SandRidge Energy (SD) 10-Q 2011 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended March 31, 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  x    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  x    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	x	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  x

The number of shares outstanding of the registrant’s common stock, par value $0.001 per share, as of the close of business on April 29, 2011, was 410,005,288.

SANDRIDGE ENERGY, INC.

FORM 10-Q

Quarter Ended March 31, 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	29
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	38
ITEM 4.	Controls and Procedures	40
PART II. OTHER INFORMATION
ITEM 1.	Legal Proceedings	41
ITEM 1A.	Risk Factors	41
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41
ITEM 6.	Exhibits	41

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, as well as the risk factors discussed 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.

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PART I. Financial Information

ITEM 1.Financial Statements

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except per share data)

	March 31, 2011			December 31, 2010
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	8,537		$	5,863
Accounts receivable, net		164,087			146,118
Derivative contracts		781			5,028
Inventories		4,278			3,945
Other current assets		21,112			14,636
Total current assets		198,795			175,590
Oil and natural gas properties, using full cost method of accounting
Proved		8,388,198			8,159,924
Unproved		571,447			547,953
Less: accumulated depreciation, depletion and impairment		(4,554,435	)		(4,483,736	)
		4,405,210			4,224,141
Other property, plant and equipment, net		506,629			509,724
Restricted deposits		27,876			27,886
Goodwill		235,182			234,356
Other assets		71,776			59,751
Total assets	$	5,445,468		$	5,231,448
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt	$	1,004		$	7,293
Accounts payable and accrued expenses		376,264			376,922
Billings and estimated contract loss in excess of costs incurred		32,243			31,474
Derivative contracts		234,059			103,409
Asset retirement obligation		25,360			25,360
Total current liabilities		668,930			544,458
Long-term debt		3,171,385			2,901,793
Derivative contracts		260,192			124,173
Asset retirement obligation		94,293			94,517
Other long-term obligations		9,409			19,024
Total liabilities		4,204,209			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 March 31, 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 March 31, 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 March 31, 2011 and December 31, 2010; aggregate liquidation preference of $300,000		3			3
Common stock, $0.001 par value, 800,000 shares authorized; 410,649 issued and 410,098 outstanding at March 31, 2011 and 406,830 issued and 406,360 outstanding at December 31, 2010		398			398
Additional paid-in capital		4,539,565			4,528,912
Treasury stock, at cost		(4,145	)		(3,547	)
Accumulated deficit		(3,305,860	)		(2,989,576	)
Total SandRidge Energy, Inc. stockholders’ equity		1,229,966			1,536,195
Noncontrolling interest		11,293			11,288
Total equity		1,241,259			1,547,483
Total liabilities and equity	$	5,445,468		$	5,231,448

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

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	Three Months Ended March 31,
	2011			2010
	(Unaudited)
Revenues
Oil and natural gas	$	266,942		$	169,585
Drilling and services		21,034			5,760
Midstream and marketing		22,258			27,988
Other		2,614			7,661
Total revenues		312,848			210,994
Expenses
Production		73,957			50,272
Production taxes		10,575			4,838
Drilling and services		15,041			7,209
Midstream and marketing		22,283			25,506
Depreciation and depletion — oil and natural gas		73,886			52,278
Depreciation and amortization — other		13,093			12,303
General and administrative		34,414			31,674
Loss (gain) on derivative contracts		277,628			(61,952	)
Gain on sale of assets		(201	)		(304	)
Total expenses		520,676			121,824
(Loss) income from operations		(207,828	)		89,170
Other income (expense)
Interest income		5			69
Interest expense		(59,443	)		(62,089	)
Loss on extinguishment of debt		(36,181	)		—
Other income, net		1,197			1,236
Total other expense		(94,422	)		(60,784	)
(Loss) income before income taxes		(302,250	)		28,386
Income tax expense		88			12
Net (loss) income		(302,338	)		28,374
Less: net income attributable to noncontrolling interest		6			1,138
Net (loss) income attributable to SandRidge Energy, Inc.		(302,344	)		27,236
Preferred stock dividends		13,940			8,631
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders	$	(316,284	)	$	18,605
(Loss) earnings per share
Basic	$	(0.79	)	$	0.09
Diluted	$	(0.79	)	$	0.09
Weighted average number of common shares outstanding
Basic		398,251			203,823
Diluted		398,251			207,892

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

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(In thousands)

	SandRidge Energy, Inc. Stockholders
	Convertible Perpetual Preferred Stock
										Additional Paid-In Capital
					Common Stock								Treasury Stock			Accumulated Deficit			Noncontrolling Interest			Total
	Shares		Amount		Shares			Amount
										(Unaudited)
Three months ended March 31, 2011
Balance, December 31, 2010		7,650	$	8		406,360		$	398	$	4,528,912		$	(3,547	)	$	(2,989,576	)	$	11,288		$	1,547,483
Distributions to noncontrolling interest owners		—		—		—			—		—			—			—			(1	)		(1	)
Stock issuance expense		—		—		—			—		(143	)		—			—			—			(143	)
Purchase of treasury stock		—		—		—			—		—			(4,809	)		—			—			(4,809	)
Retirement of treasury stock		—		—		—			—		(4,809	)		4,809			—			—			—
Stock purchases — retirement plans, net of distributions		—		—		(81	)		—		1,389			(598	)		—			—			791
Stock-based compensation		—		—		—			—		14,206			—			—			—			14,206
Stock-based compensation excess tax benefit		—		—		—			—		10			—			—			—			10
Issuance of restricted stock awards, net of cancellations		—		—		3,819			—		—			—			—			—			—
Net (loss) income		—		—		—			—		—			—			(302,344	)		6			(302,338	)
Convertible perpetual preferred stock dividends		—		—		—			—		—			—			(13,940	)		—			(13,940	)
Balance, March 31, 2011		7,650	$	8		410,098		$	398	$	4,539,565		$	(4,145	)	$	(3,305,860	)	$	11,293		$	1,241,259

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

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Three Months Ended March 31,
	2011			2010
	(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income	$	(302,338	)	$	28,374
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Provision for doubtful accounts		2			84
Depreciation, depletion and amortization		86,979			64,581
Debt issuance costs amortization		2,873			2,218
Discount amortization on long-term debt		575			519
Loss on extinguishment of debt		36,181			—
Unrealized loss (gain) on derivative contracts		267,254			(15,511	)
Gain on sale of assets		(201	)		(304	)
Investment income		(150	)		(427	)
Stock-based compensation		8,806			6,882
Changes in operating assets and liabilities		(20,224	)		61,186
Net cash provided by operating activities		79,757			147,602
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment		(431,382	)		(190,580	)
Proceeds from sale of assets		159,536			5,606
Refunds of restricted deposits		—			5,095
Net cash used in investing activities		(271,846	)		(179,879	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings		1,493,000			273,343
Repayments of borrowings		(1,230,272	)		(232,023	)
Premium on debt redemption		(28,795	)		—
Dividends paid — preferred		(18,130	)		(11,263	)
Noncontrolling interest distributions		(1	)		(4	)
Stock issuance expense		(143	)		(87	)
Stock-based compensation excess tax benefit		10			12
Purchase of treasury stock		(5,469	)		(2,770	)
Derivative settlements		3,662			—
Debt issuance costs		(19,099	)		(221	)
Net cash provided by financing activities		194,763			26,987
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		2,674			(5,290	)
CASH AND CASH EQUIVALENTS, beginning of year		5,863			7,861
CASH AND CASH EQUIVALENTS, end of period	$	8,537		$	2,571
Supplemental Disclosure of Noncash Investing and Financing Activities
Change in accrued capital expenditures	$	(11,222	)	$	38,001
Convertible perpetual preferred stock dividends payable	$	9,185		$	5,814
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.

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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 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 for the majority of expected 2011 through 2013 oil production are in place, fixed price swap contracts are in place for only a portion of expected 2011 and 2012 natural gas production and 2014 and 2015 oil production. 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 Company’s 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.

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 (“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.

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3. Acquisitions and Divestitures

Arena Acquisition.On July 16, 2010, the Company acquired all of the outstanding common stock of Arena Resources, Inc. (the “Arena Acquisition”). In connection with the acquisition, the Company issued 4.7771 shares of its common stock and paid $4.50 in cash to Arena Resources, Inc. (“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 $0.4 million and $0.6 million in fees related to the acquisition during the three-month periods ended March 31, 2011 and 2010, respectively, which have been included in general and administrative expenses in the accompanying condensed consolidated statements of operations.

The allocation of the purchase price as of July 16, 2010, including updates made in the fourth quarter of 2010 and first quarter of 2011, is still preliminary with respect to final deferred tax amounts, pending completion of the 2010 Arena tax return, and certain accruals, and is based on information that was available to management at the time these condensed consolidated financial statements were prepared. During the fourth quarter of 2010 and first quarter of 2011, the Company updated certain of the estimates used in the purchase price allocation, primarily with respect to deferred taxes and other accruals for which the Company was awaiting confirmatory information, resulting in adjustments of ($5.4) million and $0.8 million, respectively, to goodwill. The Company believes the estimates used are reasonable and the significant effects of the transaction are properly reflected. However, the estimates, primarily the amounts related to deferred taxes, are subject to change as additional information becomes available and is assessed by the Company. Additional changes to the purchase price allocation could result in a change to goodwill. Changes to the deferred tax amounts in the purchase price allocation would result in a corresponding change in the release of the Company’s valuation allowance and corresponding income tax expense.

