June 30,						Six Months Ended June 30,
Interest Rate Swaps	2011			2010			2011			2010
Realized loss	$	2,442		$	2,076		$	4,485		$	4,163
Unrealized loss (gain)		356			4,401			(1,409	)		8,249
Loss on interest rate swaps	$	2,798		$	6,477		$	3,076		$	12,412

(1) Includes $25.8 million and $38.2 million of realized gains for the three and six-month periods ended June 30, 2011, respectively, related to settlements of commodity derivative contracts with contractual maturities after the quarterly period in which they were settled. Includes $62.4 million of realized gains for the three and six-month periods ended June 30, 2010, related to settlements of commodity derivative contracts with contractual maturities after June 30, 2010.

On June 30, 2011, the Company’s open oil and natural gas commodity derivative contracts consisted of the following:

Oil Swaps

Period and Type of Contract(1)	Notional (MBbl)		Weighted Avg. Fixed Price
July 2011 — September 2011
Price swap contracts		2,301	$	86.89
October 2011 — December 2011
Price swap contracts		2,301	$	86.89
January 2012 — March 2012
Price swap contracts		2,388	$	87.98
April 2012 — June 2012
Price swap contracts		2,479	$	87.88
July 2012 — September 2012
Price swap contracts		2,536	$	87.85
October 2012 — December 2012
Price swap contracts		2,598	$	87.79
January 2013 — March 2013
Price swap contracts		2,168	$	93.09
April 2013 — June 2013
Price swap contracts		2,192	$	93.09
July 2013 — September 2013
Price swap contracts		2,216	$	93.09
October 2013 — December 2013
Price swap contracts		2,216	$	93.09
January 2014 — March 2014
Price swap contracts		493	$	101.07
April 2014 — June 2014
Price swap contracts		499	$	101.07
July 2014 — September 2014
Price swap contracts		504	$	101.07
October 2014 — December 2014
Price swap contracts		504	$	101.07
January 2015 — March 2015
Price swap contracts		295	$	100.45
April 2015 — June 2015
Price swap contracts		299	$	100.45
July 2015 — September 2015
Price swap contracts		302	$	100.45
October 2015 — December 2015
Price swap contracts		302	$	100.45

Natural Gas Swaps

Period and Type of Contract(1)	Notional (MMcf)(2)		Weighted Avg. Fixed Price
July 2011 — September 2011
Price swap contracts(3)		6,779	$	4.63
Basis swap contracts		26,220	$	(0.47	)
October 2011 — December 2011
Price swap contracts(3)		6,471	$	4.65
Basis swap contracts		26,220	$	(0.47	)
January 2012 — March 2012
Price swap contracts(3)		5,460	$	5.12
Basis swap contracts		28,210	$	(0.55	)
April 2012 — June 2012
Price swap contracts(3)		5,460	$	5.12
Basis swap contracts		28,210	$	(0.55	)
July 2012 — September 2012
Basis swap contracts		28,520	$	(0.55	)
October 2012 — December 2012
Basis swap contracts		28,520	$	(0.55	)
January 2013 — March 2013
Basis swap contracts		3,600	$	(0.46	)
April 2013 — June 2013
Basis swap contracts		3,640	$	(0.46	)
July 2013 — September 2013
Basis swap contracts		3,680	$	(0.46	)
October 2013 — December 2013
Basis swap contracts		3,680	$	(0.46	)

Natural Gas Collars

Period and Type of Contract(1)	Notional (MMcf)(2)		Collar Range
July 2012 — September 2012
Collars		201		4.00 - 6.20
October 2012 — December 2012
Collars		201		4.00 - 6.20
January 2013 — March 2013
Collars		212		4.00 - 7.15
April 2013 — June 2013
Collars		214		4.00 - 7.15
July 2013 — September 2013
Collars		216		4.00 - 7.15
October 2013 — December 2013
Collars		216		4.00 - 7.15
January 2014 — March 2014
Collars		231		4.00 - 7.78
April 2014 — June 2014
Collars		234		4.00 - 7.78
July 2014 — September 2014
Collars		236		4.00 - 7.78
October 2014 — December 2014
Collars		236		4.00 - 7.78
January 2015 — March 2015
Collars		249		4.00 - 8.55
April 2015 — June 2015
Collars		252		4.00 - 8.55
July 2015 — September 2015
Collars		255		4.00 - 8.55
October 2015 — December 2015
Collars		255		4.00 - 8.55

(1) Includes derivative contracts, the benefits of which have been conveyed to the Mississippian Trust pursuant to the derivatives agreement with the Mississippian Trust. See Note 8 for a listing of open derivative contracts at June 30, 2011, the benefits and obligations of which were conveyed to the Mississippian Trust.

(2) Assumes ratio of 1:1 for Mcf to MMBtu.

(3) Includes 7,865 MMcf and 7,280 MMcf with contractual maturities in 2011 and 2012, respectively, that were settled in July 2011.

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Open Oil and Natural Gas Commodity Derivative Contracts - Sand Ridge Mississippian Trust I (Detail) (Sand Ridge Mississippian Trust I)	Jun. 30, 2011 Mbbl
Oil | Swap | July, 2011 Through December, 2011
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	241
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	103.60
Oil | Swap | January, 2012 Through December, 2012
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	454
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	104.15
Oil | Swap | January, 2013 Through December, 2013
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	488
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	102.07
Oil | Swap | January, 2014 Through December, 2014
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	541
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	100.94
Oil | Swap | January, 2015 Through December, 2015
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	468
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	101.07
Natural Gas | Swap | July, 2011 Through December, 2011
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	2,086	[1]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	4.61
Natural Gas | Swap | January, 2012 Through June, 2012
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	2,190	[1]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	4.90
Natural Gas | Collars | January, 2013 Through December, 2013
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	858	[1]
Collar Range, minimum	4.00
Collar Range, maximum	7.15
Natural Gas | Collars | January, 2014 Through December, 2014
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	937	[1]
Collar Range, minimum	4.00
Collar Range, maximum	7.78
Natural Gas | Collars | January, 2015 Through December, 2015
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	1,010	[1]
Collar Range, minimum	4.00
Collar Range, maximum	8.55
Natural Gas | Collars | July, 2012 Through December, 2012
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	402	[1]
Collar Range, minimum	4.00
Collar Range, maximum	6.20

[1] Assumes ratio of 1:1 for Mcf to MMBtu.

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Subsequent Events - Additional Information (Detail) (Subsequent Event, USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2011 acre
Acres of land for development	15,900
Mississippian Properties
Ownership interest sold	13.20%
Acres of land for development	860,000
Expected proceeds from Atinum in exchange for the working interest	250.0
Expected payments by Atinum for the costs to develop the acreage	250.0
Acreage development period	3Y
Sand Ridge Permian Trust
Shares issued in initial public offering, value	760.7
Ownership interest acquired	40.00%

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Earnings Per Share - Additional Information (Detail) In Millions	6 Months Ended
	Jun. 30, 2011
Restricted stocks with antidilutive effect excluded from the computation of net loss per share	7.3

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Reconciliation of Carrying Amounts of Asset Retirement Obligation (Detail) (USD $) In Thousands	6 Months Ended
	Jun. 30, 2011	Dec. 31, 2010
Reconciliation of Changes in Asset Retirement Obligations [Line Items]
Asset retirement obligation, Beginning Balance	$ 119,877
Liability incurred upon acquiring and drilling wells	2,702
Sales of reserves in place	(6,855)
Liability settled in current period	(1,370)
Accretion of discount expense	4,786
Asset retirement obligation, Ending Balance	119,140
Less: current portion	25,360	25,360
Asset retirement obligation, net of current	$ 93,780	$ 94,517

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Property, Plant and Equipment

6 Months Ended

Jun. 30, 2011

Property, Plant and Equipment

5. Property, Plant and Equipment

Property, plant and equipment consists of the following (in thousands):

	June 30, 2011			December 31, 2010
Oil and natural gas properties
Proved	$	8,552,148		$	8,159,924
Unproved		624,668			547,953
Total oil and natural gas properties		9,176,816			8,707,877
Less: accumulated depreciation, depletion and impairment		(4,625,330	)		(4,483,736	)
Net oil and natural gas properties capitalized costs		4,551,486			4,224,141
Land		14,192			14,418
Non oil and natural gas equipment(1)		674,211			666,233
Buildings and structures		106,711			89,813
Total		795,114			770,464
Less: accumulated depreciation and amortization		(275,750	)		(260,740	)
Net capitalized costs		519,364			509,724
Total property, plant and equipment, net	$	5,070,850		$	4,733,865

(1) Includes capitalized interest of approximately $5.2 million and $4.7 million at June 30, 2011 and December 31, 2010, respectively.

