SandRidge Energy (SD) 10-Q 2010 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2010

OR

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

For the transition period from              to             

Commission File Number: 001-33784

SANDRIDGE ENERGY, INC.

(Exact name of registrant as specified in its charter)

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

Registrant’s telephone number, including area code:

(405) 429-5500

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

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

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

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

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

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

The number of shares outstanding of the registrant’s common stock, par value $0.001 per share, as of the close of business on October 29, 2010, was 404,626,745.

SANDRIDGE ENERGY, INC.

FORM 10-Q

Quarter Ended September 30, 2010

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	40
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	58
ITEM 4.	Controls and Procedures	62
PART II. OTHER INFORMATION
ITEM 1.	Legal Proceedings	64
ITEM 1A.	Risk Factors	65
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	66
ITEM 6.	Exhibits	66

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 include statements about our 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 and elements of our business strategy. Our forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. We have based these forward-looking statements on our current expectations, assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including risks associated with our ability to realize the benefits anticipated from the acquisition of Arena Resources, Inc., as well as the risk factors discussed in Item 1A of this Quarterly Report and of our Annual Report on Form 10-K for the fiscal year ended December 31, 2009 (the “2009 Form 10-K”). The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on our company, business or operations. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statements.

3

PART I. Financial Information

ITEM 1.Financial Statements

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except per share data)

	September 30, 2010			December 31, 2009
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	2,589		$	7,861
Accounts receivable, net		120,224			105,476
Derivative contracts		11,437			105,994
Inventories		3,592			3,707
Costs in excess of billings		—			12,346
Other current assets		20,342			20,580
Total current assets		158,184			255,964
Oil and natural gas properties, using full cost method of accounting
Proved		7,971,187			5,913,408
Unproved		530,111			281,811
Less: accumulated depreciation, depletion and impairment		(4,409,776	)		(4,223,437	)
		4,091,522			1,971,782
Other property, plant and equipment, net		516,220			461,861
Restricted deposits		27,860			32,894
Derivative contracts		1,621			—
Goodwill		239,716			—
Other assets		59,042			57,816
Total assets	$	5,094,165		$	2,780,317
LIABILITIES AND EQUITY
Current liabilities:
Current maturities of long-term debt	$	8,617		$	12,003
Accounts payable and accrued expenses		395,051			203,908
Billings and estimated contract loss in excess of costs incurred		22,224			—
Derivative contracts		34,060			7,080
Asset retirement obligation		2,553			2,553
Total current liabilities		462,505			225,544
Long-term debt		2,988,746			2,566,935
Other long-term obligations		5,776			14,099
Derivative contracts		51,580			61,060
Asset retirement obligation		148,134			108,584
Total liabilities		3,656,741			2,976,222
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 September 30, 2010 and December 31, 2009; aggregate liquidation preference of $265,000		3			3
6.0% Convertible perpetual preferred stock; 2,000 shares issued and outstanding at September 30, 2010 and December 31, 2009; aggregate liquidation preference of $200,000		2			2
Common stock, $0.001 par value, 800,000 and 400,000 shares authorized at September 30, 2010 and December 31, 2009, respectively; 407,352 issued and 404,926 outstanding at September 30, 2010 and 210,581 issued and 208,715 outstanding at December 31, 2009		395			203
Additional paid-in capital		4,236,575			2,961,613
Treasury stock, at cost		(28,392	)		(25,079	)
Accumulated deficit		(2,781,553	)		(3,142,699	)
Total SandRidge Energy, Inc. stockholders’ equity (deficit)		1,427,030			(205,957	)
Noncontrolling interest		10,394			10,052
Total equity (deficit)		1,437,424			(195,905	)
Total liabilities and equity	$	5,094,165		$	2,780,317

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

4

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
				(Unaudited)
Revenues:
Oil and natural gas	$	209,998		$	104,348		$	529,578		$	328,628
Drilling and services		5,252			5,798			14,913			17,207
Midstream and marketing		23,281			16,453			73,868			62,051
Other		6,702			8,256			20,308			20,081
Total revenues		245,233			134,855			638,667			427,967
Expenses:
Production		66,086			41,486			172,367			128,811
Production taxes		8,904			1,069			19,146			3,153
Drilling and services		4,187			9,168			12,420			19,884
Midstream and marketing		20,779			15,261			66,064			58,083
Depreciation and depletion — oil and natural gas		91,237			33,060			197,834			127,503
Depreciation, depletion and amortization — other		12,441			12,092			36,564			38,851
Impairment		—			—			—			1,304,418
General and administrative		61,878			25,006			127,419			77,123
Loss (gain) on derivative contracts		67,195			47,933			(114,378	)		(139,722	)
(Gain) loss on sale of assets		(44	)		9			39			26,359
Total expenses		332,663			185,084			517,475			1,644,463
(Loss) income from operations		(87,430	)		(50,229	)		121,192			(1,216,496	)
Other income (expense):
Interest income		69			89			236			287
Interest expense		(63,641	)		(53,201	)		(189,989	)		(136,368	)
Income from equity investments		—			593			—			1,027
Other income (expense), net		1,356			(1,144	)		2,062			100
Total other expense		(62,216	)		(53,663	)		(187,691	)		(134,954	)
Loss before income taxes		(149,646	)		(103,892	)		(66,499	)		(1,351,450	)
Income tax benefit		(457,248	)		(2,580	)		(457,086	)		(4,114	)
Net income (loss)		307,602			(101,312	)		390,587			(1,347,336	)
Less: net income attributable to noncontrolling interest		1,313			4			3,547			11
Net income (loss) attributable to SandRidge Energy, Inc.		306,289			(101,316	)		387,040			(1,347,347	)
Preferred stock dividends		8,632			2,816			25,894			2,816
Income available (loss applicable) to SandRidge Energy, Inc. common stockholders	$	297,657		$	(104,132	)	$	361,146		$	(1,350,163	)
Earnings (loss) per share:
Basic	$	0.82		$	(0.58	)	$	1.41		$	(7.85	)
Diluted	$	0.73		$	(0.58	)	$	1.24		$	(7.85	)
Weighted average number of common shares outstanding:
Basic		361,687			178,069			257,028			171,902
Diluted		419,137			178,069			313,283			171,902

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

5

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(In thousands)

	SandRidge Energy, Inc. Stockholders
	Convertible Perpetual Preferred Stock				Common Stock				Additional Paid-In Capital			Treasury Stock			Accumulated Deficit			Noncontrolling Interest			Total
	Shares		Amount		Shares		Amount
									(Unaudited)
Nine months ended September 30, 2010
Balance, December 31, 2009		4,650	$	5		208,715	$	203	$	2,961,613		$	(25,079	)	$	(3,142,699	)	$	10,052		$	(195,905	)
Distributions to noncontrolling interest owners		—		—		—		—		—			—			—			(3,511	)		(3,511	)
Contributions from noncontrolling interest owners		—		—		—		—		—			—			—			306			306
Issuance of common stock in acquisition		—		—		190,280		190		1,246,144			—			—			—			1,246,334
Stock issuance expense		—		—		—		—		(87	)		—			—			—			(87	)
Purchase of treasury stock		—		—		—		—		—			(5,335	)		—			—			(5,335	)
Stock purchase — retirement plans, net of distributions		—		—		111		—		(1,524	)		2,022			—			—			498
Stock-based compensation		—		—		—		—		28,248			—			—			—			28,248
Stock-based compensation excess tax benefit		—		—		—		—		31			—			—			—			31
Stock awards assumed in acquisition		—		—		—		—		2,152			—			—			—			2,152
Issuance of restricted stock awards, net of cancellations		—		—		5,820		2		(2	)		—			—			—			—
Net income		—		—		—		—		—			—			387,040			3,547			390,587
Convertible perpetual preferred stock dividends		—		—		—		—		—			—			(25,894	)		—			(25,894	)
Balance, September 30, 2010		4,650	$	5		404,926	$	395	$	4,236,575		$	(28,392	)	$	(2,781,553	)	$	10,394		$	1,437,424

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

6

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Nine Months Ended September 30,
	2010			2009
	(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	390,587		$	(1,347,336	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Provision for doubtful accounts		102			62
Inventory obsolescence		200			—
Depreciation, depletion and amortization		234,398			166,354
Impairment		—			1,304,418
Debt issuance costs amortization		8,044			6,037
Discount amortization on long-term debt		1,595			—
Deferred income taxes		(456,437	)		—
Unrealized loss on derivative contracts		135,364			137,313
Loss on sale of assets		39			26,359
Investment income		(191	)		(29	)
Income from equity investments		—			(1,027	)
Stock-based compensation		24,174			16,526
Changes in operating assets and liabilities		1,337			(31,593	)
Net cash provided by operating activities		339,212			277,084
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant and equipment		(694,187	)		(628,153	)
Acquisition of assets, net of cash received of $39,518		(138,428	)		—
Proceeds from sale of assets		113,422			263,630
Refunds of restricted deposits		5,095			—
Net cash used in investing activities		(714,098	)		(364,523	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		1,595,914			1,638,365
Repayments of borrowings		(1,179,083	)		(1,874,046	)
Dividends paid — preferred		(28,525	)		—
Noncontrolling interest distributions		(3,511	)		(11	)
Noncontrolling interest contributions		306			—
Proceeds from issuance of convertible perpetual preferred stock, net		(87	)		243,289
Proceeds from issuance of common stock, net		—			107,603
Stock-based compensation excess tax benefit		31			(3,864	)
Purchase of treasury stock		(5,335	)		(1,095	)
Derivative settlements		1,624			—
Debt issuance costs		(11,720	)		(8,796	)
Net cash provided by financing activities		369,614			101,445
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(5,272	)		14,006
CASH AND CASH EQUIVALENTS, beginning of year		7,861			636
CASH AND CASH EQUIVALENTS, end of period	$	2,589		$	14,642
Supplemental Disclosure of Noncash Investing and Financing Activities:
Change in accrued capital expenditures	$	101,406		$	(85,952	)
Convertible perpetual preferred stock dividends payable	$	5,816		$	2,816
Adjustment to oil and natural gas properties for estimated contract loss	$	98,000		$	—
Common stock issued in connection with acquisition	$	1,246,334		$	—

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

7

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

Nature of Business. SandRidge Energy, Inc. (including its subsidiaries, the “Company” or “SandRidge”) is an independent oil and natural gas company concentrating on exploration, development and production activities. The Company also owns and operates natural gas gathering and treating facilities and carbon dioxide (“CO₂”) treating and transportation facilities and has marketing and tertiary oil recovery operations. In addition, Lariat Services, Inc. (“Lariat”), a wholly owned subsidiary of the Company, owns and operates drilling rigs and a related oil field services business. The Company’s primary exploration, development and production areas are concentrated in west Texas and the Mid-Continent. The Company also operates interests in the Cotton Valley Trend in east Texas, Gulf Coast and Gulf of Mexico.

Interim Financial Statements. The accompanying condensed consolidated financial statements as of December 31, 2009 have been derived from the audited financial statements contained in the Company’s 2009 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 2009 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 2009 Form 10-K.

Reclassifications.Certain amounts in the prior periods presented have been reclassified to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported results of operations.