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

Current assets	$	83,411
Oil and natural gas properties(1)		1,587,630
Other property, plant and equipment		5,963
Long-term deferred tax assets		27,425
Other long-term assets		16,181
Goodwill(2)		235,182
Total assets acquired		1,955,792
Current liabilities		45,584
Long-term deferred tax liability(2)		474,925
Other long-term liabilities		8,851
Total liabilities assumed		529,360
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 preliminary purchase price allocation, a step-up in basis related to the property acquired from Arena resulted in a net deferred tax liability of approximately $447.5 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.

The following unaudited pro forma results of operations are provided for the three-month period ended March 31, 2010 as though the Arena Acquisition had been completed as of the beginning of the period. The pro forma information is based on the Company’s consolidated results of operations for the three-month period ended March 31, 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 months ended March 31, 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 preliminary 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 period presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost

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savings or other synergies that resulted from the acquisition or any estimated costs that have been or will be 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 March 31, 2010
	Actual		Pro Forma
	(Unaudited)
Revenues	$	210,994	$	262,792
Income available to SandRidge Energy, Inc. common stockholders(1)	$	18,605	$	477,711
Earnings per common share
Basic	$	0.09	$	1.21
Diluted	$	0.09	$	1.08

(1) Pro forma column reflects a $447.5 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. The transaction closed on January 6, 2011.

Sale of New Mexico Assets. In February 2011, the Company entered into an agreement to sell 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. The transaction closed on April 1, 2011.

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 March 31, 2011 or December 31, 2010.

Level 1 Fair Value Measurements

Restricted deposits. The fair value of restricted deposits is based on quoted market prices.

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 swaps are based upon quotes obtained from counterparties to the derivative contracts. The Company

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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):

March 31, 2011

	Fair Value Measurements						Netting(1)			Assets/ Liabilities  at Fair Value
Description	Level 1		Level 2		Level 3
Assets
Commodity derivative contracts	$	—	$	—	$	3,649	$	(2,868	)	$	781
Restricted deposits		27,876		—		—		—			27,876
Other long-term assets		4,965		—		—		—			4,965
	$	32,841	$	—	$	3,649	$	(2,868	)	$	33,622
Liabilities
Commodity derivative contracts	$	—	$	—	$	482,190	$	(2,868	)	$	479,322
Interest rate swaps		—		—		14,929		—			14,929
	$	—	$	—	$	497,119	$	(2,868	)	$	494,251

December 31, 2010

	Fair Value Measurements						Netting(1)			Assets/ Liabilities  at Fair Value
Description	Level 1		Level 2		Level 3
Assets
Commodity derivative contracts	$	—	$	—	$	10,576	$	(5,548	)	$	5,028
Restricted deposits		27,886		—		—		—			27,886
Other long-term assets		4,826		—		—		—			4,826
	$	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 table below sets 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-month periods ended March 31, 2011 and 2010 (in thousands):

	Three Months Ended March 31,
	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		(277,628	)		(278	)		(277,906	)		61,952			(5,935	)		56,017
Purchases		(3,662	)		—			(3,662	)		—			—			—
Settlements		8,609			2,043			10,652			(42,593	)		2,087			(40,506	)
Balance of Level 3, March 31	$	(478,541	)	$	(14,929	)	$	(493,470	)	$	65,512		$	(12,147	)	$	53,365

During the three-month periods ended March 31, 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.

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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 March 31, 2011 and December 31, 2010 were as follows (in thousands):

	March 31, 2011				December 31, 2010
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Floating Rate Notes due 2014	$	347,045	$	350,000	$	334,751	$	350,000
8.625% Senior Notes due 2015		37,554		35,776		663,181		650,000
9.875% Senior Notes due 2016(1)		411,686		353,157		394,527		352,707
8.0% Senior Notes due 2018		792,934		750,000		762,849		750,000
8.75% Senior Notes due 2020(2)		495,017		443,181		472,968		443,057
7.5% Senior Notes due 2021		937,485		900,000		—		—

(1) Carrying value is net of $12,343 and $12,793 discount at March 31, 2011 and December 31, 2010, respectively.

(2) Carrying value is net of $6,819 and $6,943 discount at March 31, 2011 and December 31, 2010, respectively.

The carrying values of the Company’s senior credit facility and remaining fixed rate debt instrument approximate fair value based on current rates applicable to similar instruments. See Note 11 for further discussion of the Company’s long-term debt, including the partial tender of the 8.625% Senior Notes due 2015 and the issuance of the 7.5% Senior Notes due 2021, which occurred during the three months ended March 31, 2011.

5. Property, Plant and Equipment

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

	March 31, 2011			December 31, 2010
Oil and natural gas properties
Proved	$	8,388,198		$	8,159,924
Unproved		571,447			547,953
Total oil and natural gas properties		8,959,645			8,707,877
Less accumulated depreciation, depletion and impairment		(4,554,435	)		(4,483,736	)
Net oil and natural gas properties capitalized costs		4,405,210			4,224,141
Land		14,418			14,418
Non oil and natural gas equipment(1)		662,563			666,233
Buildings and structures		93,945			89,813
Total		770,926			770,464
Less accumulated depreciation and amortization		(264,297	)		(260,740	)
Net capitalized costs		506,629			509,724
Total property, plant and equipment, net	$	4,911,839		$	4,733,865

(1) Includes capitalized interest of approximately $4.8 million and $4.7 million at March 31, 2011 and December 31, 2010, respectively.

There were no full cost ceiling impairments during either the three months ended March 31, 2011 or 2010. Cumulative full cost ceiling limitation impairment charges of $3,548.3 million at both March 31, 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 March 31, 2011, the Company had $235.2 million of goodwill, including the effects of the $0.8 million and ($5.4) million purchase price adjustments recorded in the first quarter of 2011 and fourth quarter of 2010, respectively, as a result of the excess consideration over the fair value of Arena net assets acquired on July 16, 2010. 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 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 information on 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 March 31, 2011, no such indicators were noted. Goodwill recognized will not be deductible for tax purposes.

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7. Other Assets

Other assets consist of the following (in thousands):

	March 31, 2011		December 31, 2010
Debt issuance costs, net of amortization	$	59,477	$	50,637
Investments		4,965		4,826
Other		7,334		4,288
Total other assets	$	71,776	$	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.

Grey Ranch Plant, 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% ownership 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.

At March 31, 2011 and December 31, 2010, consolidated amounts related to GRLP included assets of $23.1 million and $21.1 million, respectively, and liabilities of $0.3 million and $0.4 million, respectively. GRLP’s assets can be used to settle its own obligations and not other obligations 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 both March 31, 2011 and December 31, 2010, $11.3 million of noncontrolling interest in the accompanying condensed consolidated balance sheets was related to GRLP. GRLP’s creditors have no recourse to the general credit of the Company.

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.

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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 CO₂treatment 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.

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 has 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 $32.2 million and $31.5 million at March 31, 2011 and December 31, 2010, respectively, are reported as current liabilities in the accompanying condensed consolidated balance sheets.

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 March 31, 2011 is as follows (in thousands):

Asset retirement obligation, December 31, 2010	$	119,877
Liability incurred upon acquiring and drilling wells		1,197
Sales of reserves in place		(3,046	)
Liability settled in current period		(800	)
Accretion of discount expense		2,425
Asset retirement obligation, March 31, 2011		119,653
Less: current portion		25,360
Asset retirement obligation, net of current	$	94,293

11. Long-Term Debt

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

	March 31, 2011		December 31, 2010
Senior credit facility	$	323,500	$	340,000
Other notes payable:
Drilling rig fleet and related oil field services equipment		—		6,302
Mortgage		16,775		17,020
Senior Floating Rate Notes due 2014		350,000		350,000
8.625% Senior Notes due 2015		35,776		650,000
9.875% Senior Notes due 2016, net of $12,343 and $12,793 discount, respectively		353,157		352,707
8.0% Senior Notes due 2018		750,000		750,000
8.75% Senior Notes due 2020, net of $6,819 and $6,943 discount, respectively		443,181		443,057
7.5% Senior Notes due 2021		900,000		—
Total debt		3,172,389		2,909,086
Less: current maturities of long-term debt		1,004		7,293
Long-term debt	$	3,171,385	$	2,901,793

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For the three-month periods ended March 31, 2011 and 2010, interest payments were approximately $53.4 million and $9.0 million, respectively. Interest paid for the three-month period ended March 31, 2011 includes $24.1 million of accrued interest paid in connection with the partial redemption of the 8.625% Senior Notes due 2015. See further discussion 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 its Senior Secured Leverage Ratio 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.

As of March 31, 2011, the senior credit facility contained financial covenants, including maintaining agreed levels for the (i) ratio of total funded debt to EBITDAX, 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 EBITDAX is less than 1.5:1.0, calculated using the last four completed fiscal quarters (in each case 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 EBITDAX, which may not exceed 2.0:1.0 at each quarter end, calculated using the last four completed fiscal quarters (adjusted for annualized amounts of the post-acquisition results of operations of Arena). As of and during the three-month period ended March 31, 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 higher 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 2.73% and 2.26% for the three-month periods ended March 31, 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

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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. 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 three-month period ended March 31, 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.

In April 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.

At March 31, 2011, the Company had $323.5 million outstanding under the senior credit facility and $34.3 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 and $0.1 million of accrued interest and prepayment penalties.