There were no full cost ceiling impairments during the three or six-month periods ended June 30, 2011 or 2010. Cumulative full cost ceiling limitation impairment charges of $3,548.3 million at both June 30, 2011 and December 31, 2010 were included in accumulated depreciation, depletion and impairment for oil and natural gas properties in the table above.

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2011

Commitments and Contingencies

15. Commitments and Contingencies

The Company is a defendant in lawsuits from time to time in the normal course of business. In management’s opinion, the Company is not currently involved in any legal proceedings that, individually or in the aggregate, could have a material effect on the financial condition, operations or cash flows of the Company.

On or about June 27, 2008 and November 6, 2008, there were fires at the Company’s Grey Ranch Plant and a nearby compressor station. The Company, as owner of the plant and compressor station, recovered approximately $24.5 million from its insurance carriers for damages caused by the fires. At the time of the plant fire, the plant was operated by Southern Union Gas Services, Ltd. (“Southern Union Gas”). On June 4, 2010, November 10, 2010, and March 15, 2011, the Company’s insurance carriers filed lawsuits against Southern Union Gas and its parent, Southern Union Company (together with Southern Union Gas, “Southern Union”) seeking recovery for amounts paid under the Company’s insurance policies. Southern Union, in turn, has tendered indemnity requests to GRLP, of which the Company is a 50% owner. GRLP has not accepted or acknowledged any responsibility to indemnify Southern Union. To the extent the Company, as a 50% owner of GRLP, is required to fund any indemnification of Southern Union, it will pursue coverage for such liability under its general liability insurance policy. An estimate of reasonably possible losses associated with these claims cannot be made at this time. The Company has not established any reserves relating to these claims.

On February 14, 2011, Aspen Pipeline, II, L.P. (“Aspen”) filed a complaint in the District Court of Harris County, Texas, against Arena Resources, Inc. and SandRidge Energy, Inc. claiming damages based upon alleged representations by Arena in connection with the construction by Aspen of a natural gas pipeline in West Texas. The plaintiff seeks damages that include the construction cost of the pipeline, which it claims approach $90.0 million. The Company intends to defend this lawsuit vigorously and, believes the plaintiff’s claims are without merit. This case is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this claim cannot be made at this time. The Company has not established any reserves relating to this claim.

On April 5, 2011, Wesley West Minerals, Ltd. and Longfellow Ranch Partners, LP (collectively, the “plaintiffs”) filed suit against SandRidge Energy, Inc. and SandRidge Exploration and Production, LLC (collectively, the “SandRidge Entities”) in the 83^rd District Court of Pecos County, Texas. The plaintiffs, who have leased mineral rights to the SandRidge Entities in Pecos County, allege that the SandRidge Entities have not properly paid royalties on all volumes of natural gas (including carbon dioxide, or “CO₂”) produced from the acreage leased from the plaintiffs. The plaintiffs also allege that the SandRidge Entities have inappropriately failed to pay royalties on CO₂ produced from the plaintiffs’ acreage that results from the treatment of natural gas at the Century Plant. The plaintiffs seek unspecified actual damages, punitive damages and a declaration that the SandRidge Entities must pay royalties on CO₂ produced from plaintiffs’ acreage that results from treatment of natural gas at the Century Plant. The Company intends to defend this lawsuit vigorously. This case is in the early stages and, accordingly, an estimate of reasonably possible losses, if any, associated with these claims cannot be made at this time. The Company has not established any reserves relating to these claims.

SandRidge acquired certain oil and natural gas leases in Loving County, Texas, from mineral owners in April 2010, which it subsequently sold to Energen Resources Corporation (“Energen”) in December 2010 for an allocated value of approximately $4.0 million. Subsequent to the acquisition by SandRidge of the leases and prior to their disposition to Energen, the mineral owners executed oil and natural gas leases conveying the same mineral estates to Cimarex Energy Co. (“Cimarex”). SandRidge has requested a declaratory judgment resolving all disputes between it and Cimarex regarding the validity of the leases insofar as they purport to cover the same mineral interests. In connection with that action, Cimarex has filed a third-party petition naming Energen as a third-party defendant, and is asserting quiet title and trespass to try title claims against Energen. Energen has tendered to SandRidge a demand for indemnity, and SandRidge has assumed Energen’s defense and any potential loss suffered by it. An estimate of reasonably possible losses, if any, associated with the demand for indemnity cannot be made at this time. Accordingly, the Company has not established any reserves relating to the demand.

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Fair Value of Derivative Contracts (Detail) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Derivatives, Fair Value [Line Items]
Derivatives net	$ (308,918)	$ (222,554)
Oil price swaps | Current Assets
Derivatives, Fair Value [Line Items]
Derivative assets	2,674
Oil price swaps | Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative assets	3,415
Oil price swaps | Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	(104,129)	(63,123)
Oil price swaps | Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	(135,069)	(84,055)
Natural gas price swaps | Current Assets
Derivatives, Fair Value [Line Items]
Derivative assets	6,157	8,500
Natural gas price swaps | Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative assets		3,518
Natural gas price swaps | Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	(38)	(640)
Natural gas price swaps | Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities		(802)
Natural gas basis swap | Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	(41,973)	(34,112)
Natural gas basis swap | Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	(24,446)	(34,908)
Interest rate swaps | Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	(9,552)	(9,007)
Interest rate swaps | Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	(5,733)	(7,687)
Natural gas collars | Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	$ (224)	$ (238)

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Long-Term Debt (Parenthetical) (Detail) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
9.875% Senior Notes due 2016
Debt Disclosure [Line Items]
Notes, discount	$ 11,881	$ 12,793
8.75% Senior Notes due 2020
Debt Disclosure [Line Items]
Notes, discount	$ 6,693	$ 6,943

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Business Segment Information (Tables)

6 Months Ended

Jun. 30, 2011

Summarized Financial Information Concerning the Company's Segments

operating expenses and depreciation, depletion and amortization. Summarized financial information concerning the Company’s segments is shown in the following tables (in thousands):