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 depend on numerous factors beyond the Company’s control such as economic conditions, regulatory developments and competition from other energy sources. The energy markets and 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 and 2012 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 2013 oil production and no fixed price swap contracts are in place for the Company’s natural gas production beyond 2012 or oil production beyond 2013. 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 in 2010 to achieve production targets contained in certain gathering and treating arrangements. The Company is dependent on the availability of borrowings under its senior secured revolving credit facility (the “senior credit facility”), along with cash flows from operating activities, to fund those capital expenditures. Based on anticipated oil and natural gas prices, the availability of borrowings under its senior credit facility and proceeds from the sales or other strategic monetizations of assets, the Company expects to be able to fund its planned capital expenditures for the remainder of 2010 and 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. These events could adversely impact the Company’s ability to comply with the financial covenants under its senior credit facility, which in turn would limit further borrowings to fund capital expenditures. See Note 11 for discussion of the financial covenants in the senior credit facility.

8

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

2. Recent Accounting Pronouncements

For a description of the Company’s significant accounting policies, refer to Note 1 of the consolidated financial statements included in the 2009 Form 10-K.

Recently Adopted Accounting Pronouncements. In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-03 (“ASU 2010-03”) to align the oil and natural gas reserve estimation and disclosure requirements of ASC Topic 932, Extractive Industries — Oil and Gas, with the requirements in the Securities and Exchange Commission’s final rule,Modernization of the Oil and Gas Reporting Requirements, which was issued on December 31, 2008 and was effective for the year ended December 31, 2009.Modernization of the Oil and Gas Reporting Requirements was designed to modernize and update the oil and gas disclosure requirements to align with current practices and changes in technology. The Company implemented ASU 2010-03 prospectively as a change in accounting principle inseparable from a change in accounting estimate at December 31, 2009.

In December 2009, the FASB issued Accounting Standards Update 2009-17, “Consolidations — Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities” (“ASU 2009-17”), which codified FASB Statement No. 167, “Amendments to FASB Interpretation No. 46(R)”. ASU 2009-17 represents a revision to former FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities,” and changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting or similar rights should be consolidated. ASU 2009-17 also requires enhanced disclosures about a reporting entity’s involvement with variable interest entities. The Company implemented ASU 2009-17 on January 1, 2010 with no impact on its financial position or results of operations. See Note 8.

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 Company implemented the new disclosures and clarifications of existing disclosure requirements under ASU 2010-06 effective with the first quarter of 2010, except for certain disclosure requirements regarding activity in Level 3 fair value measurements that are effective for fiscal years beginning after December 15, 2010. The implementation of ASU 2010-06 had no impact on the Company’s financial position or results of operations. See Note 5. As the additional requirements under ASU 2010-06, which will be implemented January 1, 2011, pertain to disclosure of Level 3 activity, no effect to the Company’s financial position or results of operations is expected.

3. Acquisitions and Divestitures

Arena Acquisition

On July 16, 2010, the stockholders of each of the Company and Arena Resources, Inc. (“Arena”) approved the Company’s acquisition of all of the outstanding common stock of Arena, and the transaction was completed. At the time of the acquisition, Arena was engaged in oil and natural gas exploration, development and production, with activities in Oklahoma, Texas, New Mexico and Kansas. In connection with the acquisition, the Company issued 4.7771 shares of its common stock and paid $4.50 in cash to Arena stockholders for each outstanding share of Arena unrestricted common stock. In addition, outstanding options to purchase Arena common stock that were deemed exercised pursuant to the merger agreement were converted into shares of Company common stock pursuant to a formula in the merger agreement, and outstanding shares of Arena restricted common stock were converted into restricted shares of Company common stock pursuant to a formula in the merger agreement. Approximately 39.8 million shares of Arena common stock, comprised of 39.5 million

9

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

shares of Arena common stock outstanding and 0.3 million common shares attributable to Arena options exercised immediately prior to the acquisition in accordance with the merger agreement, were outstanding on the acquisition date. 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 of approximately $1.4 billion. For purposes of purchase accounting, the value of the common stock issued was determined based on the closing price of $6.55 per share of the Company’s common stock on the New York Stock Exchange at the acquisition date, July 16, 2010. The Company has incurred approximately $15.4 million in fees related to the acquisition, which have been included in general and administrative expenses in the accompanying condensed consolidated statement of operations for the nine months ended September 30, 2010.

The following allocation of the purchase price as of July 16, 2010, is preliminary and includes the use of estimates. This preliminary allocation is based on information that was available to management at the time these condensed consolidated financial statements were prepared. The Company believes the estimates used are reasonable and the significant effects of the transaction are properly reflected. However, the estimates, including amounts related to deferred taxes, are subject to change as additional information becomes available and is assessed by the Company. Changes to the purchase price allocation would result in a corresponding change to goodwill.

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

	July 16, 2010
Current assets	$	81,314
Oil and natural gas properties(1)		1,587,630
Other property, plant and equipment		5,963
Long-term deferred tax assets		18,487
Other long-term assets		16,181
Goodwill(2)		239,716
Total assets acquired		1,949,291
Current liabilities		39,083
Long-term deferred tax liability(2)		474,925
Other long-term liabilities		8,851
Total liabilities assumed		522,859
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 commodity strip prices 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 in excess of 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 $456.4 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 4 for further discussion of goodwill. The newly created net deferred tax liability was

10

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

offset with the Company’s existing net deferred tax asset, resulting in the release of $456.4 million in the Company’s valuation allowance against its existing net deferred tax asset. The release of the valuation allowance resulted in an income tax benefit that was included in the accompanying condensed consolidated statements of operations for the three and nine-month periods ended September 30, 2010. See Note 13 for additional discussion on the tax impact of the Arena acquisition.

The following pro forma results of operations are provided for the three and nine-month periods ended September 30, 2010 and 2009 as though the Arena acquisition had been completed as of the beginning of each three and nine-month period presented. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. 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 September 30,				Nine Months  Ended September 30,
	2010		2009		2010		2009
	(In thousands, except per share amounts)
Revenues	$	253,955	$	170,916	$	753,500	$	511,858
Income available (loss applicable) to SandRidge Energy, Inc. common stockholders(1)(2)	$	287,657	$	352,464	$	369,559	$	(1,433,248	)
Pro forma net income (loss) per common share:
Basic	$	0.73	$	0.96	$	0.94	$	(3.96	)
Diluted	$	0.66	$	0.88	$	0.88	$	(3.96	)

(1) Includes a $456.4 million reduction in tax expense for all periods presented related to the release of a portion of the Company’s valuation allowance on existing deferred tax assets.

(2) Includes approximately $545.5 million of additional estimated impairment from full cost ceiling limitations for the nine months ended September 30, 2009.

The pro forma combined results of operations 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 discussed above. The pro forma results of operations do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate Arena.

Revenues of $46.7 million and earnings of $38.4 million generated by the oil and natural gas properties acquired from Arena for the period of July 17, 2010 through September 30, 2010 have been included in the Company’s accompanying condensed consolidated statements of operations for the three and nine-month periods ended September 30, 2010.

Forest Acquisition

In December 2009, the Company purchased developed and undeveloped oil and natural gas properties located in the Permian Basin from Forest Oil Corporation and one of its subsidiaries (collectively, “Forest”) for $791.7 million, net of purchase price and post-closing adjustments. The acquisition qualified as a business combination and, as such, the Company estimated the fair value of the properties as of the December 21, 2009 acquisition date, which is the date the Company obtained control of the properties. The Company used a discounted cash flow model and made market assumptions about future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions are classified as Level 3 inputs under the fair value hierarchy described in Note 5.

11

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

The estimated fair value of these properties approximates the consideration paid to Forest, which the Company concluded approximates the fair value that would be paid by a typical market participant. As a result, no goodwill was recognized related to the acquisition. In the third quarter of 2010, the Company completed its valuation of assets acquired and liabilities assumed from Forest and made no significant changes to the initial allocation.

Sale of Oklahoma Deep Rights

On August 26, 2010, the Company sold certain deep acreage rights in the Cana Shale play in western Oklahoma for $139.0 million, of which $106.8 million was received as of September 30, 2010. The remaining $32.2 million is subject to certain post-closing adjustments. The sale of the deep acreage rights was accounted for as an adjustment to the full cost pool with no gain or loss recognized. The Company retained the shallow rights associated with this acreage.

4. Goodwill

The Company recorded goodwill in the amount of $239.7 million as a result of the excess consideration transferred over the fair value of Arena net assets acquired on July 16, 2010. See Note 3 for further discussion of the Arena acquisition, including the purchase price allocation. Goodwill recorded in the Arena acquisition is primarily attributable to operational and cost synergies that will be realized from the acquisition by using the Company’s current presence in the Permian Basin, its Fort Stockton service base and its current rig ownership to efficiently increase its drilling and oil production from the Central Basin Platform assets acquired, as these assets have a proven production history. The Company assigned all of the goodwill related to the Arena acquisition to its exploration and production segment. Goodwill recognized will not be deductible for tax purposes.

As stated in ASC Topic 350, Intangibles — Goodwill and Other, goodwill is not amortized, but is tested, at least annually, for impairment at the reporting unit level. Events and changes in circumstances may also require goodwill to be tested for impairment between annual measurement dates. When testing for impairment, if the fair value of the reporting unit is less than the recorded book value of the reporting unit’s net assets, then a hypothetical purchase price allocation is performed on the reporting unit’s assets and liabilities using the fair value of the reporting unit as the purchase price in the calculation. If the amount of goodwill resulting from this hypothetical purchase price allocation is less than the recorded amount of goodwill, the recorded goodwill is written down to the new amount.

5. 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

12

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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.