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, 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.

The Senior Floating Rate Notes bear interest at LIBOR plus 3.625% (3.93% at March 31, 2011). Interest is payable quarterly with the principal due on April 1, 2014. The average interest rates paid on the outstanding Senior Floating Rate Notes for the three-month periods ended March 31, 2011 and 2010 were 3.93% and 3.88%, 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 March 31, 2011, the Company had two $350.0 million notional interest rate swap agreements to fix the variable interest rate on the Senior Floating Rate Notes through April 1, 2013. The first interest rate swap agreement serves to fix the rate on the Senior Floating Rate Notes at an annual rate of 6.26% through April 1, 2011. The second interest rate swap agreement 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. The two interest rate swaps effectively serve to fix the Company’s variable interest rate on its Senior Floating Rate Notes for the majority of the term of these notes. These swaps have not been designated as hedges.

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. The premium paid to purchase these notes and the unamortized debt issuance costs associated with the tendered portion of the notes, totaling $36.2 million, were recorded as a loss on extinguishment of debt in the accompanying condensed consolidated statements of operations. The loss does not meet the criteria for classification as an extraordinary item. On April 1, 2011, the Company redeemed the remaining $35.8 million aggregate principal amount of 8.625% Senior Notes. See Note 18 for additional information on the redemption of the remaining 8.625% Senior Notes.

The $10.4 million of debt issuance costs associated with the Senior Floating Rate Notes and the 8.625% Senior Notes that remained outstanding at March 31, 2011 are included in other assets in the accompanying condensed consolidated balance sheets and are 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,

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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. 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 $881.2 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 $18.8 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-month period ended March 31, 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 interest rate swaps, at fair value. Changes in derivative contract fair values are recognized in earnings. Cash settlements and valuation gains and losses are included in loss (gain) on derivative contracts for the commodity derivative contracts and in interest expense for the interest rate swaps in the consolidated statement of operations. Commodity derivative contracts are settled on a monthly basis. Settlements on the 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.

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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 March 31, 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.

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 two interest rate swap agreements 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. See Note 11 for further discussion of the Company’s interest rate swaps.

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 March 31, 2011 and December 31, 2010 on a gross basis without regard to same-counterparty netting (in thousands):

Type of Contract	Balance Sheet Classification	March 31, 2011			December 31, 2010
Derivative assets
Natural gas price swaps	Derivative contracts-current	$	1,705		$	8,500
Oil price swaps	Derivative contracts-noncurrent		197			—
Natural gas price swaps	Derivative contracts-noncurrent		1,747			3,518
Derivative liabilities
Oil price swaps	Derivative contracts-current		(185,906	)		(63,123	)
Natural gas price swaps	Derivative contracts-current		(746	)		(640	)
Natural gas basis swaps	Derivative contracts-current		(39,014	)		(34,112	)
Interest rate swaps	Derivative contracts-current		(9,317	)		(9,007	)
Oil price swaps	Derivative contracts-noncurrent		(224,723	)		(84,055	)
Natural gas price swaps	Derivative contracts-noncurrent		(76	)		(802	)
Natural gas basis swaps	Derivative contracts-noncurrent		(31,113	)		(34,908	)
Natural gas collars	Derivative contracts-noncurrent		(612	)		(238	)
Interest rate swaps	Derivative contracts-noncurrent		(5,612	)		(7,687	)
Total derivative contracts, net		$	(493,470	)	$	(222,554	)

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

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The following table summarizes the effect of the Company’s derivative contracts on the accompanying condensed consolidated statements of operations for the three-month periods ended March 31, 2011 and 2010 (in thousands):

		Three Months Ended March 31,
Type of Contract	Location of Loss (Gain) Recognized in Income
		2011		2010
Oil and natural gas derivatives	Loss (gain) on derivative contracts	$	277,628	$	(61,952	)
Interest rate swaps	Interest expense		278		5,935
Total		$	277,906	$	(56,017	)

The following tables summarize the cash settlements and valuation gains and losses on our commodity derivative contracts and interest rate swaps for the three-month periods ended March 31, 2011 and 2010 (in thousands):

	Three Months Ended March 31,
Oil and Natural Gas Derivatives	2011			2010
Realized loss (gain)(1)	$	8,609		$	(42,593	)
Unrealized loss (gain)		269,019			(19,359	)
Loss (gain) on commodity derivative contracts	$	277,628		$	(61,952	)
Interest Rate Swaps
Realized loss	$	2,043		$	2,087
Unrealized (gain) loss		(1,765	)		3,848
Loss on interest rate swaps	$	278		$	5,935

(1) Includes $12.4 million of realized gains for the three-month period ended March 31, 2011 related to settlements of commodity derivative contracts with contractual maturities after March 31, 2011. There were no commodity derivative contracts settled prior to the contractual maturity during the three-month period ended March 31, 2010.

On March 31, 2011, the Company’s open oil and natural gas commodity derivative contracts consisted of the following:

Oil Swaps

Period and Type of Contract	Notional (in MBbl)		Weighted Avg. Fixed Price
April 2011 — June 2011
Price swap contracts		2,094	$	87.19
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		2,438	$	93.99
April 2013 — June 2013
Price swap contracts		2,465	$	93.99
July 2013 — September 2013
Price swap contracts		2,492	$	93.99
October 2013 — December 2013
Price swap contracts		2,492	$	93.99
January 2014 — March 2014
Price swap contracts		133	$	100.94
April 2014 — June 2014
Price swap contracts		135	$	100.94
July 2014 — September 2014
Price swap contracts		136	$	100.94
October 2014 — December 2014
Price swap contracts		136	$	100.94
January 2015 — March 2015
Price swap contracts		115	$	101.07
April 2015 — June 2015
Price swap contracts		117	$	101.07
July 2015 — September 2015
Price swap contracts		118	$	101.07
October 2015 — December 2015
Price swap contracts		118	$	101.07

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Natural Gas Swaps

Period and Type of Contract	Notional (MMcf)(1)		Weighted Avg. Fixed Price
April 2011 — June 2011
Price swap contracts(2)		9,100	$	4.58
Basis swap contracts		25,935	$	(0.47	)
July 2011 — September 2011
Price swap contracts(2)		11,379	$	4.61
Basis swap contracts		26,220	$	(0.47	)
October 2011 — December 2011
Price swap contracts(2)		11,071	$	4.62
Basis swap contracts		26,220	$	(0.47	)
January 2012 — March 2012
Price swap contracts(2)		10,465	$	5.11
Basis swap contracts		28,210	$	(0.55	)
April 2012 — June 2012
Price swap contracts(2)		9,100	$	5.09
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	Notional (MMcf)(1)		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) Assumes ratio of 1:1 for Mcf to MMBtu.

(2) Includes 12,250 MMcf and 8,645 MMcf with contractual maturities in 2011 and 2012, respectively, that were settled in April 2011.

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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 provision for income taxes consisted of the following components for the three-month periods ended March 31, 2011 and 2010 (in thousands):

	Three Months Ended March 31,
	2011		2010
Current
Federal	$	21	$	—
State		67		12
		88		12
Deferred
Federal		—		—
State		—		—
		—		—
Total provision		88		12
Less: income tax provision attributable to noncontrolling interest		2		—
Total provision attributable to SandRidge Energy, Inc.	$	86	$	12

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. For the three-month period ended March 31, 2011, the Company continued to have a full valuation allowance against its net deferred tax asset resulting in a low effective tax rate for the period.

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 $307.9 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 $307.9 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 $488.8 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 March 31, 2011 or December 31, 2010.

As of March 31, 2011, the Company had a liability of approximately $1.50 million for unrecognized tax benefits. If recognized, approximately $0.98 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.

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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 $0.05 million of accrued gross interest with respect to unrecognized tax benefits in its condensed consolidated statement of operations for the three-month period ended March 31, 2011. The Company did not recognize any interest and penalties related to unrecognized tax benefits during the three-month period ended March 31, 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 periods ended March 31, 2011 and 2010, income tax payments, net of refunds, were approximately $1.0 million and ($3.4) million, respectively.

14. Earnings (Loss) 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-month periods ended March 31, 2011 and 2010 (in thousands):

	Three Months Ended March 31,
	2011		2010
Weighted average basic common shares outstanding		398,251		203,823
Effect of dilutive securities:
Restricted stock		—		4,069
Convertible preferred stock outstanding		—		—
Weighted average diluted common and potential common shares outstanding		398,251		207,892

For the three-month period ended March 31, 2011, restricted stock awards covering 7.2 million shares were excluded from the computation of 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-month period ended March 31, 2011 and its outstanding 8.5% convertible perpetual preferred stock and 6.0% convertible perpetual preferred stock for the three-month period ended March 31, 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 periods ended March 31, 2011 and 2010, the Company determined the if-converted method was not more dilutive and included preferred stock dividends in the determination of (loss applicable) income available to common stockholders.

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 $20.1 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 and November 10, 2010, 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 a 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.

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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. 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.