	Exploration  and Production			Drilling and Oil Field Services			Midstream  Gas Services			All Other			Consolidated Total
Three Months Ended June 30, 2011
Revenues	$	317,768		$	96,443		$	48,278		$	2,886		$	465,375
Inter-segment revenue		(66	)		(67,906	)		(32,473	)		(156	)		(100,601	)
Total revenues	$	317,702		$	28,537		$	15,805		$	2,730		$	364,774
Operating income (loss)	$	301,197		$	4,098		$	(2,570	)	$	(23,009	)	$	279,716
Interest income (expense), net		15			4			(141	)		(61,565	)		(61,687	)
Loss on extinguishment of debt		—			—			—			(2,051	)		(2,051	)
Other income (expense), net		3			—			216			(81	)		138
Income (loss) before income taxes	$	301,215		$	4,102		$	(2,495	)	$	(86,706	)	$	216,116
Capital expenditures(1)	$	423,725		$	8,030		$	4,462		$	17,875		$	454,092
Depreciation, depletion and amortization	$	76,734		$	7,998		$	1,291		$	3,438		$	89,461
Three Months Ended June 30, 2010
Revenues	$	150,571		$	55,975		$	66,379		$	8,744		$	281,669
Inter-segment revenue		(66	)		(52,063	)		(44,223	)		(2,878	)		(99,230	)
Total revenues	$	150,505		$	3,912		$	22,156		$	5,866		$	182,439
Operating income (loss)	$	136,465		$	(294	)	$	902		$	(17,621	)	$	119,452
Interest income (expense), net		121			(254	)		(161	)		(63,867	)		(64,161	)
Other income (expense), net		13			—			56			(599	)		(530	)
Income (loss) before income taxes	$	136,599		$	(548	)	$	797		$	(82,087	)	$	54,761
Capital expenditures(1)	$	218,973		$	8,195		$	16,337		$	5,459		$	248,964
Depreciation, depletion and amortization	$	55,041		$	6,833		$	927		$	3,338		$	66,139
Six Months Ended June 30, 2011
Revenues	$	585,004		$	163,992		$	104,256		$	6,106		$	859,358
Inter-segment revenue		(133	)		(114,421	)		(66,511	)		(672	)		(181,737	)
Total revenues	$	584,871		$	49,571		$	37,745		$	5,434		$	677,621
Operating income (loss)	$	116,990		$	3,990		$	(5,098	)	$	(43,995	)	$	71,887
Interest income (expense), net		120			(101	)		(313	)		(120,830	)		(121,124	)
Loss on extinguishment of debt		—			—			—			(38,232	)		(38,232	)
Other income (expense), net		1,679			—			(485	)		141			1,335
Income (loss) before income taxes	$	118,789		$	3,889		$	(5,896	)	$	(202,916	)	$	(86,134	)
Capital expenditures(1)	$	826,813		$	14,793		$	8,635		$	24,011		$	874,252
Depreciation, depletion and amortization	$	151,206		$	15,727		$	2,388		$	7,119		$	176,440
At June 30, 2011
Total assets	$	4,951,934		$	232,165		$	153,516		$	259,059		$	5,596,674
Six Months Ended June 30, 2010
Revenues	$	320,755		$	142,049		$	148,916		$	19,197		$	630,917
Inter-segment revenue		(131	)		(132,377	)		(99,233	)		(5,742	)		(237,483	)
Total revenues	$	320,624		$	9,672		$	49,683		$	13,455		$	393,434
Operating income (loss)	$	246,488		$	(4,594	)	$	2,156		$	(35,427	)	$	208,623
Interest expense (expense), net		200			(567	)		(299	)		(125,515	)		(126,181	)
Other income (expense), net		781			—			56			(131	)		706
Income (loss) before income taxes	$	247,469		$	(5,161	)	$	1,913		$	(161,073	)	$	83,148
Capital expenditures(1)	$	411,050		$	17,612		$	36,759		$	12,124		$	477,545
Depreciation, depletion and amortization	$	108,034		$	14,163		$	1,803		$	6,720		$	130,720
At December 31, 2010
Total assets	$	4,612,295		$	224,784		$	151,598		$	242,771		$	5,231,448

(1) On an accrual basis.

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Open Oil and Natural Gas Commodity Derivative Contracts (Parenthetical) (Detail) (Natural Gas, Swap)	Jun. 30, 2011 MMcf
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional amount of Natural Gas, Settlement period	2011-07
Contracts Maturing in 2011
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	7,865
Contracts Maturing in 2012
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	7,280

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Property, Plant and Equipment (Tables)

6 Months Ended

Jun. 30, 2011

Property, Plant and Equipment

Property, plant and equipment consists of the following (in thousands):

	June 30, 2011			December 31, 2010
Oil and natural gas properties
Proved	$	8,552,148		$	8,159,924
Unproved		624,668			547,953
Total oil and natural gas properties		9,176,816			8,707,877
Less: accumulated depreciation, depletion and impairment		(4,625,330	)		(4,483,736	)
Net oil and natural gas properties capitalized costs		4,551,486			4,224,141
Land		14,192			14,418
Non oil and natural gas equipment(1)		674,211			666,233
Buildings and structures		106,711			89,813
Total		795,114			770,464
Less: accumulated depreciation and amortization		(275,750	)		(260,740	)
Net capitalized costs		519,364			509,724
Total property, plant and equipment, net	$	5,070,850		$	4,733,865

(1) Includes capitalized interest of approximately $5.2 million and $4.7 million at June 30, 2011 and December 31, 2010, respectively.

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CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (USD $) In Thousands	Total	Convertible Perpetual Preferred Stock	Common Stock	Additional Paid-In Capital	Treasury Stock	Accumulated Deficit	Noncontrolling Interest
Beginning Balance at Dec. 31, 2010	$ 1,547,483	$ 8	$ 398	$ 4,528,912	$ (3,547)	$ (2,989,576)	$ 11,288
Beginning Balance (in shares) at Dec. 31, 2010		7,650	406,360
Issuance of units by SandRidge Mississippian Trust I	336,892						336,892
Distributions to noncontrolling interest owners	(1,501)						(1,501)
Stock issuance expense	(231)			(231)
Purchase of treasury stock	(4,984)				(4,984)
Retirement of treasury stock				(4,984)	4,984
Stock purchases - retirement plans, net of distributions (in shares)			(110)
Stock purchases - retirement plans, net of distributions	1,020			1,998	(978)
Stock-based compensation	24,987			24,987
Stock-based compensation excess tax benefit	7			7
Issuance of restricted stock awards, net of cancellations			3,668
Net (loss) income	(79,167)					(92,328)	13,161
Convertible perpetual preferred stock dividends	(27,821)					(27,821)
Ending Balance at Jun. 30, 2011	$ 1,796,685	$ 8	$ 398	$ 4,550,689	$ (4,525)	$ (3,109,725)	$ 359,840
Ending Balance (in shares) at Jun. 30, 2011		7,650	409,918

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Equity

6 Months Ended

Jun. 30, 2011

Equity

16. Equity

Preferred Stock. The following table presents information regarding the Company’s preferred stock (in thousands):

	June 30, 2011		December 31, 2010
Shares authorized		50,000		50,000
Shares outstanding at end of period
8.5% Convertible perpetual preferred stock		2,650		2,650
6.0% Convertible perpetual preferred stock		2,000		2,000
7.0% Convertible perpetual preferred stock		3,000		3,000

The Company is authorized to issue 50,000,000 shares of preferred stock, $0.001 par value, of which 7,650,000 shares were designated as convertible perpetual preferred stock at June 30, 2011 and December 31, 2010. All of the outstanding shares of the Company’s convertible perpetual preferred stock were issued in private transactions and none of these shares are listed on a stock exchange.

8.5% Convertible perpetual preferred stock. The Company’s 8.5% convertible perpetual preferred stock was issued in January 2009. Each share of 8.5% convertible perpetual preferred stock has a liquidation preference of $100.00 and is convertible at the holder’s option at any time initially into approximately 12.4805 shares of the Company’s common stock based on an initial conversion price of $8.01, subject to adjustments upon the occurrence of certain events. Each holder of the convertible perpetual preferred stock is entitled to an annual dividend of $8.50 per share to be paid semi-annually in cash, common stock or a combination thereof, at the Company’s election. All dividend payments to date have been paid in cash. Approximately $5.6 million in dividends (all unpaid) and $11.3 million in dividends ($2.8 million paid and $8.5 million unpaid) on the 8.5% convertible perpetual preferred stock have been included in the Company’s earnings per share calculations for the three and six-month periods ended June 30, 2011, respectively, as presented in the accompanying condensed consolidated statements of operations. Approximately $5.6 million in dividends (all unpaid) and $11.3 million in dividends ($2.8 million paid and $8.5 million unpaid) on the 8.5% convertible perpetual preferred stock have been included in the Company’s earnings per share calculations for the three and six-month periods ended June 30, 2010, respectively, as presented in the accompanying condensed consolidated statements of operations. The 8.5% convertible perpetual preferred stock is not redeemable by the Company at any time. After February 20, 2014, the Company may cause all outstanding shares of the convertible perpetual preferred stock to convert automatically into common stock at the then-prevailing conversion rate if certain conditions are met.