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, natural gas and interest rate swaps and oil and natural gas collars are based upon quotes obtained from counterparties to the derivative contracts. The Company reviews other readily available market prices for its derivative contracts as there is an active market for these contracts. However, the Company does not have access to the specific valuation models used by its counterparties or other market participants. Included in these models are discount factors that the Company must estimate in its calculation. Additionally, the Company applies a value 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):

September 30, 2010

	Fair Value Measurements						Netting(1)			Assets/ Liabilities  at Fair Value
Description	Level 1		Level 2		Level 3
Assets:
Commodity derivative contracts	$	—	$	—	$	27,803	$	(14,745	)	$	13,058
Restricted deposits		27,860		—		—		—			27,860
Other long-term assets		3,101		—		—		—			3,101
	$	30,961	$	—	$	27,803	$	(14,745	)	$	44,019
Liabilities:
Commodity derivative contracts	$	—	$	—	$	80,584	$	(14,745	)	$	65,839
Interest rate swaps		—		—		19,801		—			19,801
	$	—	$	—	$	100,385	$	(14,745	)	$	85,640

13

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

December 31, 2009

	Fair Value Measurements						Netting(1)			Assets/ Liabilities  at Fair Value
Description	Level 1		Level 2		Level 3
Assets:
Commodity derivative contracts	$	—	$	—	$	161,197	$	(55,203	)	$	105,994
Restricted deposits		32,894		—		—		—			32,894
Other long-term assets		6,251		—		—		—			6,251
	$	39,145	$	—	$	161,197	$	(55,203	)	$	145,139
Liabilities:
Commodity derivative contracts	$	—	$	—	$	115,044	$	(55,203	)	$	59,841
Interest rate swaps		—		—		8,299		—			8,299
	$	—	$	—	$	123,343	$	(55,203	)	$	68,140

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

The tables below set forth a reconciliation of the Company’s financial assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three and nine-month periods ended September 30, 2010 and 2009 (in thousands):

	Three Months Ended
	September 30, 2010									September 30, 2009
	Commodity Derivative Contracts			Interest Rate Swaps			Total			Commodity Derivative Contracts			Interest Rate Swaps			Total
Balance of Level 3, June 30	$	67,178		$	(16,548	)	$	50,630		$	241,166		$	(5,086	)	$	236,080
Total gains or losses (realized/unrealized)		(67,195	)		(5,136	)		(72,331	)		(47,933	)		(6,345	)		(54,278	)
Purchases, issuances and settlements		(52,764	)		1,883			(50,881	)		(83,038	)		1,826			(81,212	)
Transfers in and out of Level 3		—			—			—			—			—			—
Balance of Level 3, September 30	$	(52,781	)	$	(19,801	)	$	(72,582	)	$	110,195		$	(9,605	)	$	100,590
	Nine Months Ended
	September 30, 2010									September 30, 2009
	Commodity Derivative Contracts			Interest Rate Swaps			Total			Commodity Derivative Contracts			Interest Rate Swaps			Total
Balance of Level 3, December 31	$	46,153		$	(8,299	)	$	37,854		$	246,648		$	(8,745	)	$	237,903
Total gains or losses (realized/unrealized)		114,378			(17,548	)		96,830			139,722			(4,991	)		134,731
Purchases, issuances and settlements		(213,312	)		6,046			(207,266	)		(276,175	)		4,131			(272,044	)
Transfers in and out of Level 3		—			—			—			—			—			—
Balance of Level 3, September 30	$	(52,781	)	$	(19,801	)	$	(72,582	)	$	110,195		$	(9,605	)	$	100,590

During the three and nine-month periods ended September 30, 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, including total (gains) losses, realized and unrealized, included in earnings for the period.

14

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Fair Value of Debt

The Company measures fair value of its long-term debt based on quoted market prices and with consideration given to the effect of the Company’s credit risk. The estimated fair values of the Company’s senior notes and the carrying values at September 30, 2010 and December 31, 2009 were as follows (in thousands):

	September 30, 2010				December 31, 2009
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Floating Rate Notes due 2014	$	309,478	$	350,000	$	316,859	$	350,000
8.625% Senior Notes due 2015		653,120		650,000		655,470		650,000
9.875% Senior Notes due 2016(1)		382,870		352,269		390,692		351,021
8.0% Senior Notes due 2018		733,314		750,000		739,778		750,000
8.75% Senior Notes due 2020(2)		447,468		442,937		451,890		442,590

(1) Carrying value is net of $13,231 and $14,479 discount at September 30, 2010 and December 31, 2009, respectively.

(2) Carrying value is net of $7,063 and $7,410 discount at September 30, 2010 and December 31, 2009, respectively.

The carrying values of the Company’s senior credit facility and remaining fixed rate debt instruments approximate fair value based on current rates applicable to similar instruments. See Note 11 for further discussion of the Company’s long-term debt.

6. Property, Plant and Equipment

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

	September 30, 2010			December 31, 2009
Oil and natural gas properties:
Proved	$	7,971,187		$	5,913,408
Unproved		530,111			281,811
Total oil and natural gas properties		8,501,298			6,195,219
Less accumulated depreciation, depletion and impairment		(4,409,776	)		(4,223,437	)
Net oil and natural gas properties capitalized costs		4,091,522			1,971,782
Land		14,428			13,937
Non oil and natural gas equipment		671,531			594,132
Buildings and structures		86,791			78,584
Total		772,750			686,653
Less accumulated depreciation, depletion and amortization		(256,530	)		(224,792	)
Net capitalized costs		516,220			461,861
Total property, plant and equipment, net	$	4,607,742		$	2,433,643

During the first nine months of 2009, the Company reduced the carrying value of its oil and natural gas properties by $1,304.4 million due to a full cost ceiling limitation at March 31, 2009. There were no full cost ceiling impairments during the first nine months of 2010. Cumulative full cost ceiling limitation impairment charges of $3,548.3 million at both September 30, 2010 and December 31, 2009 were included in accumulated depreciation, depletion and impairment for oil and natural gas properties in the table above.

15

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

7. Other Assets

Other assets consist of the following (in thousands):

	September 30, 2010		December 31, 2009
Debt issuance costs, net of amortization	$	52,779	$	49,103
Investments		3,101		6,251
Other		3,162		2,462
Total other assets	$	59,042	$	57,816

8. Variable Interest Entities

In accordance with the guidance in ASC Topic 810, Consolidation, including the guidance in 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, a qualitative analysis of the entity’s design, organizational structure, primary decision makers and related financial agreements is performed.

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, L.P. Primarily engaged in treating and transportation of natural gas, Grey Ranch, 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. During October 2009, the Company executed amendments to certain agreements related to the ownership and operation of GRLP. The amended operating agreements 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.

Prior to October 2009, the Company accounted for its ownership interest in GRLP using the equity method of accounting; however, due to the agreement amendments discussed above, the Company began consolidating the activity of GRLP in its consolidated financial statements prospectively on the effective date of the amendments, October 1, 2009. The change from equity method accounting to the consolidation of GRLP activity had no effect on the Company’s net income. The ownership interest not held by the Company is presented as noncontrolling interest in the consolidated financial statements.

At September 30, 2010 and December 31, 2009, consolidated amounts related to GRLP included assets of $18.1 million and $22.5 million, respectively, and liabilities of $0.9 million and $2.0 million, respectively.

16

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

GRLP’s assets can only be used to settle its obligations. 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 September 30, 2010 and December 31, 2009, $10.4 million and $10.0 million, respectively, of noncontrolling interest in the accompanying condensed consolidated balance sheets were 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.

Piñon Gathering Company, LLC.The Company has 20-year gas gathering and operations and maintenance agreements with Piñon Gathering Company, LLC (“PGC”), the entity that purchased the Company’s gathering and compression assets located in the Piñon Field in June 2009. 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.

9. Century Plant Contract

The Company is constructing a CO₂treatment plant in Pecos County, Texas (the “Century Plant”), and associated compression and pipeline facilities pursuant to an agreement with a subsidiary of 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 and expects the Phase I start-up to occur in the fourth quarter of 2010. Upon completion of each phase of the Century Plant, Occidental will take ownership and operate the Century Plant for the purpose of separating and removing CO₂ from delivered natural gas. 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.

17

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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 the contract is completed or substantially completed. 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. In September 2010, the Company recorded an addition of $98.0 million to its oil and natural gas properties for the estimated loss identified based on current projections of the costs to be incurred in excess of contract amounts. At December 31, 2009, no amounts had been recorded in anticipation of probable and estimable gains or losses. Billings and estimated contract loss in excess of costs incurred were $22.2 million and were reported as current liabilities in the accompanying condensed consolidated balance sheet at September 30, 2010. Costs in excess of billings were $12.3 million and were reported as current assets in the accompanying condensed consolidated balance sheet at December 31, 2009.

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, 2009 to September 30, 2010 is as follows (in thousands):

Asset retirement obligation, December 31, 2009	$	111,137
Liability incurred upon acquiring and drilling wells		5,980
Liability assumed in acquisition		8,851
Revisions in estimated cash flows		18,298
Liability settled in current period		(611	)
Accretion of discount expense		7,032
Asset retirement obligation, September 30, 2010		150,687
Less: current portion		2,553
Asset retirement obligation, net of current	$	148,134

11. Long-Term Debt

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

	September 30, 2010		December 31, 2009
Senior credit facility	$	426,500	$	—
Other notes payable:
Drilling rig fleet and related oil field services equipment		8,401		17,375
Mortgage		17,256		17,952
Senior Floating Rate Notes due 2014		350,000		350,000
8.625% Senior Notes due 2015		650,000		650,000
9.875% Senior Notes due 2016, net of $13,231 and $14,479 discount, respectively		352,269		351,021
8.0% Senior Notes due 2018		750,000		750,000
8.75% Senior Notes due 2020, net of $7,063 and $7,410 discount, respectively		442,937		442,590
Total debt		2,997,363		2,578,938
Less: current maturities of long-term debt		8,617		12,003
Long-term debt	$	2,988,746	$	2,566,935

18

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the three months ended September 30, 2010 and 2009, interest payments were approximately $32.7 million and $8.8 million, respectively. For the nine months ended September 30, 2010 and 2009, interest payments were approximately $124.9 million and $87.9 million, respectively.

Senior Credit Facility. The amount the Company can borrow under its senior credit facility is limited to a borrowing base. The senior credit facility is available to be drawn on subject to limitations based on its terms and certain financial covenants, as described below. In April 2010, the Company’s senior credit facility was amended and restated, affirming the borrowing base at $850.0 million and extending the maturity date to April 15, 2014. Under the terms of the amended and restated facility, (a) the ratio of EBITDAX to interest expense plus current maturities of long-term debt has been eliminated and (b) the Company’s ability to make investments has been increased from the previous terms. In October 2010, the senior credit facility was further amended and effective with this amendment, the ratio of the secured indebtedness of the parties to the senior credit facility to EBITDAX may not exceed 2.0:1.0 at quarter end. The remaining covenants were largely unchanged from the agreement in effect prior to April 2010 and are described further below.

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, including under the series of senior notes discussed below.

As of September 30, 2010, 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 (adjusted for annualized amounts of the post-acquisition results of operations of newly acquired properties/entities) and (ii) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at 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. As of and for the three and nine-month periods ended September 30, 2010, the Company was in compliance with all of the financial covenants under the senior credit facility.

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 reviewed 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 rates paid on amounts outstanding under the senior credit facility were 2.78% and 2.67% for the three and nine-month periods ended September 30, 2010, respectively.

19

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Borrowings under the senior credit facility may not exceed the lower of the borrowing base or the committed amount. 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 borrowing base remained unchanged at $850.0 million as a result of the October 2010 redetermination. The Company has, at times, incurred additional costs related to the senior credit facility as a result of amendments to the credit agreement and changes to the borrowing base.

At September 30, 2010, the Company had $426.5 million outstanding under the senior credit facility and $25.4 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 has financed a portion of its drilling rig fleet and related oil field services equipment through the issuance of notes secured by such equipment. At September 30, 2010, the aggregate outstanding balance of these notes was $8.4 million, with annual fixed interest rates ranging from 8.05% to 8.67%. The notes have a final maturity date of December 1, 2011 and require aggregate monthly installments of principal and interest in the amount of $0.6 million. The notes have a prepayment penalty (currently ranging from 0.50% to 1.00%) that is triggered if the Company repays the notes prior to maturity.

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 and a parking garage 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. During 2010, the Company expects to make payments of principal and interest on this note totaling $0.9 million and $1.1 million, respectively.

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 and are jointly and severally, unconditionally guaranteed on an unsecured basis by certain of the Company’s wholly owned subsidiaries. See Note 20 for condensed financial information of the subsidiary guarantors.