16. Equity

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

	March 31, 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 March 31, 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 ($3.7 million paid and $1.9 million unpaid) and $5.6 million in dividends ($2.8 million paid and $2.8 million unpaid) on the 8.5% convertible perpetual preferred stock have been included in the Company’s earnings per share calculations for the three-month periods ended March 31, 2011 and 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 ($1.0 million paid and $2.0 million unpaid) and $3.0 million in dividends (all unpaid) on the 6.0% convertible perpetual preferred stock have been included in the Company’s earnings per share calculations for the three-month periods ended March 31, 2011 and 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

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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. Approximately $5.3 million in unpaid dividends on the 7.0% convertible perpetual preferred stock has been included in the Company’s earnings per share calculations for the three-month period ended March 31, 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):

	March 31, 2011		December 31, 2010
Shares authorized		800,000		800,000
Shares outstanding at end of period		410,098		406,360
Shares held in treasury		551		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 603,000 shares with a total value of $4.8 million and approximately 261,000 shares with a total value of $2.8 million during the three-month periods ended March 31, 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 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 of time, subject to certain conditions. Awards issued prior to 2006 had vesting periods of one, four or seven years. 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-month periods ended March 31, 2011 and 2010, the Company recognized stock-based compensation expense of $8.2 million and $6.9 million, net of $1.8 million and $1.2 million capitalized, respectively, related to restricted common stock awards.

Noncontrolling Interest. Noncontrolling interests in one of the Company’s subsidiaries and a variable interest entity in 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.

The following table presents a reconciliation of the activity for noncontrolling interest in entities included in the consolidated results of the Company for the three-month periods ended March 31, 2011 and 2010 (in thousands):

	Three Months Ended March 31,
	2011			2010
Beginning balance, December 31	$	11,288		$	10,052
Distributions to noncontrolling interest owners		(1	)		(4	)
Net income attributable to noncontrolling interest		6			1,138
Ending balance, March 31	$	11,293		$	11,186

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17. Related Party Transactions

The Company enters into transactions in the ordinary course of business with certain of its stockholders and other 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 March  31,
	2011		2010
Sales to and reimbursements from related parties	$	4,789	$	6,613
Purchases from related parties	$	—	$	2,176
	March 31, 2011		December 31, 2010
Accounts receivable due from related parties	$	1,603	$	1,702
Accounts payable due to related parties	$	—	$	800

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.

18. Subsequent Events

Events occurring after March 31, 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.

Redemption of 8.625% Senior Notes. 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 Company will recognize an additional loss on extinguishment of debt of approximately $2.0 million in the second quarter of 2011, which represents the premium paid to redeem these remaining outstanding notes, and the remaining unamortized debt issuance costs associated with the notes.

SandRidge Mississippian Trust I.On April 12, 2011, SandRidge Mississippian Trust I (the “Trust”), a newly formed Delaware statutory trust, announced the closing of its initial public offering of 17,250,000 common units representing beneficial interests in the Trust. Net proceeds to the Trust, before offering expenses, were approximately $338.7 million, which were delivered to the Company as partial consideration for the conveyance of the royalty interests held by 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. The Company intends to use the net proceeds from the offering to repay borrowings under the senior credit facility and for general corporate purposes.

SandRidge and one of its wholly owned subsidiaries entered into a development agreement with the 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 Trust a drilling support 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. The Company entered into an administrative services agreement with the Trust pursuant to which the Company will provide certain administrative services to the Trust. The Company and the Trust entered into a derivatives agreement, effective April 1, 2011, to pass along to the Trust the benefits and obligations of certain of the Company’s derivative contracts.

The Company has determined that its equity interest in the Trust constitutes a variable interest, that the Trust is a variable interest entity and that the Company is the primary beneficiary of the Trust. As a result, the Company will consolidate the activities of the Trust into its results beginning in April 2011. In consolidation, the common units of the Trust owned by third parties will be reflected as noncontrolling interest.

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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 land 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 table (in thousands):

	Exploration  and Production			Drilling and Oil Field Services			Midstream  Gas Services			All Other			Consolidated Total
Three Months Ended March 31, 2011
Revenues	$	267,237		$	67,549		$	55,978		$	3,220		$	393,984
Inter-segment revenue		(67	)		(46,515	)		(34,038	)		(516	)		(81,136	)
Total revenues	$	267,170		$	21,034		$	21,940		$	2,704		$	312,848
Operating loss	$	(184,207	)	$	(108	)	$	(2,528	)	$	(20,985	)	$	(207,828	)
Interest income (expense), net		105			(105	)		(172	)		(59,266	)		(59,438	)
Loss on extinguishment of debt		—			—			—			(36,181	)		(36,181	)
Other income (expense), net		1,676			—			(701	)		222			1,197
Loss before income taxes	$	(182,426	)	$	(213	)	$	(3,401	)	$	(116,210	)	$	(302,250	)
Capital expenditures(1)	$	403,087		$	6,763		$	4,172		$	6,138		$	420,160
Depreciation, depletion and amortization	$	74,472		$	7,730		$	1,097		$	3,680		$	86,979
At March 31, 2011
Total assets	$	4,795,614		$	228,158		$	162,449		$	259,247		$	5,445,468
Three Months Ended March 31, 2010
Revenues	$	170,184		$	86,074		$	82,537		$	10,453		$	349,248
Inter-segment revenue		(65	)		(80,314	)		(55,011	)		(2,864	)		(138,254	)
Total revenues	$	170,119		$	5,760		$	27,526		$	7,589		$	210,994
Operating income (loss)	$	110,023		$	(4,301	)	$	1,254		$	(17,806	)	$	89,170
Interest income (expense), net		79			(313	)		(138	)		(61,648	)		(62,020	)
Other income, net		768			—			—			468			1,236
Income (loss) before income taxes	$	110,870		$	(4,614	)	$	1,116		$	(78,986	)	$	28,386
Capital expenditures(1)	$	192,077		$	9,417		$	20,422		$	6,665		$	228,581
Depreciation, depletion and amortization	$	52,993		$	7,330		$	876		$	3,382		$	64,581
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 8.625% Senior Notes, Senior Floating Rate Notes and 8.75% Senior Notes. 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

26

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 a variable interest entity 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

	March 31, 2011
	Parent		Guarantors		Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	802	$	686	$	7,049	$	—		$	8,537
Accounts and notes receivable, net		1,389,642		160,530		407,712		(1,793,797	)		164,087
Derivative contracts		—		781		—		—			781
Other current assets		—		20,596		4,794		—			25,390
Total current assets		1,390,444		182,593		419,555		(1,793,797	)		198,795
Property, plant and equipment, net		—		4,815,118		96,721		—			4,911,839
Investment in subsidiaries		3,023,080		68,763		—		(3,091,843	)		—
Goodwill		—		235,182		—		—			235,182
Other assets		59,477		40,175		—		—			99,652
Total assets	$	4,473,001	$	5,341,831	$	516,276	$	(4,885,640	)	$	5,445,468
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	70,984	$	1,668,526	$	430,551	$	(1,793,797	)	$	376,264
Derivative contracts		9,317		224,742		—		—			234,059
Asset retirement obligation		—		25,360		—		—			25,360
Other current liabilities		—		32,243		1,004		—			33,247
Total current liabilities		80,301		1,950,871		431,555		(1,793,797	)		668,930
Long-term debt		3,155,614		—		15,771		—			3,171,385
Derivative contracts		5,612		254,580		—		—			260,192
Asset retirement obligation		—		94,122		171		—			94,293
Other liabilities		1,508		7,901		—		—			9,409
Total liabilities		3,243,035		2,307,474		447,497		(1,793,797	)		4,204,209
Equity		1,229,966		3,034,357		68,779		(3,091,843	)		1,241,259
Total liabilities and equity	$	4,473,001	$	5,341,831	$	516,276	$	(4,885,640	)	$	5,445,468
	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

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Condensed Consolidating Statements of Operations

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Three Months Ended March 31, 2011
Total revenues	$	—		$	309,296		$	14,481		$	(10,929	)	$	312,848
Expenses
Direct operating expenses		—			119,226			13,212			(10,783	)		121,655
General and administrative		85			33,734			741			(146	)		34,414
Depreciation, depletion, amortization and impairment		—			85,240			1,739			—			86,979
Loss on derivative contracts		—			277,628			—			—			277,628
Total expenses		85			515,828			15,692			(10,929	)		520,676
Loss from operations		(85	)		(206,532	)		(1,211	)		—			(207,828	)
Equity earnings from subsidiaries		(206,987	)		(1,237	)		—			208,224			—
Interest expense, net		(59,007	)		(173	)		(258	)		—			(59,438	)
Loss on extinguishment of debt		(36,181	)		—			—			—			(36,181	)
Other income, net		—			955			242			—			1,197
Loss before income taxes		(302,260	)		(206,987	)		(1,227	)		208,224			(302,250	)
Income tax expense		84			—			4			—			88
Net loss		(302,344	)		(206,987	)		(1,231	)		208,224			(302,338	)
Less: net income attributable to noncontrolling interest		—			—			6			—			6
Net loss attributable to SandRidge Energy, Inc.	$	(302,344	)	$	(206,987	)	$	(1,237	)	$	208,224		$	(302,344	)
Three Months Ended March 31, 2010
Total revenues	$	—		$	199,284		$	63,275		$	(51,565	)	$	210,994
Expenses
Direct operating expenses		—			82,642			56,238			(51,359	)		87,521
General and administrative		77			30,968			835			(206	)		31,674
Depreciation, depletion, amortization and impairment		—			62,925			1,656			—			64,581
Gain on derivative contracts		—			(61,952	)		—			—			(61,952	)
Total expenses		77			114,583			58,729			(51,565	)		121,824
(Loss) income from operations		(77	)		84,701			4,546			—			89,170
Equity earnings from subsidiaries		88,701			3,136			—			(91,837	)		—
Interest expense, net		(61,376	)		(372	)		(272	)		—			(62,020	)
Other income, net		—			1,236			—			—			1,236
Income before income taxes		27,248			88,701			4,274			(91,837	)		28,386
Income tax expense		12			—			—			—			12
Net income		27,236			88,701			4,274			(91,837	)		28,374
Less: net income attributable to noncontrolling interest		—			—			1,138			—			1,138
Net income attributable to SandRidge Energy, Inc.	$	27,236		$	88,701		$	3,136		$	(91,837	)	$	27,236