6.0% Convertible perpetual preferred stock. The Company’s 6.0% convertible perpetual preferred stock was issued in December 2009. Each share of the 6.0% convertible perpetual preferred stock has a liquidation preference of $100.00 and is entitled to an annual dividend of $6.00 payable semi-annually in cash, common stock or any combination thereof, at the Company’s election. All dividend payments to date have been paid in cash. Approximately $3.0 million (all unpaid) and $6.0 million in dividends ($0.5 million paid and $5.5 million unpaid) on the 6.0% convertible perpetual preferred stock have been included in the Company’s earnings per share calculations for the three and six-month periods ended June 30, 2011, respectively, as presented in the accompanying condensed consolidated statements of operations. Approximately $3.0 million and $6.0 million in unpaid dividends on the 6.0% convertible perpetual preferred stock have been included in the Company’s earnings per share calculations for the three and six-month periods ended June 30, 2010, respectively, as presented in the accompanying condensed consolidated statements of operations. The 6.0% convertible perpetual preferred stock is not redeemable by the Company at any time. Each share is initially convertible into approximately 9.2115 shares of the Company’s common stock, at the holder’s option based on an initial conversion price of $10.86 and subject to customary adjustments in certain circumstances. Five years after their issuance, all outstanding shares of the convertible preferred stock will be converted automatically into shares of the Company’s common stock at the then-prevailing conversion price as long as all dividends accrued at that time have been paid.

7.0% Convertible perpetual preferred stock. The Company’s 7.0% convertible perpetual preferred stock was issued in November 2010. Each share of the 7.0% convertible preferred stock has a liquidation preference of $100.00 per share and became convertible at the holder’s option on February 15, 2011, initially into approximately 12.8791 shares of the Company’s common stock based on an initial conversion price of $7.76 per share. The annual dividend on each share of the 7.0% convertible preferred stock is $7.00 payable semi-annually, in cash, common stock or a combination thereof, at the Company’s election beginning on May 15, 2011. All dividend payments to date have been paid in cash. Approximately $5.3 million ($2.7 million paid and $2.6 million unpaid) and $10.6 million in dividends ($8.0 million paid and $2.6 million unpaid) on the 7.0% convertible perpetual preferred stock have been included in the Company’s earnings per share calculations for the three and six-month periods ended June 30, 2011 as presented in the accompanying condensed consolidated statements of operations. The 7.0% convertible perpetual preferred stock is not redeemable by the Company at any time. After November 20, 2015, the Company may cause all outstanding shares of the 7.0% convertible perpetual preferred stock to convert automatically into common stock at the then-prevailing conversion rate if certain conditions are met.

Common Stock. The following table presents information regarding the Company’s common stock (in thousands):

	June 30, 2011		December 31, 2010
Shares authorized		800,000		800,000
Shares outstanding at end of period		409,918		406,360
Shares held in treasury		580		470

Treasury Stock. The Company makes required tax payments on behalf of employees when their restricted stock awards vest and then withholds a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. As a result of such transactions, the Company withheld approximately 617,000 shares with a total value of $5.0 million and approximately 274,000 shares with a total value of $2.9 million during the six-month periods ended June 30, 2011 and 2010, respectively. These shares were accounted for as treasury stock when withheld, and subsequently retired.

Any shares of Company common stock held as assets in a trust for the Company’s non-qualified deferred compensation plan are accounted for as treasury shares. These shares are not included as outstanding shares of common stock in this Quarterly Report. For corporate purposes and for purposes of voting at Company stockholder meetings, these shares are considered outstanding and have voting rights, which are exercised by the Company.

Equity Compensation. The Company awards restricted common stock under incentive compensation plans that vest over specified periods, subject to certain conditions. All awards issued during and after 2006 have four-year vesting periods. Shares of restricted common stock are subject to restriction on transfer. Unvested restricted stock awards are included in the Company’s outstanding shares of common stock.

For the three and six-month periods ended June 30, 2011, the Company recognized stock-based compensation expense of $8.9 million and $17.1 million, net of $1.9 million and $3.7 million capitalized, respectively, related to restricted common stock awards. For the three and six-month periods ended June 30, 2010, the Company recognized stock-based compensation expense of $7.3 million and $14.2 million, net of $1.3 million and $2.6 million capitalized, respectively, related to restricted common stock awards.

Noncontrolling Interest. Noncontrolling interests in one of the Company’s subsidiaries and three variable interest entities of which the Company is the primary beneficiary (see Note 8) represent third-party ownership interests in the consolidated entity and are included as a component of equity in the consolidated balance sheet and consolidated statement of changes in equity.

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Pro Forma Financial Information (Detail) (USD $) In Thousands, except Per Share data	3 Months Ended			6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010		Jun. 30, 2011	Jun. 30, 2010
Business Acquisition, Pro Forma Information [Line Items]
Revenues	$ 364,774	$ 182,439		$ 677,621	$ 393,434
Income available (loss applicable) to SandRidge Energy, Inc. common stockholders	196,135	44,884		(120,149)	63,489
Earnings (loss) per share
Basic	$ 0.49	$ 0.22		$ (0.30)	$ 0.31
Diluted	$ 0.42	$ 0.21		$ (0.30)	$ 0.31
Pro forma
Revenues		236,751			499,544
Income available (loss applicable) to SandRidge Energy, Inc. common stockholders		$ 503,597	[1]		$ 536,985	[1]
Pro forma net income (loss) per common share:
Basic		$ 1.28			$ 1.36
Diluted		$ 1.14			$ 1.23

[1] Pro forma columns reflect a $454.5 million reduction in tax expense related to the release of a portion of the Company's valuation allowance on existing deferred tax assets.

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Subsequent Events

6 Months Ended

Jun. 30, 2011

Subsequent Events

18. Subsequent Events

Events occurring after June 30, 2011 were evaluated to ensure that any subsequent events that met the criteria for recognition and/or disclosure in this Quarterly Report have been included.

SandRidge Permian Trust. On May 25, 2011, the Company and SandRidge Permian Trust (the “Permian Trust”), a newly formed Delaware trust, filed a joint registration statement with the Securities and Exchange Commission (the “SEC”) relating to a proposed public offering of up to approximately $760.7 million (before underwriting discounts and offering expenses) in common units representing beneficial interests in the Permian Trust (including common units issuable upon exercise of the underwriters’ over-allotment option). Prior to the closing of this offering, the Company intends to convey certain royalty interests to the Permian Trust in exchange for units representing approximately 40% of the beneficial interest in the Permian Trust and the net proceeds of the Permian Trust’s public offering. The royalty interests will entitle the Permian Trust to a percentage of the proceeds received by the Company from the production of hydrocarbons from currently producing wells and development wells to be drilled by the Company on approximately 15,900 net acres in the Permian Basin’s Central Basin Platform in Andrews County, Texas. There can be no assurance that this transaction will be completed, as it is subject to market conditions and other uncertainties, as well as completion of the SEC’s review process. If the transaction is completed, the Company intends to use the proceeds it receives to repay borrowings under its senior credit facility and for general corporate purposes.

Sale of Working Interest in Mississippian Properties. On August 3, 2011, the Company entered into an agreement with Atinum Partners Co., Ltd. (“Atinum”) pursuant to which the Company agreed to sell to Atinum a 13.2% undivided working interest in approximately 860,000 acres that the Company has leased in Oklahoma and Kansas for development of the Mississippian Lime horizontal play. In exchange for the working interest, Atinum will pay the Company $250.0 million in cash at closing and will pay $250.0 million of the Company’s costs to develop the acreage over the next three years. The agreement is subject to customary closing conditions and is expected to close during the fourth quarter of 2011.