The Senior Floating Rate Notes bear interest at LIBOR plus 3.625% (4.16% at September 30, 2010). 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 months and nine months ended September 30, 2010 were 4.16% and 3.98%, respectively, without consideration of the interest rate swap discussed below. The 8.625% Senior Notes bear interest at a fixed rate of 8.625% per annum with the principal due on April 1, 2015. Under the terms of the 8.625% Senior Notes, interest is payable semi-annually in cash.

The Company has entered into 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.

20

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

The Company may redeem, at specified redemption prices, some or all of the Senior Floating Rate Notes at any time and some or all of the 8.625% Senior Notes on or after April 1, 2011.

The $26.3 million of debt issuance costs associated with the Senior Floating Rate Notes and the 8.625% Senior Notes 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, 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, unconditionally guaranteed on an unsecured basis by all of the Company’s wholly owned subsidiaries, except certain minor 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, unconditionally guaranteed on an unsecured basis, by all of the Company’s wholly owned subsidiaries, except certain minor 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, unconditionally guaranteed on an unsecured basis by all of the Company’s wholly owned subsidiaries, except certain minor subsidiaries.

In conjunction with the issuance of the 8.75% Senior Notes, the Company entered into a Registration Rights Agreement requiring the Company to register these notes by December 16, 2010. On November 2, 2010, pursuant to an exchange offer, the Company replaced all of the 8.75% Senior Notes, which were issued under Rule 144A and Regulation S under the Securities Act, with 8.75% Senior Notes issued pursuant to a registration statement. The terms of the 8.75% Senior Notes issued in the exchange offer are identical in all material respects to the terms of the exchanged senior notes, except that the transfer restrictions, registration rights and provisions for additional interest relating to the exchanged notes do not apply to the newly issued 8.75% Senior Notes. At the closing of the exchange offer, the 8.75% Senior Notes that were accepted for exchange were cancelled. As a result, the exchange offer did not result in the incurrence of any additional indebtedness.

Debt issuance costs of $9.7 million incurred in connection with the offering of and subsequent 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.

21

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

The indentures governing the Company’s senior notes contain limitations on the incurrence of indebtedness, payment of dividends, investments, asset sales, certain asset purchases, transactions with related parties and consolidations or mergers. As of and for the three and nine-month periods ended September 30, 2010, the Company was in compliance with all of the covenants contained in the indentures governing the senior notes.

12. Derivatives

The Company’s derivative contracts have not 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.

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 September 30, 2010 and December 31, 2009, the Company’s commodity derivative contracts consisted of fixed price swaps, price 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 entered into 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.

22

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Fair Value of Derivatives. In accordance with ASC Topic 815, Derivatives and Hedging, the following table presents the fair value of the Company’s derivative contracts as of September 30, 2010 and December 31, 2009 on a gross basis without regard to same-counterparty netting (in thousands):

Type of Contract	Balance Sheet Classification		September 30, 2010			December 31, 2009
Derivative assets:
Oil price swaps		Derivative contracts-current	$	8,030		$	2,849
Natural gas swaps		Derivative contracts-current		14,996			152,986
Natural gas collars		Derivative contracts-current		172			—
Oil price swaps		Derivative contracts-noncurrent		—			5,362
Natural gas swaps		Derivative contracts-noncurrent		4,605			—
Derivative liabilities:
Oil price swaps		Derivative contracts-current		—			(4,127	)
Natural gas swaps		Derivative contracts-current		(37,014	)		(45,714	)
Oil collars		Derivative contracts-current		(64	)		—
Interest rate swaps		Derivative contracts-current		(8,742	)		(7,080	)
Oil price swaps		Derivative contracts-noncurrent		(2,294	)		(2,262	)
Natural gas swaps		Derivative contracts-noncurrent		(41,212	)		(62,941	)
Interest rate swaps		Derivative contracts-noncurrent		(11,059	)		(1,219	)
Total derivative contracts, net			$	(72,582	)	$	37,854

Refer to Note 5 for additional discussion on the fair value measurement of the Company’s derivative contracts.

The following table summarizes the effect of the Company’s derivative contracts on the accompanying condensed consolidated statements of operations for the three and nine-month periods ended September 30, 2010 and 2009 (in thousands):

			Amount of Loss (Gain) Recognized in Income
Type of Contract	Location of Loss (Gain) Recognized in Income		Three Months Ended September 30,				Nine Months Ended September 30,
			2010		2009		2010			2009
Oil and natural gas derivatives		Loss (gain) on derivative contracts	$	67,195	$	47,933	$	(114,378	)	$	(139,722	)
Interest rate swaps		Interest expense		5,136		6,345		17,548			4,991
Total			$	72,331	$	54,278	$	(96,830	)	$	(134,731	)

The Company acquired commodity derivative contracts as part of the Arena acquisition. The derivative contracts were recorded at fair value in the purchase price allocation in accordance with ASC Topic 805, Business Combinations. These derivative contracts acquired from Arena are deemed to contain a significant financing element and cash flows associated with these derivative contracts will be reported as financing activity in the consolidated statement of cash flows for the periods in which settlement occurs in accordance with ASC Topic 815. See Note 3 for further discussion of the Arena acquisition.

23

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

The following tables summarize the cash settlements and valuation gains and losses on our commodity derivative contracts and interest rate swaps for the three and nine-month periods ended September 30, 2010 and 2009 (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
Oil and Natural Gas Derivatives	2010			2009			2010			2009
Realized gain(1)	$	(77,692	)	$	(83,038	)	$	(238,240	)	$	(276,175	)
Unrealized loss		144,887			130,971			123,862			136,453
Loss (gain) on commodity derivative contracts	$	67,195		$	47,933		$	(114,378	)	$	(139,722	)
	Three Months Ended September 30,						Nine Months Ended September 30,
Interest Rate Swaps	2010			2009			2010			2009
Realized loss	$	1,883		$	1,826		$	6,046		$	4,131
Unrealized loss		3,253			4,519			11,502			860
Loss on interest rate swaps	$	5,136		$	6,345		$	17,548		$	4,991

(1) Includes $48.2 million and $110.6 million of realized gains for the three and nine-month periods ended September 30, 2010, respectively, related to settlements of commodity derivative contracts with contractual maturities after the quarterly period in which they were settled.

On September 30, 2010, the Company’s open oil and natural gas commodity derivative contracts consisted of the following:

Oil

Period and Type of Contract	Notional (in MBbl)		Weighted Avg. Fixed Price		Collar High		Collar Low
October 2010 — December 2010
Price swap contracts		1,564	$	80.46	$	—	$	—
Collars		276	$	—	$	92.95	$	66.67
January 2011 — March 2011
Price swap contracts		1,953	$	86.20	$	—	$	—
April 2011 — June 2011
Price swap contracts		1,975	$	86.20	$	—	$	—
July 2011 — September 2011
Price swap contracts		2,180	$	85.96	$	—	$	—
October 2011 — December 2011
Price swap contracts		2,180	$	85.96	$	—	$	—
January 2012 — March 2012
Price swap contracts		2,275	$	87.18	$	—	$	—
April 2012 — June 2012
Price swap contracts		2,366	$	87.10	$	—	$	—
July 2012 — September 2012
Price swap contracts		2,422	$	87.08	$	—	$	—
October 2012 — December 2012
Price swap contracts		2,484	$	87.04	$	—	$	—
January 2013 — March 2013
Price swap contracts		360	$	87.23	$	—	$	—

24

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Period and Type of Contract	Notional (in MBbl)		Weighted Avg. Fixed Price		Collar High		Collar Low
April 2013 — June 2013
Price swap contracts		364	$	87.23	$	—	$	—
July 2013 — September 2013
Price swap contracts		368	$	87.23	$	—	$	—
October 2013 — December 2013
Price swap contracts		368	$	87.23	$	—	$	—

Natural Gas

Period and Type of Contract	Notional (MMcf)(1)		Weighted Avg. Fixed Price			Collar High		Collar Low
October 2010 — December 2010
Price swap contracts		9,760	$	4.20		$	—	$	—
Basis swap contracts		20,700	$	(0.74	)		—		—
Collars		460	$	—		$	7.87	$	4.00
January 2011 — March 2011
Price swap contracts		12,600	$	4.72		$	—	$	—
Basis swap contracts		25,650	$	(0.47	)	$	—		—
April 2011 — June 2011
Price swap contracts		12,740	$	4.72		$	—	$	—
Basis swap contracts		25,935	$	(0.47	)	$	—	$	—
July 2011 — September 2011
Price swap contracts		12,880	$	4.72		$	—	$	—
Basis swap contracts		26,220	$	(0.47	)	$	—	$	—
October 2011 — December 2011
Price swap contracts		12,880	$	4.72		$	—	$	—
Basis swap contracts		26,220	$	(0.47	)	$	—	$	—
January 2012 — March 2012
Price swap contracts		9,100	$	5.23		$	—	$	—
Basis swap contracts		28,210	$	(0.55	)	$	—	$	—
April 2012 — June 2012
Price swap contracts		9,100	$	5.23		$	—	$	—
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	)	$	—	$	—

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

25

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

13. Income Taxes

The Company estimates for each interim reporting period the effective tax rate expected for the full fiscal year and uses that estimated rate in providing income taxes on a current year-to-date basis.

The (benefit) provision for income taxes consisted of the following components for the three and nine-month periods ended September 30, 2010 and 2009 (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Current:
Federal	$	(844	)	$	(1,763	)	$	(844	)	$	(3,979	)
State		33			(817	)		195			(135	)
		(811	)		(2,580	)		(649	)		(4,114	)
Deferred:
Federal		(442,923	)		—			(442,923	)		—
State		(13,514	)		—			(13,514	)		—
		(456,437	)		—			(456,437	)		—
Total (benefit) provision		(457,248	)		(2,580	)		(457,086	)		(4,114	)
Less: income tax provision attributable to noncontrolling interest		15			—			104			—
Total (benefit) provision attributable to SandRidge Energy, Inc.	$	(457,263	)	$	(2,580	)	$	(457,190	)	$	(4,114	)

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 consolidated 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, 2009 and 2008, the Company determined it was appropriate to record a full valuation allowance against its net deferred tax asset. During the three-month period ended September 30, 2010, the Company recorded a net deferred tax liability associated with the Arena acquisition which resulted in the Company releasing a portion of the previously recorded valuation allowance. The partial release of the valuation allowance was based on management’s assessment that it is more likely than not that the Company will realize a benefit from more of its existing deferred tax assets as the Arena deferred tax liabilities are available to offset the reversal of the Company’s deferred tax assets. Although the Company continued to have a full valuation allowance against its net deferred tax asset at September 30, 2010, the release of a portion of the valuation allowance resulted in an income tax benefit of $456.4 million for the three and nine-month periods ended September 30, 2010.

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 $299.5 million of federal net operating loss carryforwards, to the IRC Section 382 limitation. This limitation could result in a material amount of these loss carryforwards expiring unused. 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 limitation on certain of its tax attributes as a result of the July 16, 2010 ownership change; however, the extent of any

26

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

limitation is not yet known. Arena also experienced an ownership change on July 16, 2010 as a result of the acquisition by the Company. This ownership change is expected to result in a limitation on Arena’s net operating loss carryforwards available to the Company. None of the limitations discussed above resulted in a current federal tax liability at September 30, 2010 or December 31, 2009.