Condensed Consolidating Statements of Cash Flows

	Parent			Guarantors			Non-Guarantors			Eliminations		Consolidated
	(In thousands)
Three Months Ended March 31, 2011
Net cash (used in) provided by operating activities	$	(198,288	)	$	274,331		$	3,714		$	—	$	79,757
Net cash used in investing activities		—			(271,569	)		(277	)		—		(271,846	)
Net cash provided by (used in) financing activities		197,649			(2,640	)		(246	)		—		194,763
Net (decrease) increase in cash and cash equivalents		(639	)		122			3,191			—		2,674
Cash and cash equivalents at beginning of year		1,441			564			3,858			—		5,863
Cash and cash equivalents at end of period	$	802		$	686		$	7,049		$	—	$	8,537
Three Months Ended March 31, 2010
Net cash (used in) provided by operating activities	$	(31,065	)	$	180,425		$	(1,758	)	$	—	$	147,602
Net cash used in investing activities		—			(179,351	)		(528	)		—		(179,879	)
Net cash provided by (used in) financing activities		30,881			(3,660	)		(234	)		—		26,987
Net decrease in cash and cash equivalents		(184	)		(2,586	)		(2,520	)		—		(5,290	)
Cash and cash equivalents at beginning of year		339			2,841			4,681			—		7,861
Cash and cash equivalents at end of period	$	155		$	255		$	2,161		$	—	$	2,571

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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 our business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with our condensed consolidated financial statements and the accompanying notes included in this Quarterly Report, as well as our audited consolidated financial statements and the accompanying notes included in the 2010 Form 10-K. Our discussion and analysis relates to the following subjects:

• Overview of Our Company

• Recent Developments

• Recently Adopted Accounting Pronouncements

• Results by Segment

• Consolidated Results of Operations

• Liquidity and Capital Resources

The financial information with respect to the three-month periods ended March 31, 2011 and March 31, 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 Our Company

We are an independent oil and natural gas company concentrating on development and production activities related to the exploitation of our significant holdings in West Texas and the Mid-Continent area of Oklahoma and Kansas. Our primary areas of focus are the Permian Basin in West Texas, the Mississippian formation in the Mid-Continent and the West Texas Overthrust (“WTO”). We also own and operate other interests in the Mid-Continent, Cotton Valley Trend in East Texas, Gulf Coast and Gulf of Mexico. In 2009, we began expanding the oil component of our 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 our holdings in the Permian Basin area. Concurrent with our Permian Basin acquisitions, we focused on increasing oil production in the Mid-Continent by significantly growing our property base in the area.

We operate businesses that are complementary to our development and production activities. We own 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 our 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 our own account are eliminated in consolidation and, therefore, do not directly contribute to our consolidated results of operations.

We currently generate the majority of our consolidated revenues and cash flow from the production and sale of oil and natural gas. Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas and on our 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 our exposure to these fluctuations, we enter into derivative commodity contracts for a portion of our anticipated future oil and natural gas production. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital expenditure programs.

Recent Developments

Wolfberry and New Mexico Asset Sales.In January 2011, we sold our Wolfberry assets in the Permian Basin for $153.8 million, net of fees and subject to post-closing adjustments. This transaction closed on January 6, 2011. In February 2011, we entered into an agreement to sell 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 transaction closed on April 1, 2011.

Tender Offer for 8.625% Senior Notes.On March 1, 2011, we announced a cash tender offer to repurchase any and all of the then-outstanding $650.0 million aggregate principal amount of our 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, we had purchased approximately 94.5%, or $614.2 million, of the

29

aggregate principal amount of the 8.625% Senior Notes pursuant to the tender offer, which expired on March 28, 2011. The premium paid to purchase these notes along with the unamortized debt issuance costs associated with the tendered portion of the notes, totaling $36.2 million, was recorded as a loss on extinguishment of debt. On April 1, 2011, we redeemed the remaining outstanding $35.8 million aggregate principal amount of our 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. We will recognize an additional loss on extinguishment of debt of approximately $2.0 million in the second quarter of 2011, which represents the premium paid to redeem these remaining outstanding notes and the remaining unamortized debt issuance costs associated with the notes.

Issuance of 7.5% Senior Notes. In March 2011, we issued $900.0 million of unsecured 7.5% Senior Notes to qualified institutional buyers under Rule 144A of the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. Net proceeds from the offering were approximately $881.2 million after deducting offering expenses. We used such proceeds 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 completion of the tender offer (each as described above) and to repay borrowings under our 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 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 our wholly owned subsidiaries.

Change to Borrowing Base on Senior Credit Facility.On March 15, 2011, the borrowing base under our senior credit facility was reduced from $850.0 million to $790.0 million as a result of the issuance of the 7.5% Senior Notes. This $790.0 million borrowing base was reaffirmed in conjunction with the April 2011 amendment of the senior credit facility.

SandRidge Mississippian Trust I.On April 12, 2011, SandRidge Mississippian Trust I (the “Trust”), a newly formed Delaware statutory trust, announced the closing of its initial public offering of 17,250,000 common units representing beneficial interests in the Trust. Net proceeds to the Trust, before offering expenses, were approximately $338.7 million, which we received as partial consideration for the conveyance of the royalty interests held by the Trust. Concurrent with the closing, we 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 we lease in the Mississippian formation in five counties in Northern Oklahoma. We intend to use the net proceeds from the offering to repay borrowings under the senior credit facility and for general corporate purposes.

SandRidge and one of its wholly owned subsidiaries entered into a development agreement with the Trust that obligates us 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, we will have until December 31, 2015 to fulfill our drilling obligation. One of our wholly owned subsidiaries also granted to the Trust a drilling support lien in our 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. We entered into an administrative services agreement with the Trust pursuant to which we will provide certain administrative services to the Trust. We also entered into a derivatives agreement, effective April 1, 2011, with the Trust to pass along to the Trust the benefits and obligations of certain of our derivative contracts.

Recently Adopted Accounting Pronouncements

In January 2010, 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 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. The implementation of ASU 2010-06 had no impact on our financial position or results of operations.

Results by Segment

We operate 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 our reportable segments, including our CO₂ gathering and sales operations and corporate operations. Management evaluates the performance of our 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 us about the activity and profitability of our lines of business. Set forth in the table below is financial information regarding our business segments for the three month-periods ended March 31, 2011 and 2010 (in thousands).

30

	Exploration  and Production			Drilling and Oil Field Services			Midstream  Gas Services			All Other			Consolidated Total
Three Months Ended March 31, 2011
Revenues	$	267,237		$	67,549		$	55,978		$	3,220		$	393,984
Inter-segment revenue		(67	)		(46,515	)		(34,038	)		(516	)		(81,136	)
Total revenues	$	267,170		$	21,034		$	21,940		$	2,704		$	312,848
Operating loss	$	(184,207	)	$	(108	)	$	(2,528	)	$	(20,985	)	$	(207,828	)
Interest income (expense), net		105			(105	)		(172	)		(59,266	)		(59,438	)
Loss on extinguishment of debt		—			—			—			(36,181	)		(36,181	)
Other income (expense), net		1,676			—			(701	)		222			1,197
Loss before income taxes	$	(182,426	)	$	(213	)	$	(3,401	)	$	(116,210	)	$	(302,250	)
Three Months Ended March 31, 2010
Revenues	$	170,184		$	86,074		$	82,537		$	10,453		$	349,248
Inter-segment revenue		(65	)		(80,314	)		(55,011	)		(2,864	)		(138,254	)
Total revenues	$	170,119		$	5,760		$	27,526		$	7,589		$	210,994
Operating income (loss)	$	110,023		$	(4,301	)	$	1,254		$	(17,806	)	$	89,170
Interest income (expense), net		79			(313	)		(138	)		(61,648	)		(62,020	)
Other income, net		768			—			—			468			1,236
Income (loss) before income taxes	$	110,870		$	(4,614	)	$	1,116		$	(78,986	)	$	28,386

Exploration and Production Segment

The primary factors affecting the financial results of our exploration and production segment are the prices we receive for our oil and natural gas production, the quantity of oil and natural gas we produce and changes in the fair value of commodity derivative contracts we use to reduce the volatility of the prices we receive for our oil and natural gas production. Quarterly comparisons of production and price data are presented in the table below. Changes in our results for these periods reflect the strategic movement toward increased oil production, including the acquisition of oil and natural gas properties from Arena in July 2010, which increased production volumes and associated oil and natural gas revenues.