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Income Taxes - Additional Information (Detail) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010	Jul. 16, 2010	Dec. 31, 2008
Reconciliation of Provision of Income Taxes [Line Items]
Change in net deferred tax liability related to business acquisition	$ 7,000,000
Deferred taxes assets, valuation allowance released					447,500,000
Deferred Income Tax Expense (Benefit)	(6,986,000)		(6,986,000)
Federal Net Operating Loss Carryforwards to the IRC Section 382 limitation						491,400,000	302,800,000
Unrecognized tax benefits	1,520,000		1,520,000		1,450,000
Unrecognized tax benefits that would affect the effective tax rate if recognized	1,000,000		1,000,000
Unrecognized tax benefits, accrued gross interest	20,000		70,000
Income Tax Payments, net of refunds	$ (40,000)	$ (100,000)	$ 940,000	$ (3,500,000)

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Cash Settlements and Valuation Gains and Losses on Commodity Derivative Contracts and Interest Rate Swaps (Parenthetical) (Detail) (Commodity derivative contracts, USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Commodity derivative contracts
Derivative Instruments, Gain (Loss) [Line Items]
Realized loss (gain) related to settlements of commodity derivative contracts	$ (25.8)	$ (62.4)	$ (38.2)	$ (62.4)

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Basis of Presentation

6 Months Ended

Jun. 30, 2011

Basis of Presentation

1. Basis of Presentation

Nature of Business. SandRidge Energy, Inc. (including its subsidiaries, the “Company” or “SandRidge”) is an independent oil and natural gas company concentrating on development and production activities related to the exploitation of its significant holdings in West Texas and the Mid-Continent area of Oklahoma and Kansas. The Company’s primary areas of focus are the Permian Basin in West Texas, the Mississippian formation in the Mid-Continent and the West Texas Overthrust (“WTO”). The Company owns and operates other interests in the Mid-Continent, Cotton Valley Trend in East Texas, Gulf Coast and Gulf of Mexico. The Company also operates businesses that are complementary to its primary development and production activities, including gas gathering and treating facilities, a gas marketing business, an oil field services business, including a drilling rig business, and tertiary oil recovery operations.

Interim Financial Statements. The accompanying condensed consolidated financial statements as of December 31, 2010 have been derived from the audited financial statements contained in the Company’s 2010 Form 10-K. The unaudited interim condensed consolidated financial statements have been prepared by the Company in accordance with the accounting policies stated in the audited consolidated financial statements contained in the 2010 Form 10-K. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted, although the Company believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the information in the Company’s unaudited condensed consolidated financial statements have been included. These condensed consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in the 2010 Form 10-K.

Risks and Uncertainties. The Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, each of which depends on numerous factors beyond the Company’s control such as economic conditions, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile, and may be subject to significant fluctuations in the future. The Company’s derivative arrangements serve to mitigate a portion of the effect of this price volatility on the Company’s cash flows, and while derivative contracts are in place for the majority of expected oil production for 2011 through 2013, fixed price swap contracts are in place for only a portion of expected natural gas production in 2011 and 2012 and oil production for 2014 and 2015. No fixed price swap contracts are in place for the Company’s natural gas production beyond 2012 or oil production beyond 2015. The Company has natural gas collars in place for a portion of expected natural gas production through 2015. See Note 12 for the Company’s open oil and natural gas commodity derivative contracts.

The Company has incurred, and will have to continue to incur, capital expenditures to achieve production targets contained in certain gathering and treating arrangements. The Company depends on the availability of borrowings under its senior secured revolving credit facility (the “senior credit facility”), along with cash flows from operating activities and the proceeds from planned asset sales or other asset monetizations, to fund those capital expenditures. Based on anticipated oil and natural gas prices, availability under the senior credit facility, potential access to the capital markets and anticipated proceeds from sales or other monetizations of assets, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for 2011. However, a substantial or extended decline in oil or natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced, which could adversely impact the Company’s ability to comply with the financial covenants under its senior credit facility, which in turn would limit further borrowings to fund capital expenditures. See Note 11 for discussion of the financial covenants in the senior credit facility.

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Asset Retirement Obligation

6 Months Ended

Jun. 30, 2011

Asset Retirement Obligation

10. Asset Retirement Obligation

A reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligation for the period from December 31, 2010 to June 30, 2011 is as follows (in thousands):

Asset retirement obligation, December 31, 2010	$	119,877
Liability incurred upon acquiring and drilling wells		2,702
Sales of reserves in place		(6,855	)
Liability settled in current period		(1,370	)
Accretion of discount expense		4,786
Asset retirement obligation, June 30, 2011		119,140
Less: current portion		25,360
Asset retirement obligation, net of current	$	93,780

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Variable Interest Entities - Additional Information (Detail) (USD $)	6 Months Ended				6 Months Ended	1 Months Ended	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2011 Grey Ranch, L.P.	Dec. 31, 2010 Grey Ranch, L.P.	Jun. 30, 2011 Grey Ranch Plant Genpar, LLC	Jun. 30, 2011 Pinon Gathering Company, LLC Year	Apr. 12, 2011 Sand Ridge Mississippian Trust I	Jun. 30, 2011 Sand Ridge Mississippian Trust I	Apr. 12, 2011 Sand Ridge Mississippian Trust I Common Units	Apr. 12, 2011 Sand Ridge Mississippian Trust I Subordinated Units
Variable Interest Entity [Line Items]
Shares issued in initial public offering						17,250,000
Net proceeds initial public offering						$ 336,900,000
Mississippian Trust units exchanged to royalty interests						10,750,000		3,750,000	7,000,000
Ownership interest		50.00%		50.00%		38.40%
Description of interest conveyed to the Trust						In conjunction with the closing, the Company conveyed certain royalty interests to the Trust in exchange for units representing approximately 38.4% of the beneficial interest in the Trust and the net proceeds of the Trust’s public offering. The royalty interests conveyed to the Trust are in certain oil and natural gas properties leased by the Company in the Mississippian formation in five counties in Northern Oklahoma.
Percentage of ownership interest in Grey Ranch, L.P.				1.00%
Noncontrolling interest		9,600,000	11,300,000				350,200,000
Conveyance of the royalty interests to the Mississippian Trust	336,892,000					309,000,000
Percentage of subordinated units to total unit						25.00%
Incentive distributions							Incentive distributions are equal to 50% of the amount by which the cash available for distribution on all of the Mississippian Trust units for any quarter is 20% or greater than the target distribution for such quarter.
Maximum amount recoverable by the Mississippian Trust under the lien							$ 136,400,000
Gas gathering and operations and maintenance agreements, period					20

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Assets and Liabilities Included in the Condensed Consolidated Balance Sheet, Grey Ranch, L.P (Detail) (Grey Ranch, L.P., USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Variable Interest Entity [Line Items]
Assets of Trust	$ 19,279	$ 24,294
Liabilities of Trust	318	1,751
Current Assets
Variable Interest Entity [Line Items]
Assets of Trust	3,719	8,215
Property, plant and equipment, other, net
Variable Interest Entity [Line Items]
Assets of Trust	15,560	16,079
Current Liabilities
Variable Interest Entity [Line Items]
Liabilities of Trust	$ 318	$ 1,751