No reserves for uncertain income tax positions have been recorded pursuant to the guidance for uncertainty in income taxes under ASC Topic 740, Income Taxes. Tax years 2003 to present remain open for the majority of taxing authorities due to net operating loss carryforwards from those years or normal statute of limitations. The Company’s accounting policy is to recognize interest and penalties, if any, related to unrecognized tax benefits as income tax expense. The Company did not have an accrued liability for interest and penalties at September 30, 2010 or December 31, 2009 with respect to reserves for uncertain income tax positions.

For the three-month period ended September 30, 2010 and 2009, income tax payments, net of refunds, were approximately $1.9 million and $0.0 million, respectively. For the nine-month period ended September 30, 2010 and 2009, income tax payments, net of refunds, were approximately $(1.6) million and $3.0 million, respectively.

14. Earnings Per Share

Basic earnings per share are computed using the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average shares outstanding during the period, but also include the dilutive effect of awards of restricted stock and outstanding convertible preferred stock. The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings per share, for the three and nine-month periods ended September 30, 2010 and 2009 (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Weighted average basic common shares outstanding		361,687		178,069		257,028		171,902
Effect of dilutive securities:
Restricted stock		5,954		—		4,759		—
Convertible preferred stock outstanding		51,496		—		51,496		—
Weighted average diluted common and potential common shares outstanding		419,137		178,069		313,283		171,902

For the three and nine-month periods ended September 30, 2009, restricted stock awards covering 3.2 million shares and 2.7 million shares, respectively, were excluded from the computation of net loss per share because their effect would have been antidilutive.

In computing diluted earnings per share, the Company evaluated the if-converted method with respect to its outstanding 8.5% convertible perpetual preferred stock and 6.0% convertible perpetual preferred stock (see Note 16) for the three and nine-month periods ended September 30, 2010 and its outstanding 8.5% convertible perpetual preferred stock for the three and nine-month periods ended September 30, 2009. Under this 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 and nine-month periods ended September 30, 2010, the Company determined the if-converted method was more dilutive and did not include preferred stock dividends in the

27

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

determination of income available to common stockholders. For the three and nine-month periods ended September 30, 2009, the Company determined the if-converted method was not more dilutive and included preferred stock dividends in the determination of 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.

16. Equity

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

	September 30, 2010		December 31, 2009
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

The Company is authorized to issue 50,000,000 shares of preferred stock, $0.001 par value, of which 4,650,000 shares were designated as convertible perpetual preferred stock at September 30, 2010 and December 31, 2009. 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. Dividend payments were paid in cash in February and August 2010. Approximately $5.6 million in dividends ($2.8 million paid and $2.8 million unpaid) and $16.9 million in dividends ($14.1 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 and nine-month periods ended September 30, 2010, respectively, as presented in the accompanying condensed consolidated statements of operations. The 8.5% convertible perpetual preferred stock is not redeemable by the Company at any time. After February 20, 2014, the Company may cause all outstanding shares of the convertible perpetual preferred stock to convert automatically into common stock at the then-prevailing conversion rate if certain conditions are met.

6.0% Convertible perpetual preferred stock. The Company’s 6.0% convertible perpetual preferred stock was issued in December 2009. Each share of the 6.0% convertible perpetual preferred stock has a liquidation preference of $100.00 and is entitled to an annual dividend of $6.00 payable semi-annually in cash, common stock or any combination thereof, at the Company’s election, beginning on July 15, 2010. The first dividend payment was paid in cash in July 2010. Approximately $3.0 million (all unpaid) and $9.0 million in dividends ($6.0 million paid and $3.0 million unpaid) on the 6.0% convertible perpetual preferred stock have been included in the Company’s

28

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

earnings per share calculations for the three and nine-month periods ended September 30, 2010, respectively, as presented in the accompanying condensed consolidated statements of operations. The 6.0% convertible perpetual preferred stock is not redeemable by the Company at any time. Each share is initially convertible into 9.21 shares of the Company’s common stock, at the holder’s option based on an initial conversion price of $10.86 and subject to customary adjustments in certain circumstances. Five years after their issuance, all outstanding shares of the convertible preferred stock will be converted automatically into shares of the Company’s common stock at the then-prevailing conversion price as long as all dividends accrued at that time have been paid.

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

	September 30, 2010		December 31, 2009
Shares authorized		800,000		400,000
Shares outstanding at end of period		404,926		208,715
Shares held in treasury		2,426		1,866

On July 16, 2010, in conjunction with stockholder approval of the issuance of shares of Company common stock in connection with the Company’s acquisition of Arena, the Company’s stockholders approved an amendment to the Company’s certificate of incorporation to increase the number of authorized shares of common stock from 400.0 million shares to 800.0 million shares. See Note 3 for further discussion regarding the Arena acquisition.

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 670,000 shares with a total value of $5.3 million and approximately 136,000 shares with a total value of $1.1 million during the nine-month periods ended September 30, 2010 and 2009, respectively. These shares were accounted for as treasury stock. Also accounted for as treasury stock are any shares of Company common stock held as assets in a trust for the Company’s non-qualified deferred compensation plan. These shares were therefore not included as outstanding shares of common stock in this Quarterly Report. For corporate purposes and for purposes of voting at Company stockholder meetings, these shares are considered outstanding and have voting rights, which are exercised by the Company.

Equity Compensation. The Company awards restricted common stock under incentive compensation plans that vest over specified periods 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 and nine-month periods ended September 30, 2010, the Company recognized stock-based compensation expense of $10.0 million and $24.2 million, net of $1.5 million and $4.1 million capitalized, respectively, related to restricted common stock. For the three and nine-month periods ended September 30, 2009, the Company recognized stock-based compensation expense of $6.2 million and $16.5 million, net of $1.1 million and $3.2 million capitalized, respectively, related to restricted common stock.

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 as required by ASC Topic 810.

29

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

The following table presents a reconciliation of the activity for noncontrolling interest in entities included in the consolidated results of the Company for the nine-month periods ended September 30, 2010 and 2009 (in thousands):

	2010			2009
Beginning balance, January 1,	$	10,052		$	30
Distributions to noncontrolling interest owners		(3,511	)		(11	)
Contributions from noncontrolling interest owners		306			—
Net income attributable to noncontrolling interest		3,547			11
Ending balance, September 30	$	10,394		$	30

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 September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Sales to and reimbursements from related parties	$	4,157	$	1,014	$	10,980	$	5,420
Purchases from related parties	$	75	$	4,550	$	165	$	18,956

	September 30, 2010		December 31, 2009
Accounts receivable due from related parties	$	1,459	$	64
Accounts payable due to related parties	$	—	$	860

Larclay, L.P. Until April 15, 2009, Lariat and its partner Clayton Williams Energy, Inc. (“CWEI”) each owned a 50% interest in Larclay, L.P. (“Larclay”), a limited partnership, and, until such time, Lariat operated the rigs owned by Larclay. On April 15, 2009, Lariat completed an assignment to CWEI of Lariat’s 50% equity interest in Larclay pursuant to the terms of an Assignment and Assumption Agreement (the “Larclay Assignment”) entered into between Lariat and CWEI on March 13, 2009. Pursuant to the Larclay Assignment, Lariat assigned all of its right, title and interest in and to Larclay to CWEI effective April 15, 2009, and CWEI assumed all of the obligations and liabilities of Lariat relating to Larclay. For the nine-month period ended September 30, 2009, sales to and reimbursements from Larclay were $3.0 million and purchases of services from Larclay were $1.8 million.

Oklahoma City Thunder Agreements. The Company’s Chairman and Chief Executive Officer owns a minority interest in a limited liability company which owns and operates the Oklahoma City Thunder, a National Basketball Association team playing in Oklahoma City, where the Company is headquartered. The Company, like four other Oklahoma City companies, has a five-year sponsorship agreement whereby the Company 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. Amounts related to these agreements are not included in the tables above.

30

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

18. Subsequent Events

Events occurring after September 30, 2010 were evaluated to ensure that any subsequent events that met the criteria for recognition and/or disclosure in this Quarterly Report have been included.

Proposed settlement. In October 2010, the Company agreed to compromise and settle a dispute with certain working interest owners under two joint operating agreements. Under the proposed settlement, the Company will pay the working interest owners a total of $6.0 million in cash and issue to the working interest owners a total of 1,788,909 shares of Company common stock, valued at $5.59 per share. To the extent that the market price of the Company’s common stock is less than $5.59 at the time trading in the shares is no longer restricted, the Company will make an additional payment in the aggregate amount of such difference. Such restrictions are expected to lapse within one year from the date of issuance of the shares. The proposed settlement amount of $16.0 million was accrued and included in the accompanying condensed consolidated financial statements as of September 30, 2010.

8.75% Senior Notes Due 2020. On November 2, 2010, pursuant to an exchange offer, the Company replaced all of the 8.75% Senior Notes, which were issued under Rule 144A and Regulation S under the Securities Act, with 8.75% Senior Notes issued pursuant to a registration statement. See Note 11 for additional discussion of the exchange.

Private Placement of Convertible Perpetual Preferred Stock.On November 4, 2010, the Company agreed to issue, in a private offering under Rule 144A of the Securities Act, 2,500,000 shares of a new series of 7.0% convertible perpetual preferred stock for net proceeds of approximately $242.0 million, after applying a discount to the purchase price of the stock and deducting offering expenses. The Company also granted a 30-day option to the initial purchasers to purchase an additional 500,000 shares solely to cover over-allotments. The Company intends to use the net proceeds from this offering, including any additional proceeds from the exercise of the option to purchase additional shares, for general corporate purposes, including (i) to repay a portion of the amount outstanding under the Company’s senior credit facility and (ii) to fund the Company’s 2010 capital expenditure program. Closing of the private placement of the preferred stock offering is expected to occur on November 10, 2010 and will be subject to satisfaction of various customary closing conditions.

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 purchasing, gathering, treating and selling 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.

As further discussed in Note 20, SandRidge Energy, Inc., the parent company, contributed its oil and natural gas related assets and liabilities to one of its wholly owned subsidiaries effective as of May 1, 2009. As a result, the financial information of SandRidge Energy, Inc. is included in the All Other column in the tables below, which is consistent with management’s evaluation of the business segments. SandRidge Energy, Inc. was previously included in the exploration and production segment. All periods presented below reflect this change in presentation.