	Three Months Ended March 31,				Change
	2011		2010		Amount			Percent
Production data
Oil (MBbls)(1)		2,581		1,211		1,370			113.1	%
Natural gas (MMcf)		17,266		19,057		(1,791	)		(9.4	)%
Combined equivalent volumes (MBoe)		5,459		4,387		1,072			24.4	%
Average daily combined equivalent volumes (MBoe/d)		61		49		12			24.5	%
Average prices — as reported(2)
Oil (per Bbl)(1)	$	79.76	$	66.50	$	13.26			19.9	%
Natural gas (per Mcf)	$	3.54	$	4.67	$	(1.13	)		(24.2	)%
Combined equivalent (per Boe)	$	48.90	$	38.64	$	10.26			26.6	%
Average prices — including impact of derivative contract settlements
Oil (per Bbl)(1)	$	72.26	$	69.09	$	3.17			4.6	%
Natural gas (per Mcf)	$	3.44	$	6.75	$	(3.31	)		(49.0	)%
Combined equivalent (per Boe)	$	45.05	$	48.36	$	(3.31	)		(6.8	)%

(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 March 31, 2011 compared to the three months ended March 31, 2010

Exploration and production segment revenues increased $97.1 million, or 57.0%, to $267.2 million in the three months ended March 31, 2011 from $170.1 million in the three months ended March 31, 2010, as a result of a 113.1% increase in oil production and a 19.9% increase in the average price we received for our oil production. These increases were slightly offset by the 9.4% decrease in natural gas production and a 24.2% decrease in the average price received for our 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. Properties acquired from Arena produced 872 MBbls of oil for the three-month period ended March 31, 2011. The decrease in natural gas production was a result of the decline in the number of rigs drilling for natural gas during 2010 due to depressed natural gas prices.

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The average price received for our oil production increased 19.9%, or $13.26 per barrel, to $79.76 per barrel during the three months ended March 31, 2011 from $66.50 per barrel during the same period in 2010. The average price received for our natural gas production for the three-month period ended March 31, 2010 decreased 24.2%, or $1.13 per Mcf, to $3.54 per Mcf from $4.67 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 March 31, 2011 was $72.26 per Bbl compared to $69.09 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 March 31, 2011 was $3.44 per Mcf compared to $6.75 per Mcf during the same period in 2010. Our 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 March 31, 2011, the exploration and production segment reported a $277.6 million net loss on our commodity derivative positions ($8.6 million realized loss and $269.0 million unrealized loss) compared to a $62.0 million net gain on our commodity derivative positions ($42.6 million realized gain and $19.4 million unrealized gain) in the same period in 2010. The realized loss for the three months ended March 31, 2011 was primarily due to higher oil prices at the time of settlement compared to the contract price. Realized gains totaling $12.4 million resulting from settlements of commodity derivative contracts with original contractual maturities after March 31, 2011 were included in the net realized loss for the three months ended March 31, 2011. The realized gain of $42.6 million for the three months ended March 31, 2010 was primarily due to lower natural gas prices at the time of settlement compared to the contract price. Unrealized gains or losses on derivative contracts represent the change in fair value of open derivative contracts during the period. The unrealized loss on our commodity contracts recorded during the three months ended March 31, 2011 was primarily attributable to an increase in average oil prices at March 31, 2011 compared to the average oil prices at December 31, 2010 or the contract price for contracts entered into during the first quarter of 2011. The unrealized gain for the three-month period ended March 31, 2010 was attributable to decreased average natural gas prices, offset by decreases in the price differentials on our basis swaps at March 31, 2010.

For the three months ended March 31, 2011, we had an operating loss of $184.2 million in our exploration and production segment compared to operating income of $110.0 million for the same period in 2010. The $97.4 million increase in oil and natural gas revenues was more than offset by a $23.7 million increase in production expenses, a $21.6 million increase in depreciation and depletion on oil and natural gas properties and the $277.6 million net loss recorded on our commodity derivative contracts during the three months ended March 31, 2011. See discussion of production expense and depreciation and depletion under “Consolidated Results of Operations.”

Drilling and Oil Field Services Segment

The financial results of our drilling and oil field services segment depend primarily on demand and the price we can charge for our services. In addition to providing drilling services, our oil field services business also conducts operations that complement our 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 we operate, are included in drilling and services revenues and expenses while drilling and oil field service revenues earned and expenses incurred in performing services for our own account are eliminated in consolidation.

As of March 31, 2011, we owned 31 drilling rigs. The table below presents a summary of our rigs as of March 31, 2011 and 2010:

	March 31,
Rigs	2011		2010
Working for SandRidge		20		21
Working for third parties		11		2
Idle		—		3
Total operational		31		26
Non-operational(1)		—		4
Total rigs		31		30

(1) Includes four rigs being equipped for operation at March 31, 2010.

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Drilling and Oil Field Services Segment — Three months ended March 31, 2011 compared to the three months ended March 31, 2010

Drilling and oil field services segment revenues increased to $21.0 million in the three-month period ended March 31, 2011 from $5.8 million in the three-month period ended March 31, 2010 and drilling and oil field services segment expenses increased $11.0 million to $21.1 million during the same period. The increase in revenue resulted in a reduced operating loss of $0.1 million in the three-month period ended March 31, 2011 compared to $4.3 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 our rigs and the result of additional rigs becoming available in West Texas as we decreased our drilling activity in the WTO in 2010 and transitioned to drilling more oil wells in the Permian Basin and Mid-Continent areas.

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 we charge related to gathering, compressing and treating 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 we charge to gather, compress and treat the natural gas. In general, natural gas purchased and sold by our midstream gas business is priced at a published daily or monthly index price. The primary factors affecting the results of our midstream gas services segment are the quantity of natural gas we gather, treat and market and the prices we pay and receive for natural gas.

We own and operate two gas treating plants in West Texas, which remove CO₂ from natural gas production and deliver residue gas to nearby pipelines. During the first quarter of 2011, we continued with the operational assessment phase of the Century Plant, in Pecos County, Texas, including treating some of our natural gas at this plant during the quarter. As a result of this assessment, in April 2011, the Century Plant was taken off line to resolve certain operational issues. We are now in the process of diverting our high CO₂ natural gas production back through the Century Plant and anticipate commencing performance testing for Train 1 of the Century Plant during the second quarter of 2011. Upon successful completion of the performance testing, the use of our two gas treating plants in West Texas may be limited, the extent of which will depend on variables, including the expected need for such plants to back up the Century Plant going forward. During the second quarter of 2011, we will evaluate our gas treating plants for impairment in connection with completion of the operational assessment phase of Train I of the Century Plant.

Midstream Gas Services Segment — Three months ended March 31, 2011 compared to the three months ended March 31, 2010

Midstream gas services segment revenues for the three months ended March 31, 2011 were $21.9 million compared to $27.5 million in the same period in 2010. The decrease in revenue and relatively flat expenses resulted in an operating loss of $2.5 million for the three months ended March 31, 2011 compared to operating income of $1.3 million for the comparable period in 2010. The decrease in revenue was due to a decrease in third party volumes we marketed, a decrease in natural gas prices and a decrease in natural gas volumes processed in our gas treating plants in the three-month period ended March 31, 2011 compared to the same period in 2010.

Consolidated Results of Operations

Three months ended March 31, 2011 compared to the three months ended March 31, 2010

Revenues.Total revenues increased 48.3% for the three months ended March 31, 2011 from the same period in 2010. This increase was primarily due to the increase in oil and natural gas sales.

	Three Months Ended March 31,
	2011		2010		$ Change			% Change
	(In thousands)
Revenues
Oil and natural gas	$	266,942	$	169,585	$	97,357			57.4	%
Drilling and services		21,034		5,760		15,274			265.2	%
Midstream and marketing		22,258		27,988		(5,730	)		(20.5	)%
Other		2,614		7,661		(5,047	)		(65.9	)%
Total revenues	$	312,848	$	210,994	$	101,854			48.3	%

Total oil and natural gas revenues increased $97.4 million for the three months ended March 31, 2011 compared to the same period in 2010, primarily as a result of an increase in the amount of oil we produced and the price received for our oil production, offset slightly by a decrease in the amount of natural gas we produced as well as decreased prices received for our natural gas production. The 1,370 MBbl increase in oil production was primarily due to the properties acquired from Arena and our focus on increased oil drilling throughout 2010 and into 2011. The average price received for our oil production, excluding the impact of derivative contracts, increased 19.9% in the 2011 period to $79.76 per Bbl compared to $66.50 per Bbl in 2010.

Drilling and services revenues increased $15.3 million for the three months ended March 31, 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.

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Midstream and marketing revenues decreased $5.7 million, or 20.5%, in the three-month period ended March 31, 2011 compared to the three-month period ended March 31, 2010. The decrease in midstream and marketing revenues was attributable to a decrease in third party volumes we marketed due to decreased natural gas production, a decrease in natural gas prices and a decrease in natural gas volumes processed in our gas treating plants in the three-month period ended March 31, 2011 compared to the same period in 2010.

Other revenues decreased $5.0 million for the three months ended March 31, 2011 from $7.7 million for the same period in 2010. The decrease was due to lower CO₂ volumes sold to third parties from our gas treating plants during the three-month period ended March 31, 2011 compared to the same period in 2010 as a result of less natural gas treated at these plants.

Operating Costs and Expenses. Total operating costs and expenses increased to $520.7 million for the three months ended March 31, 2011 compared to $121.8 million for the same period in 2010. The increase was primarily due to increases in production expenses and depreciation and depletion on oil and natural gas properties and the loss on derivative contracts.