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Open Oil and Natural Gas Commodity Derivative Contracts (Detail)	Jun. 30, 2011 Mbbl
Oil | July 2012 Through September 2012 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	2,536	[1]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	87.85	[1]
Oil | October 2012 Through December 2012 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	2,598	[1]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	87.79	[1]
Oil | January 2013 Through March 2013 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	2,168	[1]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	93.09	[1]
Oil | April 2013 Through June 2013 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	2,192	[1]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	93.09	[1]
Oil | July 2013 Through September 2013 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	2,216	[1]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	93.09	[1]
Oil | October 2013 Through December 2013 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	2,216	[1]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	93.09	[1]
Oil | January 2014 Through March 2014 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	493	[1]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	101.07	[1]
Oil | April 2014 Through June 2014 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	499	[1]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	101.07	[1]
Oil | July 2014 Through September 2014 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	504	[1]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	101.07	[1]
Oil | October 2014 Through December 2014 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	504	[1]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	101.07	[1]
Oil | January 2015 Through March 2015 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	295	[1]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	100.45	[1]
Oil | April 2015 Through June 2015 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	299	[1]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	100.45	[1]
Oil | July 2015 Through September 2015 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	302	[1]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	100.45	[1]
Oil | October 2015 Through December 2015 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	302	[1]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	100.45	[1]
Oil | July 2011 Through September 2011 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	2,301	[1]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	86.89	[1]
Oil | October 2011 Through December 2011 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	2,301	[1]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	86.89	[1]
Oil | January 2012 Through March 2012 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	2,388	[1]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	87.98	[1]
Oil | April 2012 Through June 2012 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	2,479	[1]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	87.88	[1]
Natural Gas | Basis swap contracts | July 2012 Through September 2012
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	28,520	[1],[2]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	(0.55)	[1]
Natural Gas | Basis swap contracts | October 2012 Through December 2012
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	28,520	[1],[2]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	(0.55)	[1]
Natural Gas | Basis swap contracts | January 2013 Through March 2013
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	3,600	[1],[2]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	(0.46)	[1]
Natural Gas | Basis swap contracts | April 2013 Through June 2013
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	3,640	[1],[2]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	(0.46)	[1]
Natural Gas | Basis swap contracts | July 2013 Through September 2013
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	3,680	[1],[2]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	(0.46)	[1]
Natural Gas | Basis swap contracts | October 2013 Through December 2013
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	3,680	[1],[2]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	(0.46)	[1]
Natural Gas | Basis swap contracts | July 2011 Through September 2011
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	26,220	[1],[2]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	(0.47)	[1]
Natural Gas | Basis swap contracts | October 2011 Through December 2011
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	26,220	[1],[2]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	(0.47)	[1]
Natural Gas | Basis swap contracts | January 2012 Through March 2012
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	28,210	[1],[2]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	(0.55)	[1]
Natural Gas | Basis swap contracts | April 2012 Through June 2012
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	28,210	[1],[2]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	(0.55)	[1]
Natural Gas | July 2012 Through September 2012 | Collars
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	201	[1],[2]
Collar Range, minimum	4.00	[1]
Collar Range, maximum	6.20	[1]
Natural Gas | October 2012 Through December 2012 | Collars
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	201	[1],[2]
Collar Range, minimum	4.00	[1]
Collar Range, maximum	6.20	[1]
Natural Gas | January 2013 Through March 2013 | Collars
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	212	[1],[2]
Collar Range, minimum	4.00	[1]
Collar Range, maximum	7.15	[1]
Natural Gas | April 2013 Through June 2013 | Collars
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	214	[1],[2]
Collar Range, minimum	4.00	[1]
Collar Range, maximum	7.15	[1]
Natural Gas | July 2013 Through September 2013 | Collars
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	216	[1],[2]
Collar Range, minimum	4.00	[1]
Collar Range, maximum	7.15	[1]
Natural Gas | October 2013 Through December 2013 | Collars
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	216	[1],[2]
Collar Range, minimum	4.00	[1]
Collar Range, maximum	7.15	[1]
Natural Gas | January 2014 Through March 2014 | Collars
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	231	[1],[2]
Collar Range, minimum	4.00	[1]
Collar Range, maximum	7.78	[1]
Natural Gas | April 2014 Through June 2014 | Collars
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	234	[1],[2]
Collar Range, minimum	4.00	[1]
Collar Range, maximum	7.78	[1]
Natural Gas | July 2014 Through September 2014 | Collars
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	236	[1],[2]
Collar Range, minimum	4.00	[1]
Collar Range, maximum	7.78	[1]
Natural Gas | October 2014 Through December 2014 | Collars
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	236	[1],[2]
Collar Range, minimum	4.00	[1]
Collar Range, maximum	7.78	[1]
Natural Gas | January 2015 Through March 2015 | Collars
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	249	[1],[2]
Collar Range, minimum	4.00	[1]
Collar Range, maximum	8.55	[1]
Natural Gas | April 2015 Through June 2015 | Collars
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	252	[1],[2]
Collar Range, minimum	4.00	[1]
Collar Range, maximum	8.55	[1]
Natural Gas | July 2015 Through September 2015 | Collars
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	255	[1],[2]
Collar Range, minimum	4.00	[1]
Collar Range, maximum	8.55	[1]
Natural Gas | October 2015 Through December 2015 | Collars
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	255	[1],[2]
Collar Range, minimum	4.00	[1]
Collar Range, maximum	8.55	[1]
Natural Gas | July 2011 Through September 2011 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	6,779	[1],[2],[3]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	4.63	[1],[3]
Natural Gas | October 2011 Through December 2011 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	6,471	[1],[2],[3]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	4.65	[1],[3]
Natural Gas | January 2012 Through March 2012 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	5,460	[1],[2],[3]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	5.12	[1],[3]
Natural Gas | April 2012 Through June 2012 | Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount (Oil in MBbl/ Natural Gas in MMcf)	5,460	[1],[2],[3]
Weighted Avg. Fixed Price (Oil in USD / bbl, Natural Gas in USD / Mcf)	5.12	[1],[3]

[1] Includes derivative contracts, the benefits of which have been conveyed to the Mississippian Trust pursuant to the derivatives agreement with the Mississippian Trust. See Note 8 for a listing of open derivative contracts at June 30, 2011, the benefits and obligations of which were conveyed to the Mississippian Trust.

[2] Assumes ratio of 1:1 for Mcf to MMBtu.

[3] Includes 7,865 MMcf and 7,280 MMcf with contractual maturities in 2011 and 2012, respectively, that were settled in July 2011.

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Derivatives (Tables)

6 Months Ended

Jun. 30, 2011

Fair Value of Derivative Contracts

Fair Value of Derivatives. In accordance with ASC Topic 815, Derivatives and Hedging, the following table presents the fair value of the Company’s derivative contracts at June 30, 2011 and December 31, 2010 on a gross basis without regard to same-counterparty netting (in thousands):

Type of Contract	Balance Sheet Classification	June 30, 2011			December 31, 2010
Derivative assets
Oil price swaps	Derivative contracts-current	$	2,674		$	—
Natural gas price swaps	Derivative contracts-current		6,157			8,500
Oil price swaps	Derivative contracts-noncurrent		3,415			—
Natural gas price swaps	Derivative contracts-noncurrent		—			3,518
Derivative liabilities
Oil price swaps	Derivative contracts-current		(104,129	)		(63,123	)
Natural gas price swaps	Derivative contracts-current		(38	)		(640	)
Natural gas basis swaps	Derivative contracts-current		(41,973	)		(34,112	)
Interest rate swaps	Derivative contracts-current		(9,552	)		(9,007	)
Oil price swaps	Derivative contracts-noncurrent		(135,069	)		(84,055	)
Natural gas price swaps	Derivative contracts-noncurrent		—			(802	)
Natural gas basis swaps	Derivative contracts-noncurrent		(24,446	)		(34,908	)
Natural gas collars	Derivative contracts-noncurrent		(224	)		(238	)
Interest rate swap	Derivative contracts-noncurrent		(5,733	)		(7,687	)
Total derivative contracts, net		$	(308,918	)	$	(222,554	)

Cash Settlements and Valuation Gains and Losses on Commodity Derivative Contracts

The following table summarizes the effects of the Company’s derivative contracts on the accompanying condensed consolidated statements of operations for the three and six-month periods ended June 30, 2011 and 2010 (in thousands):

Type of Contract	Location of (Gain) Loss Recognized in Income	Amount of (Gain) Loss Recognized in Income
		Three Months Ended June 30,						Six Months Ended June 30,
		2011			2010			2011		2010
Oil and natural gas derivatives	(Gain) loss on derivative contracts	$	(169,988	)	$	(119,621	)	$	107,640	$	(181,573	)
Interest rate swaps	Interest expense		2,798			6,477			3,076		12,412
Total		$	(167,190	)	$	(113,144	)	$	110,716	$	(169,161	)

Open Oil and Natural Gas Commodity Derivative Contracts

On June 30, 2011, the Company’s open oil and natural gas commodity derivative contracts consisted of the following:

Oil Swaps

Period and Type of Contract(1)	Notional (MBbl)		Weighted Avg. Fixed Price
July 2011 — September 2011
Price swap contracts		2,301	$	86.89
October 2011 — December 2011
Price swap contracts		2,301	$	86.89
January 2012 — March 2012
Price swap contracts		2,388	$	87.98
April 2012 — June 2012
Price swap contracts		2,479	$	87.88
July 2012 — September 2012
Price swap contracts		2,536	$	87.85
October 2012 — December 2012
Price swap contracts		2,598	$	87.79
January 2013 — March 2013
Price swap contracts		2,168	$	93.09
April 2013 — June 2013
Price swap contracts		2,192	$	93.09
July 2013 — September 2013
Price swap contracts		2,216	$	93.09
October 2013 — December 2013
Price swap contracts		2,216	$	93.09
January 2014 — March 2014
Price swap contracts		493	$	101.07
April 2014 — June 2014
Price swap contracts		499	$	101.07
July 2014 — September 2014
Price swap contracts		504	$	101.07
October 2014 — December 2014
Price swap contracts		504	$	101.07
January 2015 — March 2015
Price swap contracts		295	$	100.45
April 2015 — June 2015
Price swap contracts		299	$	100.45
July 2015 — September 2015
Price swap contracts		302	$	100.45
October 2015 — December 2015
Price swap contracts		302	$	100.45

Natural Gas Swaps

Period and Type of Contract(1)	Notional (MMcf)(2)		Weighted Avg. Fixed Price
July 2011 — September 2011
Price swap contracts(3)		6,779	$	4.63
Basis swap contracts		26,220	$	(0.47	)
October 2011 — December 2011
Price swap contracts(3)		6,471	$	4.65
Basis swap contracts		26,220	$	(0.47	)
January 2012 — March 2012
Price swap contracts(3)		5,460	$	5.12
Basis swap contracts		28,210	$	(0.55	)
April 2012 — June 2012
Price swap contracts(3)		5,460	$	5.12
Basis swap contracts		28,210	$	(0.55	)
July 2012 — September 2012
Basis swap contracts		28,520	$	(0.55	)
October 2012 — December 2012
Basis swap contracts		28,520	$	(0.55	)
January 2013 — March 2013
Basis swap contracts		3,600	$	(0.46	)
April 2013 — June 2013
Basis swap contracts		3,640	$	(0.46	)
July 2013 — September 2013
Basis swap contracts		3,680	$	(0.46	)
October 2013 — December 2013
Basis swap contracts		3,680	$	(0.46	)

Natural Gas Collars

Period and Type of Contract(1)	Notional (MMcf)(2)		Collar Range
July 2012 — September 2012
Collars		201		4.00 - 6.20
October 2012 — December 2012
Collars		201		4.00 - 6.20
January 2013 — March 2013
Collars		212		4.00 - 7.15
April 2013 — June 2013
Collars		214		4.00 - 7.15
July 2013 — September 2013
Collars		216		4.00 - 7.15
October 2013 — December 2013
Collars		216		4.00 - 7.15
January 2014 — March 2014
Collars		231		4.00 - 7.78
April 2014 — June 2014
Collars		234		4.00 - 7.78
July 2014 — September 2014
Collars		236		4.00 - 7.78
October 2014 — December 2014
Collars		236		4.00 - 7.78
January 2015 — March 2015
Collars		249		4.00 - 8.55
April 2015 — June 2015
Collars		252		4.00 - 8.55
July 2015 — September 2015
Collars		255		4.00 - 8.55
October 2015 — December 2015
Collars		255		4.00 - 8.55

(1) Includes derivative contracts, the benefits of which have been conveyed to the Mississippian Trust pursuant to the derivatives agreement with the Mississippian Trust. See Note 8 for a listing of open derivative contracts at June 30, 2011, the benefits and obligations of which were conveyed to the Mississippian Trust.

(2) Assumes ratio of 1:1 for Mcf to MMBtu.

(3) Includes 7,865 MMcf and 7,280 MMcf with contractual maturities in 2011 and 2012, respectively, that were settled in July 2011.

Forward Contracts

Cash Settlements and Valuation Gains and Losses on Commodity Derivative Contracts

The following tables summarize the cash settlements and valuation gains and losses on our commodity derivative contracts and interest rate swaps for the three and six-month periods ended June 30, 2011 and 2010 (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
Oil and Natural Gas Derivatives	2011			2010			2011			2010
Realized loss (gain)(1)	$	18,273		$	(117,955	)	$	26,881		$	(160,548	)
Unrealized (gain) loss		(188,261	)		(1,666	)		80,759			(21,025	)
(Gain) loss on commodity derivative contracts	$	(169,988	)	$	(119,621	)	$	107,640		$	(181,573	)
	Three Months Ended June 30,						Six Months Ended June 30,
Interest Rate Swaps	2011			2010			2011			2010
Realized loss	$	2,442		$	2,076		$	4,485		$	4,163
Unrealized loss (gain)		356			4,401			(1,409	)		8,249
Loss on interest rate swaps	$	2,798		$	6,477		$	3,076		$	12,412

(1) Includes $25.8 million and $38.2 million of realized gains for the three and six-month periods ended June 30, 2011, respectively, related to settlements of commodity derivative contracts with contractual maturities after the quarterly period in which they were settled. Includes $62.4 million of realized gains for the three and six-month periods ended June 30, 2010, related to settlements of commodity derivative contracts with contractual maturities after June 30, 2010.

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Earnings Per Share

6 Months Ended

Jun. 30, 2011

Earnings Per Share

14. Earnings Per Share

Basic earnings per share are computed using the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average shares outstanding during the period, but also include the dilutive effect of awards of restricted stock and outstanding convertible preferred stock. The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings per share for the three and six-month periods ended June 30, 2011 and 2010 (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Weighted average basic common shares outstanding		398,435		203,839		398,343		203,831
Effect of dilutive securities
Restricted stock		7,414		4,231		—		4,152
Convertible preferred stock outstanding		90,133		51,496		—		18,423
Weighted average diluted common and potential common shares outstanding		495,982		259,566		398,343		226,406

For the six-month period ended June 30, 2011, restricted stock awards covering 7.3 million shares were excluded from the computation of net loss per share because their effect would have been antidilutive.

In computing diluted earnings per share, the Company evaluated the if-converted method with respect to its outstanding 8.5% convertible perpetual preferred stock, 6.0% convertible perpetual preferred stock and 7.0% convertible perpetual preferred stock for the three and six-month periods ended June 30, 2011 and its outstanding 8.5% convertible perpetual preferred stock and 6.0% convertible perpetual preferred stock for the three and six-month periods ended June 30, 2010. See Note 16 for discussion of the Company’s convertible preferred stock. Under the if-converted method, the Company assumes the conversion of the preferred stock to common stock and determines if this is more dilutive than including the preferred stock dividends (paid and unpaid) in the computation of income available to common stockholders. For the three-month period ended June 30, 2011, the Company determined the if-converted method was more dilutive and did not include the 6.0%, 8.5% or 7.0% preferred stock dividends in the determination of income available to common stockholders. For the six-month period ended June 30, 2011, the Company determined the if-converted method was not more dilutive and included preferred stock dividends in the determination of loss applicable to common stockholders. For the three-month period ended June 30, 2010, the Company determined the if-converted method was more dilutive and did not include the 6.0% and 8.5% preferred stock dividends in the determination of income available to common stockholders. For the six-month period ended June 30, 2010, the Company determined the if-converted method was more dilutive with respect to its 6.0% convertible perpetual preferred stock, but not more dilutive with respect to its 8.5% convertible perpetual preferred stock. As a result, the Company did not include the 6.0% preferred stock dividends, but did include the 8.5% preferred stock dividends in the determination of income available to common stockholders for the six-month period ended June 30, 2010.