31

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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

	Exploration  and Production			Drilling and Oil Field Services			Midstream  Gas Services			All Other			Consolidated Total
Three Months Ended September 30, 2010
Revenues	$	210,484		$	60,370		$	65,470		$	8,965		$	345,289
Inter-segment revenue		(63	)		(55,096	)		(42,545	)		(2,352	)		(100,056	)
Total revenues	$	210,421		$	5,274		$	22,925		$	6,613		$	245,233
Operating (loss) income	$	(65,642	)	$	(1,826	)	$	1,196		$	(21,158	)	$	(87,430	)
Interest income (expense), net		137			(201	)		(175	)		(63,333	)		(63,572	)
Other income, net		459			—			388			509			1,356
(Loss) income before income taxes	$	(65,046	)	$	(2,027	)	$	1,409		$	(83,982	)	$	(149,646	)
Capital expenditures(1)	$	295,007		$	8,897		$	10,143		$	4,002		$	318,049
Depreciation, depletion and amortization	$	91,931		$	7,081		$	1,131		$	3,535		$	103,678
Three Months Ended September 30, 2009
Revenues	$	105,026		$	42,958		$	52,564		$	9,576		$	210,124
Inter-segment revenue		(66	)		(37,160	)		(36,644	)		(1,399	)		(75,269	)
Total revenues	$	104,960		$	5,798		$	15,920		$	8,177		$	134,855
Operating (loss) income	$	(31,122	)	$	(4,621	)	$	476		$	(14,962	)	$	(50,229	)
Interest expense, net		(14	)		(482	)		—			(52,616	)		(53,112	)
Other (expense) income, net		(1,144	)		—			593			—			(551	)
(Loss) income before income taxes	$	(32,280	)	$	(5,103	)	$	1,069		$	(67,578	)	$	(103,892	)
Capital expenditures(1)	$	87,288		$	569		$	2,500		$	7,360		$	97,717
Depreciation, depletion and amortization	$	33,759		$	7,042		$	558		$	3,793		$	45,152

32

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

	Exploration  and Production			Drilling and Oil Field Services			Midstream  Gas Services			All Other			Consolidated Total
Nine Months Ended September 30, 2010
Revenues	$	531,239		$	202,419		$	214,386		$	28,162		$	976,206
Inter-segment revenue		(194	)		(187,473	)		(141,778	)		(8,094	)		(337,539	)
Total revenues	$	531,045		$	14,946		$	72,608		$	20,068		$	638,667
Operating income (loss)	$	180,846		$	(6,421	)	$	3,352		$	(56,585	)	$	121,192
Interest income (expense), net		337			(768	)		(474	)		(188,848	)		(189,753	)
Other income, net		1,240			—			444			378			2,062
Income (loss) before income taxes	$	182,423		$	(7,189	)	$	3,322		$	(245,055	)	$	(66,499	)
Capital expenditures(1)	$	706,056		$	26,509		$	46,902		$	16,126		$	795,593
Depreciation, depletion and amortization	$	199,965		$	21,244		$	2,933		$	10,256		$	234,398
At September 30, 2010
Total assets	$	4,482,756		$	226,113		$	150,031		$	235,265		$	5,094,165
Nine Months Ended September 30, 2009
Revenues	$	330,686		$	192,747		$	218,769		$	21,983		$	764,185
Inter-segment revenue		(196	)		(175,540	)		(158,339	)		(2,143	)		(336,218	)
Total revenues	$	330,490		$	17,207		$	60,430		$	19,840		$	427,967
Operating loss(2)	$	(1,132,198	)	$	(10,177	)	$	(27,344	)	$	(46,777	)	$	(1,216,496	)
Interest expense, net		(62	)		(1,673	)		—			(134,346	)		(136,081	)
Other income, net		100			—			1,027			—			1,127
Loss before income taxes	$	(1,132,160	)	$	(11,850	)	$	(26,317	)	$	(181,123	)	$	(1,351,450	)
Capital expenditures(1)	$	470,519		$	2,770		$	43,788		$	25,124		$	542,201
Depreciation, depletion and amortization	$	129,544		$	21,237		$	4,515		$	11,058		$	166,354
At December 31, 2009
Total assets	$	2,222,724		$	229,507		$	110,757		$	217,329		$	2,780,317

(1) Capital expenditures are presented on an accrual basis.

(2) The operating loss for the exploration and production segment for the nine-month period ended September 30, 2009 includes a $1,304.4 million non-cash full cost ceiling impairment on the Company’s oil and natural gas properties.

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, unconditionally guaranteed on an unsecured basis the Company’s 8.625% Senior Notes and Senior Floating Rate Notes. The subsidiary guarantees (i) rank equally in right of payment with all of the existing and future senior

33

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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 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.

Effective May 1, 2009, SandRidge Energy, Inc., the parent, contributed all of its rights, title and interest in its oil and natural gas related assets and accompanying liabilities to one of its wholly owned guarantor subsidiaries, leaving it with no oil or natural gas related assets or operations.

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 Company’s subsidiary guarantors guarantee payments of principal and interest under the Company’s registered notes. 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.

34

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Condensed Consolidating Balance Sheets

	September 30, 2010
	Parent		Guarantors		Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	1,195	$	667	$	727	$	—		$	2,589
Accounts receivable, net		1,090,259		116,796		402,175		(1,489,006	)		120,224
Derivative contracts		—		11,437		—		—			11,437
Other current assets		—		19,490		4,444		—			23,934
Total current assets		1,091,454		148,390		407,346		(1,489,006	)		158,184
Property, plant and equipment, net		—		4,508,040		99,702		—			4,607,742
Goodwill		—		239,716		—		—			239,716
Investment in subsidiaries		3,358,257		68,896		—		(3,427,153	)		—
Other assets		52,779		35,744		—		—			88,523
Total assets	$	4,502,490	$	5,000,786	$	507,048	$	(4,916,159	)	$	5,094,165
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	83,953	$	1,379,390	$	420,714	$	(1,489,006	)	$	395,051
Other current liabilities		8,742		57,736		976		—			67,454
Total current liabilities		92,695		1,437,126		421,690		(1,489,006	)		462,505
Long-term debt		2,971,706		760		16,280		—			2,988,746
Asset retirement obligation		—		147,970		164		—			148,134
Other liabilities		11,059		46,297		—		—			57,356
Total liabilities		3,075,460		1,632,153		438,134		(1,489,006	)		3,656,741
Equity		1,427,030		3,368,633		68,914		(3,427,153	)		1,437,424
Total liabilities and equity	$	4,502,490	$	5,000,786	$	507,048	$	(4,916,159	)	$	5,094,165

35

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

	December 31, 2009
	Parent			Guarantors		Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	339		$	2,841	$	4,681	$	—		$	7,861
Accounts receivable, net		642,317			96,251		14,888		(647,980	)		105,476
Derivative contracts		—			105,994		—		—			105,994
Other current assets		—			24,785		11,848		—			36,633
Total current assets		642,656			229,871		31,417		(647,980	)		255,964
Property, plant and equipment, net		—			2,331,261		102,382		—			2,433,643
Investment in subsidiaries		1,813,887			64,827		—		(1,878,714	)		—
Other assets		49,103			41,607		—		—			90,710
Total assets	$	2,505,646		$	2,667,566	$	133,799	$	(2,526,694	)	$	2,780,317
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	159,693		$	641,349	$	50,846	$	(647,980	)	$	203,908
Other current liabilities		7,080			13,624		932		—			21,636
Total current liabilities		166,773			654,973		51,778		(647,980	)		225,544
Long-term debt		2,543,611			6,304		17,020		—			2,566,935
Asset retirement obligation		—			108,429		155		—			108,584
Other liabilities		1,219			73,940		—		—			75,159
Total liabilities		2,711,603			843,646		68,953		(647,980	)		2,976,222
(Deficit) equity		(205,957	)		1,823,920		64,846		(1,878,714	)		(195,905	)
Total liabilities and equity	$	2,505,646		$	2,667,566	$	133,799	$	(2,526,694	)	$	2,780,317

36

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Condensed Consolidating Statements of Operations

	Parent			Guarantors			Non-Guarantors				Eliminations			Consolidated
	(In thousands)
Three Months Ended September 30, 2010
Total revenues	$	—		$	235,447		$	27,318			$	(17,532	)	$	245,233
Expenses:
Direct operating expenses		—			96,136			21,124				(17,348	)		99,912
General and administrative		71			61,376			615				(184	)		61,878
Depreciation, depletion, amortization and impairment		—			101,956			1,722				—			103,678
Loss on derivative contracts		—			67,195			—				—			67,195
Total expenses		71			326,663			23,461				(17,532	)		332,663
(Loss) income from operations		(71	)		(91,216	)		3,857				—			(87,430	)
Equity earnings from subsidiaries		(87,857	)		2,242			—				85,615			—
Interest expense, net		(63,061	)		(239	)		(272	)			—			(63,572	)
Other income, net		—			1,356			—				—			1,356
(Loss) income before income taxes		(150,989	)		(87,857	)		3,585				85,615			(149,646	)
Income tax (benefit) expense		(457,278	)		—			30				—			(457,248	)
Net income (loss)		306,289			(87,857	)		3,555				85,615			307,602
Less: net income attributable to noncontrolling interest		—			—			1,313				—			1,313
Net income (loss) attributable to SandRidge Energy, Inc.	$	306,289		$	(87,857	)	$	2,242			$	85,615		$	306,289
Three Months Ended September 30, 2009
Total revenues	$	—		$	125,673		$	34,994			$	(25,812	)	$	134,855
Expenses:
Direct operating expenses		—			61,048			31,635				(25,690	)		66,993
General and administrative		—			24,473			655				(122	)		25,006
Depreciation, depletion, amortization and impairment		—			43,786			1,366				—			45,152
Loss on derivative contracts		—			47,933			—				—			47,933
Total expenses		—			177,240			33,656				(25,812	)		185,084
(Loss) income from operations		—			(51,567	)		1,338				—			(50,229	)
Equity earnings from subsidiaries		(51,566	)		1,049			—				50,517			—
Interest expense, net		(52,330	)		(497	)		(285	)			—			(53,112	)
Other expense, net		—			(551	)		—				—			(551	)
(Loss) income before income taxes		(103,896	)		(51,566	)		1,053				50,517			(103,892	)
Income tax benefit		(2,580	)		—			—				—			(2,580	)
Net (loss) income		(101,316	)		(51,566	)		1,053				50,517			(101,312	)
Less: net income attributable to noncontrolling interest		—			—			4				—			4
Net (loss) income attributable to SandRidge Energy, Inc.	$	(101,316	)	$	(51,566	)	$	1,049		��	$	50,517		$	(101,316	)