	Three Months Ended March 31,
	2011			2010			$ Change			% Change
	(In thousands)
Operating costs and expenses
Production	$	73,957		$	50,272		$	23,685			47.1	%
Production taxes		10,575			4,838			5,737			118.6	%
Drilling and services		15,041			7,209			7,832			108.6	%
Midstream and marketing		22,283			25,506			(3,223	)		(12.6	)%
Depreciation and depletion — oil and natural gas		73,886			52,278			21,608			41.3	%
Depreciation and amortization — other		13,093			12,303			790			6.4	%
General and administrative		34,414			31,674			2,740			8.7	%
Loss (gain) on derivative contracts		277,628			(61,952	)		339,580			(548.1	)%
Gain on sale of assets		(201	)		(304	)		103			(33.9	)%
Total operating costs and expenses	$	520,676		$	121,824		$	398,852			327.4	%

Production expenses include the costs associated with our exploration and production activities, including, but not limited to, lease operating expenses and treating costs. Production expenses increased $23.7 million primarily due to the addition of operating expenses associated with properties acquired from Arena. Additionally, higher production costs were incurred on oil production compared to production costs on natural gas volumes. Oil production increased 1,370 MBbls in the three-month period ended March 31, 2011 compared to the same period in 2010.

Production taxes increased $5.7 million, or 118.6%, due to taxes on increased oil production, including taxes for production from properties acquired from Arena, and a decrease in the amount of high-cost gas severance tax refunds received in the three-month period ended March 31, 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 our CO₂ services companies, increased $7.8 million or 108.6% for the three months ended March 31, 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 March 31, 2011 compared to the same period in 2010.

Midstream and marketing expenses decreased $3.2 million, or 12.6%, to $22.3 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 March 31, 2011.

Depreciation and depletion for our oil and natural gas properties increased $21.6 million for the three-month period ended March 31, 2011 from the same period in 2010. The increase was primarily due to an increase in our depreciation and depletion per Boe to $13.53 in the first quarter of 2011 from $11.92 per Boe in the comparable period in 2010 as a result of an increase to our depreciable oil and natural gas properties, primarily due to the acquisition of properties from Arena.

We recorded a net loss of $277.6 million ($8.6 million realized loss and $269.0 million unrealized loss) on our commodity derivative contracts for the three-month period ended March 31, 2011 compared to a net gain of $62.0 million ($42.6 million realized gain and $19.4 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 increased to $94.4 million in the three-month period ended March 31, 2011 compared to $60.8 million for the same period in 2010. The increase is reflected in the table below.

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	Three Months Ended March 31,
	2011			2010			$ Change			% Change
	(In thousands)
Other income (expense)
Interest income	$	5		$	69		$	(64	)		(92.8	)%
Interest expense		(59,443	)		(62,089	)		2,646			(4.3	)%
Loss on extinguishment of debt		(36,181	)		—			(36,181	)		(100.0	)%
Other income, net		1,197			1,236			(39	)		(3.2	)%
Total other expense		(94,422	)		(60,784	)		(33,638	)		55.3	%
(Loss) income before income taxes		(302,250	)		28,386			(330,636	)		(1,164.8	)%
Income tax expense		88			12			76			633.3	%
Net (loss) income	$	(302,338	)	$	28,374		$	(330,712	)		(1,165.5	)%

Interest expense decreased to $59.4 million for the three months ended March 31, 2011 from $62.1 million for the same period in 2010. This decrease was primarily attributable to a $5.6 million decrease in the net loss on our interest rate swaps for the three-month period ending March 31, 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 three months ending March 31, 2011.

In connection with the tender offer to repurchase our 8.625% Senior Notes, we recognized a loss on extinguishment of debt of $36.2 million for the notes tendered prior to March 31, 2011. The loss represents the premium paid to purchase these notes and the unamortized debt issuance costs associated with the tendered notes.

For the three-month periods ended March 31, 2011 and 2010, we continued to have a low effective tax rate due to a full valuation allowance against our net deferred tax asset.

Liquidity and Capital Resources

Our primary sources of liquidity and capital resources are cash flow generated from operations, borrowings under our senior credit facility, the issuance of equity and debt securities and proceeds from sales or other monetization of assets. As described in “Recent Developments,” we received proceeds of $338.7 million in April 2011 as partial consideration for conveyance of royalty interests on certain of our oil and natural gas properties to the Trust. Our primary uses of capital are expenditures related to our oil and natural gas properties and other fixed assets, the acquisition of oil and natural gas properties, the repayment of amounts outstanding on our senior credit facility, the payment of dividends on our outstanding convertible perpetual preferred stock and interest payments on our outstanding debt. We maintain access to funds that may be needed to meet capital funding requirements through our senior credit facility.

Working Capital

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

At March 31, 2011, we had a working capital deficit of $470.1 million compared to a deficit of $368.9 million at December 31, 2010. Current assets increased $23.2 million at March 31, 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. Current liabilities increased $124.5 million, primarily due to a $130.7 million increase in the liability positions on our current derivative contracts, resulting primarily from an increase in average oil prices compared to the contract price at March 31, 2011.

We expect to fund our planned capital expenditures budget, debt service requirements and working capital needs for 2011 based on cash flow from operating activities, availability under our senior credit facility, potential access to the capital markets and anticipated proceeds from sales or other monetizations of assets. In April 2011, we received net proceeds of $338.7 million as partial consideration for the conveyance of royalty interests to the Trust. See “Recent Developments” for discussion of the Trust.

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Cash Flows

Our cash flows for the three months ended March 31, 2011 and 2010 were as follows:

	Three Months Ended March 31,
	2011			2010
	(In thousands)
Cash flows provided by operating activities	$	79,757		$	147,602
Cash flows used in investing activities		(271,846	)		(179,879	)
Cash flows provided by financing activities		194,763			26,987
Net increase (decrease) in cash and cash equivalents	$	2,674		$	(5,290	)

Cash Flows from Operating Activities

Our operating cash flow is mainly influenced by the prices we receive for our oil and natural gas production; the quantity of oil and natural gas we produce; third-party demand for our drilling rigs and oil field services and the rates we are able to charge for these services; and the margins we obtain from our natural gas and CO₂ gathering and treating contracts.

Net cash provided by operating activities for the three months ended March 31, 2011 and 2010 was $79.8 million and $147.6 million, respectively. The decrease in cash provided by operating activities was primarily due to an increase in accounts receivable resulting from an increase in oil production and a decrease in accounts payable due to payments made on outstanding invoices. This was partially offset by the increase in oil production and prices we received for our oil production.

Cash Flows from Investing Activities

We dedicate and expect to continue to dedicate a substantial portion of our 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 $271.8 million in the three-month period ended March 31, 2011 from $179.9 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. Our capital expenditures, on an accrual basis, by segment for the three-month periods ended March 31, 2011 and 2010 are summarized below:

	Three Months Ended March 31,
	2011		2010
	(In thousands)
Capital Expenditures
Exploration and production	$	403,087	$	192,077
Drilling and oil field services		6,763		9,417
Midstream gas services		4,172		20,422
Other		6,138		6,665
Total	$	420,160	$	228,581

Cash Flows from Financing Activities

Our financing activities provided $194.8 million in cash for the three-month period ended March 31, 2011 compared to $27.0 million in the comparable period in 2010. Cash provided by financing activities during the three months ended March 31, 2011 was primarily comprised of $881.2 million of net proceeds from the issuance of our 7.5% Senior Notes, offset by the redemption of $614.2 million of our 8.625% Senior Notes, the premium of $28.8 million paid in connection with our tender offer for our 8.625% Senior Notes, $16.5 million of net repayments under our senior credit facility and payment of dividends on our 8.5% and 6.0% convertible perpetual preferred stock.

Indebtedness

Senior Credit Facility.The amount we may borrow under our 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 our 7.5% Senior Notes. The borrowing base is determined based upon the discounted present value of future cash flows attributable to our proved reserves. Because the value of our proved reserves is a key factor in determining the amount of the borrowing base, changing commodity prices and our 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.

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On February 23, 2011, our 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 us, (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 us to net against our 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 our Senior Secured Leverage Ratio is less than 1.5:1.0 then compliance with our 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.

As of March 31, 2011, the senior credit facility contained financial covenants, including maintaining agreed levels for the (i) ratio of total funded debt to EBITDAX, 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 our secured indebtedness to EBITDAX is less than 1.5:1.0, calculated using the last four completed fiscal quarters (in each case 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 our derivative contracts are disregarded) and (iii) ratio of our secured indebtedness to EBITDAX, which may not exceed 2.0:1.0 at each quarter end calculated using the last four completed fiscal quarters (adjusted for annualized amounts of the post-acquisition results of operations of Arena). We remain in compliance with all financial covenants under the senior credit facility.

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

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

Long-term obligations under the senior credit facility, senior notes and other long-term debt consist of the following at March 31, 2011 (in thousands):

Senior credit facility	$	323,500
Other notes payable		16,775
Senior Floating Rate Notes due 2014		350,000
8.625% Senior Notes due 2015		35,776
9.875% Senior Notes due 2016, net of $12,343 discount		353,157
8.0% Senior Notes due 2018		750,000
8.75% Senior Notes due 2020, net of $6,819 discount		443,181
7.5% Senior Notes due 2021		900,000
Total debt	$	3,172,389

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.

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	$	746
2012		1,051
2013		1,120
2014		674,691
2015		1,266
Thereafter		2,476,901
Total debt	$	3,155,775

The table above does not include the $35.8 million aggregate principal amount of our outstanding 8.625% Senior Notes at March 31, 2011, as these were redeemed on April 1, 2011. For more information about the senior credit facility, the senior notes and our other long-term debt obligations, see Note 11 to the condensed consolidated financial statements included in this Quarterly Report.