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CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Current assets
Cash and cash equivalents	$ 4,615	$ 5,863
Accounts receivable, net	162,976	146,118
Derivative contracts	2,513	5,028
Inventories	7,571	3,945
Other current assets	12,897	14,636
Total current assets	190,572	175,590
Oil and natural gas properties, using full cost method of accounting
Proved	8,552,148	8,159,924
Unproved	624,668	547,953
Less: accumulated depreciation, depletion and impairment	(4,625,330)	(4,483,736)
Net oil and natural gas properties capitalized costs	4,551,486	4,224,141
Other property, plant and equipment, net	519,364	509,724
Restricted deposits	27,902	27,886
Goodwill	235,396	234,356
Other assets	71,954	59,751
Total assets	5,596,674	5,231,448
Current liabilities
Current maturities of long-term debt	1,019	7,293
Accounts payable and accrued expenses	423,971	376,922
Billings and estimated contract loss in excess of costs incurred	41,232	31,474
Derivative contracts	149,374	103,409
Asset retirement obligation	25,360	25,360
Total current liabilities	640,956	544,458
Long-term debt	2,892,434	2,901,793
Derivative contracts	162,057	124,173
Asset retirement obligation	93,780	94,517
Other long-term obligations	10,762	19,024
Total liabilities	3,799,989	3,683,965
Commitments and contingencies (Note 15)
Preferred stock, $0.001 par value, 50,000 shares authorized
Common stock, $0.001 par value, 800,000 shares authorized; 410,498 issued and 409,918 outstanding at June 30, 2011 and 406,830 issued and 406,360 outstanding at December 31, 2010	398	398
Additional paid-in capital	4,550,689	4,528,912
Treasury stock, at cost	(4,525)	(3,547)
Accumulated deficit	(3,109,725)	(2,989,576)
Total SandRidge Energy, Inc. stockholders' equity	1,436,845	1,536,195
Noncontrolling interest	359,840	11,288
Total equity	1,796,685	1,547,483
Total liabilities and equity	5,596,674	5,231,448
8.5% Convertible perpetual preferred stock
Preferred stock, $0.001 par value, 50,000 shares authorized
Preferred stock	3	3
6.0% Convertible perpetual preferred stock
Preferred stock, $0.001 par value, 50,000 shares authorized
Preferred stock	2	2
7.0% Convertible perpetual preferred stock
Preferred stock, $0.001 par value, 50,000 shares authorized
Preferred stock	$ 3	$ 3

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Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2011

Calculation of Weighted Average Common Shares Outstanding Used in the Computation of Diluted Earnings Per Share

convertible preferred stock. The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings per share for the three and six-month periods ended June 30, 2011 and 2010 (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Weighted average basic common shares outstanding		398,435		203,839		398,343		203,831
Effect of dilutive securities
Restricted stock		7,414		4,231		—		4,152
Convertible preferred stock outstanding		90,133		51,496		—		18,423
Weighted average diluted common and potential common shares outstanding		495,982		259,566		398,343		226,406

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Significant Transactions with Related Parties (Detail) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Related Party Transaction [Line Items]
Sales to and reimbursements from related parties	$ 6,947	$ 4,166	$ 11,735	$ 6,823
Accounts receivable due from related parties	$ 2,153		$ 2,153		$ 1,702

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Commitments and Contingencies - Additional Information (Detail) (USD $) In Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2010
Commitments and Contingencies Disclosure [Line Items]
Insurance recoveries from damages caused by the fire	$ 24.5
Damages sought by plaintiff in connection with the construction of a natural gas pipeline in West Texas	90.0
Allocated value oil and natural gas leases sold to Energen Resources Corporation		$ 4.0

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Estimated Fair Value, Based on Quoted Market Prices, and the Carrying Value of Senior Notes (Parenthetical) (Detail) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
9.875% Senior Notes due 2016
Long-term debt, Carrying value, discount	$ 11,881	$ 12,793
8.75% Senior Notes due 2020
Long-term debt, Carrying value, discount	$ 6,693	$ 6,943

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Open Oil and Natural Gas Commodity Derivative Contracts - Sand Ridge Mississippian Trust I (Parenthetical) (Detail)	6 Months Ended
	Jun. 30, 2010
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional amount, Mcf to MMBtu ratio	1:1 for Mcf to MMBtu

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Cash Settlements and Valuation Gains and Losses on Commodity Derivative Contracts and Interest Rate Swaps (Detail) (USD $) In Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2011		Jun. 30, 2010		Jun. 30, 2011		Jun. 30, 2010
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized (gain) loss					$ (79,350)		$ 12,776
Commodity derivative contracts
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss	18,273	[1]	(117,955)	[1]	26,881	[1]	(160,548)	[1]
Unrealized (gain) loss	(188,261)		(1,666)		80,759		(21,025)
(Gain) loss on derivative contracts	(169,988)		(119,621)		107,640		(181,573)
Interest rate swaps
Derivative Instruments, Gain (Loss) [Line Items]
Realized (gain) loss	2,442		2,076		4,485		4,163
Unrealized (gain) loss	356		4,401		(1,409)		8,249
(Gain) loss on derivative contracts	$ 2,798		$ 6,477		$ 3,076		$ 12,412

[1] Includes $25.8 million and $38.2 million of realized gains for the three and six-month periods ended June 30, 2011, respectively, related to settlements of commodity derivative contracts with contractual maturities after the quarterly period in which they were settled. Includes $62.4 million of realized gains for the three and six-month periods ended June 30, 2010, related to settlements of commodity derivative contracts with contractual maturities after June 30, 2010.

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Pro Forma Financial Information (Parenthetical) (Detail) (USD $) In Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2010	Jun. 30, 2010
Business Acquisition, Pro Forma Information [Line Items]
Reduction in tax expense related to the release of a portion of the valuation allowance on existing deferred tax assets	$ 454.5	$ 454.5

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Financial Assets and Liabilities Measured at Fair Value on a Recurring Basis (Detail) (Fair Value, Measurements, Recurring, USD $) In Thousands	Jun. 30, 2011		Dec. 31, 2010
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value	$ 35,323		$ 37,740
Liabilities measured at fair value	311,431		227,582
Fair Value Measurements Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value	32,810		32,712
Fair Value Measurements Level 1 | Restricted deposits
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value	27,902		27,886
Fair Value Measurements Level 1 | Other long-term assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value	4,908		4,826
Fair Value Measurements Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value	12,246		10,576
Liabilities measured at fair value	321,164		233,130
Fair Value Measurements Level 3 | Commodity derivative contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value	12,246		10,576
Liabilities measured at fair value	305,879		216,436
Fair Value Measurements Level 3 | Interest rate swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities measured at fair value	15,285		16,694
Netting
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value	(9,733)	[1]	(5,548)	[1]
Liabilities measured at fair value	(9,733)	[1]	(5,548)	[1]
Netting | Commodity derivative contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value	(9,733)	[1]	(5,548)	[1]
Liabilities measured at fair value	(9,733)	[1]	(5,548)	[1]
Restricted deposits
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value	27,902		27,886
Other long-term assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value	4,908		4,826
Commodity derivative contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value	2,513		5,028
Liabilities measured at fair value	296,146		210,888
Interest rate swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities measured at fair value	$ 15,285		$ 16,694

[1] Represents the impact of netting assets and liabilities with counterparties with which the right of offset exists.

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Other Asset (Detail) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Debt issuance costs, net of amortization	$ 56,662	$ 50,637
Investments	4,908	4,826
Other	10,384	4,288
Total other assets	$ 71,954	$ 59,751

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Equity (Tables)

6 Months Ended

Jun. 30, 2011

Preferred Stock

Equity

Preferred Stock. The following table presents information regarding the Company’s preferred stock (in thousands):

	June 30, 2011		December 31, 2010
Shares authorized		50,000		50,000
Shares outstanding at end of period
8.5% Convertible perpetual preferred stock		2,650		2,650
6.0% Convertible perpetual preferred stock		2,000		2,000
7.0% Convertible perpetual preferred stock		3,000		3,000

Common Stock

Equity

Common Stock. The following table presents information regarding the Company’s common stock (in thousands):

	June 30, 2011		December 31, 2010
Shares authorized		800,000		800,000
Shares outstanding at end of period		409,918		406,360
Shares held in treasury		580		470