37

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Nine Months Ended September 30, 2010
Total revenues	$	—		$	609,135		$	117,950		$	(88,418	)	$	638,667
Expenses:
Direct operating expenses		—			258,991			98,868			(87,823	)		270,036
General and administrative		234			125,207			2,573			(595	)		127,419
Depreciation, depletion, amortization and impairment		—			229,325			5,073			—			234,398
Gain on derivative contracts		—			(114,378	)		—			—			(114,378	)
Total expenses		234			499,145			106,514			(88,418	)		517,475
(Loss) income from operations		(234	)		109,990			11,436			—			121,192
Equity earnings from subsidiaries		117,937			6,920			—			(124,857	)		—
Interest expense, net		(188,031	)		(905	)		(817	)		—			(189,753	)
Other income, net		74			1,932			56			—			2,062
(Loss) income before income taxes		(70,254	)		117,937			10,675			(124,857	)		(66,499	)
Income tax (benefit) expense		(457,294	)		—			208			—			(457,086	)
Net income		387,040			117,937			10,467			(124,857	)		390,587
Less: net income attributable to noncontrolling interest		—			—			3,547			—			3,547
Net income attributable to SandRidge Energy, Inc.	$	387,040		$	117,937		$	6,920		$	(124,857	)	$	387,040
Nine Months Ended September 30, 2009
Total revenues	$	58,271		$	345,608		$	152,945		$	(128,857	)	$	427,967
Expenses:
Direct operating expenses		27,737			193,485			143,540			(128,472	)		236,290
General and administrative		15,515			60,431			1,562			(385	)		77,123
Depreciation, depletion, amortization and impairment		627,478			839,164			4,130			—			1,470,772
(Gain) loss on derivative contracts		(237,351	)		97,629			—			—			(139,722	)
Total expenses		433,379			1,190,709			149,232			(128,857	)		1,644,463
(Loss) income from operations		(375,108	)		(845,101	)		3,713			—			(1,216,496	)
Equity earnings from subsidiaries		(842,935	)		2,844			—			840,091			—
Interest expense, net		(133,520	)		(1,703	)		(858	)		—			(136,081	)
Other income, net		102			1,025			—			—			1,127
(Loss) income before income taxes		(1,351,461	)		(842,935	)		2,855			840,091			(1,351,450	)
Income tax benefit		(4,114	)		—			—			—			(4,114	)
Net (loss) income		(1,347,347	)		(842,935	)		2,855			840,091			(1,347,336	)
Less: net income attributable to noncontrolling interest		—			—			11			—			11
Net (loss) income attributable to SandRidge Energy, Inc.	$	(1,347,347	)	$	(842,935	)	$	2,844		$	840,091		$	(1,347,347	)

38

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Condensed Consolidating Statements of Cash Flows

	Parent			Guarantors			Non-Guarantors			Eliminations		Consolidated
	(In thousands)
Nine Months Ended September 30, 2010
Net cash (used in) provided by operating activities	$	(241,580	)	$	574,767		$	6,025		$	—	$	339,212
Net cash used in investing activities		(138,428	)		(569,592	)		(6,078	)		—		(714,098	)
Net cash provided by (used in) financing activities		380,864			(7,349	)		(3,901	)		—		369,614
Net increase (decrease) in cash and cash equivalents		856			(2,174	)		(3,954	)		—		(5,272	)
Cash and cash equivalents at beginning of year		339			2,841			4,681			—		7,861
Cash and cash equivalents at end of period	$	1,195		$	667		$	727		$	—	$	2,589
Nine Months Ended September 30, 2009
Net cash provided by operating activities	$	141,658		$	125,532		$	9,894		$	—	$	277,084
Net cash used in investing activities		(240,992	)		(114,336	)		(9,195	)		—		(364,523	)
Net cash provided by (used in) financing activities		113,730			(11,618	)		(667	)		—		101,445
Net increase (decrease) in cash and cash equivalents		14,396			(422	)		32			—		14,006
Cash and cash equivalents at beginning of year		18			592			26			—		636
Cash and cash equivalents at end of period	$	14,414		$	170		$	58		$	—	$	14,642

39

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 2009 Form 10-K.

The financial information with respect to the three and nine-month periods ended September 30, 2010 and September 30, 2009 that is 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 exploration, development and production activities related to the exploitation of our significant holdings in west Texas and the Mid-Continent. Our primary areas of focus are the Permian Basin, the West Texas Overthrust (“WTO”) and the Mississippian horizontal play in the Mid-Continent area of Oklahoma and Kansas. Our oil properties in the Permian Basin include properties acquired in December 2009 from Forest and properties formerly owned by Arena that we acquired in July 2010. Each such acquisition is described below. The WTO, which includes the Piñon gas field, is a natural gas-prone geological region where we have operated since 1986. We also operate interests in the Cotton Valley Trend in east Texas, Gulf Coast and Gulf of Mexico.

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 commodity derivative 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.

We operate businesses that are complementary to our exploration, 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 is largely 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 contribute to our consolidated results of operations.

Acquisitions

In December 2009, we purchased, for approximately $791.7 million, oil and natural gas properties located in the Permian Basin from Forest, consisting primarily of six operated areas in the Central Basin Platform and greater Permian Basin area of western Texas and eastern New Mexico. Approximately 98% of the production associated with these properties is operated and the properties cover over 90,000 net acres, of which nearly 80% is held by production. The acquisition of properties from Forest expanded our holdings in the Central Basin Platform of the Permian Basin and added significant Permian Basin oil production in the Midland and Delaware Basins in Texas as well as the Northwest Shelf in New Mexico.

In July 2010, we acquired all of the outstanding common stock of Arena. In connection with the acquisition, we issued 4.7771 shares of our common stock and paid $4.50 in cash to Arena stockholders for each outstanding share of unrestricted Arena common stock for a total purchase price of approximately $1.4 billion. At the time of

40

the acquisition, Arena was engaged in oil and natural gas exploration, development and production, with activities in Oklahoma, Texas, New Mexico and Kansas. The acquisition of Arena expanded our holdings in the Central Basin Platform of the Permian Basin and added significant Permian Basin oil production.

Recent Developments

Proposed settlement. In October 2010, we agreed to compromise and settle a dispute with certain working interest owners under two joint operating agreements. Under the proposed settlement, we will pay the working interest owners a total of $6.0 million in cash and issue to the working interest owners a total of 1,788,909 shares of our common stock, valued at $5.59 per share. To the extent that the market price of our common stock is less than $5.59 at the time trading in the shares is no longer restricted, we will make an additional payment in the aggregate amount of such difference. Such restrictions are expected to lapse within one year from the date of issuance of the shares. See Note 18 to the condensed consolidated financial statements.

8.75% Senior Notes Due 2020. On November 2, 2010, pursuant to an exchange offer, we replaced all of the 8.75% Senior Notes, which were issued under Rule 144A and Regulation S under the Securities Act, with 8.75% Senior Notes issued pursuant to a registration statement.

Private Placement of Convertible Perpetual Preferred Stock.On November 4, 2010, we agreed to issue, in a private offering under Rule 144A of the Securities Act, 2,500,000 shares of a new series of 7.0% convertible perpetual preferred stock for net proceeds of approximately $242.0 million, after applying a discount to the purchase price of the stock and deducting offering expenses. We also granted a 30-day option to the initial purchasers to purchase an additional 500,000 shares solely to cover over-allotments. We intend to use the net proceeds from this offering, including any additional proceeds from the exercise of the option to purchase additional shares, for general corporate purposes, including (i) to repay a portion of the amount outstanding under the senior credit facility and (ii) to fund the 2010 capital expenditure program. Closing of the private placement of the preferred stock offering is expected to occur on November 10, 2010 and will be subject to satisfaction of various customary closing conditions.

Recently Adopted Accounting Pronouncements

In January 2010, the FASB issued ASU 2010-03 to align the oil and natural gas reserve estimation and disclosure requirements of ASC Topic 932, Extractive Industries — Oil and Gas, with the requirements in the Securities and Exchange Commission’s final rule,Modernization of the Oil and Gas Reporting Requirements, which was issued on December 31, 2008 and was effective for the year ended December 31, 2009.Modernization of the Oil and Gas Reporting Requirements was designed to modernize and update the oil and gas disclosure requirements to align with current practices and changes in technology. We implemented ASU 2010-03 prospectively as a change in accounting principle inseparable from a change in accounting estimate at December 31, 2009.

In December 2009, the FASB issued ASU 2009-17, “Consolidations — Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” which codified FASB Statement No. 167, “Amendments to FASB Interpretation No. 46(R).” ASU 2009-17 represents a revision to former FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities,” and changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting or similar rights should be consolidated. ASU 2009-17 also requires enhanced disclosures about a reporting entity’s involvement with variable interest entities. We implemented ASU 2009-17 on January 1, 2010 with no impact on our financial position or results of operations.

In January 2010, the FASB issued ASU 2010-06, “Fair Value Measurements and Disclosures: Improving Disclosures about Fair Value Measurements.” ASU 2010-06 requires additional disclosures and clarifies existing disclosure requirements about fair value measurement as set forth in ASC Topic 820. We implemented the new

41

disclosures and clarifications of existing disclosure requirements under ASU 2010-06 effective with the first quarter of 2010, except for certain disclosure requirements regarding activity in Level 3 fair value measurements that are effective for fiscal years beginning after December 15, 2010. The implementation of ASU 2010-06 had no impact on our financial position or results of operations. As the additional requirements under ASU 2010-06, which will be implemented January 1, 2011, pertain to disclosure of Level 3 activity, no effect to our financial position or results of operations is expected.

42

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 such as our CO₂ gathering and sales operations and corporate operations. SandRidge Energy, Inc., the parent company, contributed its oil and natural gas related assets and liabilities to one of its wholly owned subsidiaries, effective as of May 1, 2009. As a result, the financial information of SandRidge Energy, Inc. is now included in the All Other column in the tables below, which is consistent with management’s evaluation of the business segments. SandRidge Energy, Inc. was previously included in the exploration and production segment. All periods presented below reflect this change in presentation.

Management evaluates the performance of our business segments based on operating income (loss), which is defined as segment operating revenues less operating expenses. 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 each of our business segments for the three and nine-month periods ended September 30, 2010 and 2009 (in thousands).

	Exploration  and Production			Drilling and Oil Field Services			Midstream  Gas Services			All Other			Consolidated Total
Three Months Ended September 30, 2010
Revenues	$	210,484		$	60,370		$	65,470		$	8,965		$	345,289
Inter-segment revenue		(63	)		(55,096	)		(42,545	)		(2,352	)		(100,056	)
Total revenues	$	210,421		$	5,274		$	22,925		$	6,613		$	245,233
Operating (loss) income	$	(65,642	)	$	(1,826	)	$	1,196		$	(21,158	)	$	(87,430	)
Interest income (expense), net		137			(201	)		(175	)		(63,333	)		(63,572	)
Other income, net		459			—			388			509			1,356
(Loss) income before income taxes	$	(65,046	)	$	(2,027	)	$	1,409		$	(83,982	)	$	(149,646	)
Three Months Ended September 30, 2009
Revenues	$	105,026		$	42,958		$	52,564		$	9,576		$	210,124
Inter-segment revenue		(66	)		(37,160	)		(36,644	)		(1,399	)		(75,269	)
Total revenues	$	104,960		$	5,798		$	15,920		$	8,177		$	134,855
Operating (loss) income	$	(31,122	)	$	(4,621	)	$	476		$	(14,962	)	$	(50,229	)
Interest expense, net		(14	)		(482	)		—			(52,616	)		(53,112	)
Other (expense) income, net		(1,144	)		—			593			—			(551	)
(Loss) income before income taxes	$	(32,280	)	$	(5,103	)	$	1,069		$	(67,578	)	$	(103,892	)

	Exploration  and Production			Drilling and Oil Field Services			Midstream  Gas Services			All Other			Consolidated Total
Nine Months Ended September 30, 2010
Revenues	$	531,239		$	202,419		$	214,386		$	28,162		$	976,206
Inter-segment revenue		(194	)		(187,473	)		(141,778	)		(8,094	)		(337,539	)
Total revenues	$	531,045		$	14,946		$	72,608		$	20,068		$	638,667
Operating income (loss)	$	180,846		$	(6,421	)	$	3,352		$	(56,585	)	$	121,192
Interest income (expense), net		337			(768	)		(474	)		(188,848	)		(189,753	)
Other income, net		1,240			—			444			378			2,062
Income (loss) before income taxes	$	182,423		$	(7,189	)	$	3,322		$	(245,055	)	$	(66,499	)
Nine Months Ended September 30, 2009
Revenues	$	330,686		$	192,747		$	218,769		$	21,983		$	764,185
Inter-segment revenue		(196	)		(175,540	)		(158,339	)		(2,143	)		(336,218	)
Total revenues	$	330,490		$	17,207		$	60,430		$	19,840		$	427,967
Operating loss(1)	$	(1,132,198	)	$	(10,177	)	$	(27,344	)	$	(46,777	)	$	(1,216,496	)
Interest expense, net		(62	)		(1,673	)		—			(134,346	)		(136,081	)
Other income, net		100			—			1,027			—			1,127
Loss before income taxes	$	(1,132,160	)	$	(11,850	)	$	(26,317	)	$	(181,123	)	$	(1,351,450	)

(1) The operating loss for the exploration and production segment for the nine-month period ended September 30, 2009 includes a $1,304.4 million non-cash full cost ceiling impairment on our oil and natural gas properties.