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Outlook

For 2011, we have budgeted $1.3 billion for capital expenditures, including expenditures related to our drilling obligation under the development agreement with the Trust, excluding acquisitions. The majority of our capital expenditures are discretionary and could be curtailed if our cash flows decline from expected levels or if we are unable to obtain capital on attractive terms. We 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.

Our 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 our 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. Our derivative arrangements serve to mitigate a portion of the effect of this price volatility on our cash flows, and while derivative contracts for the majority of expected 2011 through 2013 oil production are in place, fixed price swap contracts are in place for only a portion of expected 2011 and 2012 natural gas production and 2014 and 2015 oil production. No fixed price swap contracts are in place for our natural gas production beyond 2012 or oil production beyond 2015. We have 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 our derivative contracts. We have, and will have to continue to incur, capital expenditures to achieve production targets contained in certain gathering and treating arrangements. We are dependent on the availability of borrowings under our 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 our senior credit facility, potential access to the capital markets and anticipated proceeds from the sales or other monetizations of assets, we expect to be able to fund our 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 our financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced, which could adversely impact our ability to comply with the financial covenants under our senior credit facility, which in turn would limit further borrowings to fund capital expenditures. We have the ability to reduce our capital expenditures budget if cash flows are not available.

We may choose to refinance borrowings outstanding under our senior credit facility by issuing long-term debt or equity in the public or private markets, or both. In addition, we may from time to time seek to retire or purchase our outstanding securities through cash purchases and/or exchanges in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.

As of March 31, 2011, our cash and cash equivalents were $8.5 million and we had approximately $3.2 billion in total debt outstanding with $323.5 million outstanding under our senior credit facility. As of and for the three-month period ended March 31, 2011, we were in compliance with all of the covenants under all of our senior notes and our senior credit facility. As of May 3, 2011, our cash and cash equivalents were approximately $62.4 million, we had no amounts outstanding under our senior credit facility and we had $24.3 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 we use 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. Our most significant market risk relates to the prices we receive for our oil and natural gas production. Due to the historical volatility of these commodities, we periodically have entered into, and expect in the future to enter into, derivative arrangements for the purpose of reducing the variability of oil and natural gas prices we receive for our production. From time to time, we enter into commodity pricing derivative contracts for a portion of our anticipated production volumes depending upon management’s view of opportunities under the then prevailing current market conditions. Our senior credit facility limits our ability to enter into derivative transactions to 85% of expected production volumes from estimated proved reserves. We do not intend to enter into derivative contracts that would exceed our expected production volumes for the period covered by the derivative arrangement. Future credit facilities could require a minimum level of commodity price hedging.

We use, and may continue to use, a variety of commodity-based derivative contracts, including fixed price swaps, collars and basis protection swaps. Our oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period. Our natural gas fixed price swap transactions are settled based upon New York Mercantile Exchange prices, and our 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. Our 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.

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

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

The following table summarizes the cash settlements and valuation gains and losses on our commodity derivative contracts for the three-month periods ended March 31, 2011 and 2010 (in thousands):

	Three Months Ended March 31,
	2011		2010
Realized loss (gain)(1)	$	8,609	$	(42,593	)
Unrealized loss (gain)		269,019		(19,359	)
Loss (gain) on commodity derivative contracts	$	277,628	$	(61,952	)

(1) Includes $12.4 million of realized gains for the three-month period ended March 31, 2011 related to settlements of commodity derivative contracts with contractual maturities after March 31, 2011. There were no commodity derivative contracts settled prior to the contractual maturity during the three-month period ended March 31, 2010.

Credit Risk. The use of derivative contracts involves the risk that the counterparties will be unable to meet their obligations under the contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. As of March 31, 2011, we had 18 approved derivative counterparties, all of which are lenders under our senior credit facility. We currently have derivative contracts outstanding with 15 of these counterparties. We periodically review the credit quality of each counterparty to our derivative contracts and the level of overall financial exposure we have to each counterparty to limit our credit risk exposure with respect to these contracts. Additionally, we apply a credit default risk rating factor for our counterparties in determining the fair value of our derivative contracts. The counterparties for all of our derivative transactions have an “investment grade” credit rating.

Our ability to fund our capital expenditure budget is partially dependent upon the availability of funds under our senior credit facility. In order to mitigate the credit risk associated with individual financial institutions committed to participate in our senior credit facility, our bank group currently consists of 27 financial institutions with commitments ranging from 0.57% to 5.41%.

Interest Rate Risk. We are subject to interest rate risk on our long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to (i) changes in market interest rates reflected in the fair value of the debt and (ii) the risk that we may need to refinance maturing debt with new debt at a higher rate. Variable rate debt, where the interest rate fluctuates, exposes us to short-term changes in market interest rates as our 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, we may enter into derivative transactions to fix the interest we pay on a portion of the money we borrow under our credit agreement. At March 31, 2011, we had two $350.0 million notional interest rate swap agreements to fix the variable interest rate on the Senior Floating Rate Notes through April 1, 2013. The first interest rate swap agreement fixes the rate on the Senior Floating Rate Notes at an annual rate of 6.26% through April 1, 2011. The second interest rate swap agreement fixes 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. The two interest rate swaps effectively serve to fix the variable interest rate on our Senior Floating Rate Notes for the majority of the term of these notes. These swaps have not been designated as hedges.

Our interest rate swaps reduce our market risk on our Senior Floating Rate Notes. We use sensitivity analyses to determine the impact that market risk exposures could have on our variable interest rate borrowings if not for our interest rate swaps. Based on the $350.0 million outstanding balance of our Senior Floating Rate Notes at March 31, 2011, a one percent change in the applicable rates, with all other variables held constant, would have resulted in a change in our interest expense of approximately $0.9 million for the three-month period ended March 31, 2011.

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The following table summarizes the cash settlements and valuation gains and losses on our interest rate swaps for the three-month periods ended March 31, 2011 and 2010 (in thousands):

	Three Months Ended March 31,
	2011			2010
Realized loss	$	2,043		$	2,087
Unrealized (gain) loss		(1,765	)		3,848
Loss on interest rate swaps	$	278		$	5,935

ITEM 4.Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we performed an evaluation of the effectiveness of the design and operation of our 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, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2011 to provide reasonable assurance that the information required to be disclosed by us in our 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 our internal control over financial reporting during the quarter ended March 31, 2011 that has materially affected, or is reasonably likely to materially affect, our 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, we are not currently involved in any legal proceedings that, individually or in the aggregate, could have a material effect on our financial condition, operations or cash flows.

ITEM 1A. Risk Factors

There has been no material change to the risk factors previously discussed in Item 1A – Risk Factors in our 2010 Form 10-K.

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

As part of our restricted stock program, we make required tax payments on behalf of employees when their stock awards vest and then withhold 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 March 31, 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
January 1, 2011 — January 31, 2011		568,468	$	7.80	N/A	N/A
February 1, 2011 — February 28, 2011		2,642	$	9.18	N/A	N/A
March 1, 2011 — March 31, 2011		32,224	$	10.83	N/A	N/A

ITEM 6. Exhibits

See the Exhibit Index accompanying this Quarterly Report.

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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: May 9, 2011

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EXHIBIT INDEX

		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date	Filed Herewith
1.1	Underwriting Agreement, dated April 6, 2011, by and among SandRidge Energy, Inc., SandRidge Mississippian Trust I, and Raymond James & Associates, Inc. and Morgan Stanley & Co. Incorporated, as representatives of the several Underwriters	8-K	001-33784	1.1	04/08/2011
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
4.1	Indenture, dated as of March 15, 2011, by and among SandRidge Energy, Inc., certain subsidiary guarantors named therein, and Wells Fargo, National Association, as trustee	8-K	001-33784	4.1	03/18/2011
4.2	Registration Rights Agreement, dated March 15, 2011, by and among SandRidge Energy, Inc., certain subsidiary guarantors named therein and RBC Capital Markets, LLC, Barclays Capital Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Mitsubishi UFJ Securities (USA), Inc. and Wells Fargo Securities, LLC, as representatives of the several initial purchasers	8-K	001-33784	4.2	03/18/2011
4.3	First Supplemental Indenture, dated as of March 15, 2011, by and among the Company, certain subsidiary guarantors named therein, and Wells Fargo, National Association, as trustee, to Indenture, dated as of May 1, 2008, by and among the Company, certain subsidiary guarantors named therein, and Wells Fargo, National Association, as trustee	8-K	001-33784	4.3	03/18/2011
10.1	Purchase Agreement, dated March 2, 2011, by and among SandRidge Energy, Inc., certain subsidiary guarantors named therein, and RBC Capital Markets, LLC, Barclays Capital Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Mitsubishi UFJ Securities (USA), Inc. and Wells Fargo Securities, LLC, as representatives of the several initial purchasers	8-K	001-33784	10.1	03/07/2011
10.2	Amendment No. 2 to the Amended and Restated Credit Agreement, dated February 23, 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-K	001-33784	10.73	02/28/2011
10.3	Employment Agreement, effective as of February 1, 2011, between SandRidge Energy, Inc. and James D. Bennett	8-K	001-33784	10.1	01/10/2011
10.4	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					*
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					*

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		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date	Filed Herewith
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					*

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