43

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 tables below. Changes in our results for these periods reflect, in part, the acquisition of oil and natural gas properties from Forest in December 2009 and Arena in July 2010, which increased production volumes and revenues for our exploration and production segment.

	Three Months Ended September 30,				Change
	2010		2009		Amount			Percent
Production data:
Oil (MBbl)(1)		2,219		723		1,496			206.9	%
Natural gas (MMcf)		19,100		20,897		(1,797	)		(8.6	)%
Combined equivalent volumes (MMcfe)		32,414		25,235		7,179			28.4	%
Average daily combined equivalent volumes (MMcfe/d)		352		274		78			28.5	%
Average prices — as reported(2):
Oil (per Bbl)(1)	$	63.90	$	62.76	$	1.14			1.8	%
Natural gas (per Mcf)	$	3.57	$	2.82	$	0.75			26.6	%
Combined equivalent (per Mcfe)	$	6.48	$	4.14	$	2.34			56.5	%
Average prices — including impact of derivative contract settlements:
Oil (per Bbl)(1)	$	64.74	$	66.47	$	(1.73	)		(2.6	)%
Natural gas (per Mcf)	$	5.02	$	6.67	$	(1.65	)		(24.7	)%
Combined equivalent (per Mcfe)	$	7.39	$	7.43	$	(0.04	)		(0.5	)%

	Nine Months Ended September 30,				Change
	2010		2009		Amount			Percent
Production data:
Oil (MBbl)(1)		4,774		2,163		2,611			120.7	%
Natural gas (MMcf)		57,473		67,583		(10,110	)		(15.0	)%
Combined equivalent volumes (MMcfe)		86,117		80,561		5,556			6.9	%
Average daily combined equivalent volumes (MMcfe/d)		315		295		20			6.8	%
Average prices — as reported(2):
Oil (per Bbl)(1)	$	64.18	$	51.02	$	13.16			25.8	%
Natural gas (per Mcf)	$	3.88	$	3.23	$	0.65			20.1	%
Combined equivalent (per Mcfe)	$	6.15	$	4.08	$	2.07			50.7	%
Average prices — including impact of derivative contract settlements:
Oil (per Bbl)(1)	$	67.12	$	55.40	$	11.72			21.2	%
Natural gas (per Mcf)	$	6.30	$	7.18	$	(0.88	)		(12.3	)%
Combined equivalent (per Mcfe)	$	7.92	$	7.51	$	0.41			5.5	%

(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 September 30, 2010 compared to the three months ended September 30, 2009

Exploration and production segment revenues increased $105.4 million, or 100.5%, to $210.4 million in the three months ended September 30, 2010 from $105.0 million in the three months ended September 30, 2009, as a result of a 56.5% increase in the combined average price we received for our oil and natural gas production. Also

44

contributing to the increase was the 206.9% increase in oil production, slightly offset by the 8.6% decrease in natural gas production volumes. In the three-month period ended September 30, 2010, oil production increased by 1,496 MBbls to 2,219 MBbls and natural gas production decreased by 1.8 Bcf to 19.1 Bcf from the comparable period in 2009. The increase in oil production was due to the addition of Permian Basin properties acquired from Forest and Arena, and a focus on increased oil drilling in 2010. Properties acquired from Forest and Arena produced 1,295 MBbls of oil for the three-month period ended September 30, 2010. 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.

The average price received for our oil production increased 1.8%, or $1.14 per barrel, to $63.90 per barrel during the three months ended September 30, 2010 from $62.76 per barrel during the same period in 2009. The average price we received for our natural gas production for the three-month period ended September 30, 2010 increased 26.6%, or $0.75 per Mcf, to $3.57 per Mcf from $2.82 per Mcf in the comparable period in 2009. Including the impact of derivative contract settlements, the effective price received for oil for the three-month period ended September 30, 2010 was $64.74 per Bbl compared to $66.47 per Bbl during the same period in 2009. Including the impact of derivative contract settlements, the effective price received for natural gas for the three-month period ended September 30, 2010 was $5.02 per Mcf compared to $6.67 per Mcf during the same period in 2009. 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 September 30, 2010, the exploration and production segment reported a $67.2 million net loss on our commodity derivative positions ($77.7 million realized gain and $144.9 million unrealized loss) compared to a $47.9 million net loss on our commodity derivative positions ($83.0 million realized gain and $130.9 million unrealized loss) in the same period in 2009. The realized gain of $77.7 million for the three months ended September 30, 2010 was primarily due to lower natural gas prices at the time of settlement compared to the contract price. Realized gains totaling $48.2 million resulting from settlements of commodity derivative contracts with original contractual maturities after September 30, 2010 were included in the realized gain for the three months ended September 30, 2010. 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 September 30, 2010 was primarily attributable to an increase in average oil prices at September 30, 2010 compared to the average oil prices at June 30, 2010 and the settlement of natural gas price swaps during the three months ended September 30, 2010. The unrealized loss for the three-month period ended September 30, 2009 was attributable to increased average oil and natural gas prices and decreases in the price differentials on our basis swaps at September 30, 2009.

For the three months ended September 30, 2010, we had an operating loss of $65.6 million in our exploration and production segment compared to an operating loss of $31.1 million for the same period in 2009. The $105.7 million increase in oil and natural gas revenues was more than offset by the $19.3 million increase in loss on commodity derivative contracts, a $24.6 million increase in production expenses, a $7.8 million increase in production taxes and a $58.2 million increase in depreciation and depletion on oil and natural gas properties. See discussion of production expense, production taxes and depreciation and depletion under “Consolidated Results of Operations.”

Exploration and Production Segment — Nine months ended September 30, 2010 compared to the nine months ended September 30, 2009

Exploration and production segment revenues increased $200.5 million, or 60.7%, to $531.0 million in the nine months ended September 30, 2010 from $330.5 million in the nine months ended September 30, 2009, as a result of a 50.7% increase in the combined average price we received for our oil and natural gas production. Also

45

contributing to the increase was the 120.7% increase in oil production, slightly offset by the 15.0% decrease in natural gas production. In the nine-month period ended September 30, 2010, oil production increased by 2,611 MBbls to 4,774 MBbls and natural gas production decreased by 10.1 Bcf to 57.5 Bcf from the comparable period in 2009. The increase in oil production was due to the addition of Permian Basin properties acquired from Forest and Arena and a focus on increased oil drilling in 2010. We produced 2,201 MBbls of oil from the properties we acquired from Forest and Arena during the nine-month period ended September 30, 2010. The decrease in natural gas production was a result of the decline in the number of rigs drilling for natural gas during 2009 and 2010 due to depressed natural gas prices.

The average price received for our oil production increased 25.8%, or $13.16 per barrel, to $64.18 per barrel during the nine months ended September 30, 2010 from $51.02 per barrel during the same period in 2009. The average price we received for our natural gas production for the nine-month period ended September 30, 2010 increased 20.1%, or $0.65 per Mcf, to $3.88 per Mcf from $3.23 per Mcf in the comparable period in 2009. Including the impact of derivative contract settlements, the effective price received for oil for the nine-month period ended September 30, 2010 was $67.12 per Bbl compared to $55.40 per Bbl during the same period in 2009. Including the impact of derivative contract settlements, the effective price received for natural gas for the nine-month period ended September 30, 2010 was $6.30 per Mcf compared to $7.18 per Mcf during the same period in 2009.

During the nine-month period ended September 30, 2010, the exploration and production segment reported a $114.4 million net gain on our commodity derivative positions ($238.2 million realized gain and $123.8 million unrealized loss) compared to a $139.7 million net gain on our commodity derivative positions ($276.2 million realized gain and $136.5 million unrealized loss) in the same period in 2009. The realized gain of $238.2 million for the nine months ended September 30, 2010 was primarily due to lower natural gas prices at the time of settlement compared to the contract price. Realized gains totaling $110.6 million resulting from settlements of commodity derivative contracts with original contractual maturities after the quarterly period in which they were settled were included in the realized gain for the nine months ended September 30, 2010. The unrealized loss on commodity contracts recorded during the nine months ended September 30, 2010 was attributable to an increase in average oil prices and decreases in the price differentials on our basis swaps at September 30, 2010 compared to the average oil prices and price differentials at December 31, 2009 or the contract price for contracts entered into during 2010. This amount was partially offset by decreases in the average price of natural gas at September 30, 2010 compared to the average price of natural gas at December 31, 2009, or as stated in the contract for contracts entered into during 2010. The unrealized loss for the nine-month period ended September 30, 2009 was attributable to increased average oil and natural gas prices and decreases in the price differentials on our basis swaps at September 30, 2009.

For the nine months ended September 30, 2010, we had operating income of $180.8 million in our exploration and production segment compared to an operating loss of $1,132.2 million for the same period in 2009. The $201.0 million increase in oil and natural gas revenues and the absence of a full cost ceiling limitation during the first nine months of 2010 were partially offset by the $25.3 million decrease in gains on commodity derivative contracts, a $43.6 million increase in production expenses, a $16.0 million increase in production taxes and a $70.3 million increase in depreciation and depletion of our oil and natural gas properties. See discussion of the 2009 period full cost ceiling limitation, production expense, production taxes 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 the demand for and 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

46

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 September 30, 2010, we owned 35 drilling rigs, through Lariat. The table below presents a summary of the rigs owned by Lariat:

	September 30,
	2010		2009
Rigs working for SandRidge		21		7
Rigs working for third parties		3		1
Idle rigs(1)		4		20
Total operational		28		28
Non-operational rigs(2)		3		3
Retired		4		—
Total rigs owned		35		31

(1) Includes one rig receiving stand-by rates from a third party at September 30, 2009. There were no rigs receiving stand-by rates at September 30, 2010.

(2) Includes one rig being constructed and two rigs being converted at September 30, 2010 and three rigs being serviced at September 30, 2009.

Until April 15, 2009, we indirectly owned, through Lariat and its partner CWEI, an additional 11 operational rigs through an investment in Larclay. Although our ownership in Larclay afforded us access to Larclay’s operational rigs, we did not control Larclay and, therefore, did not consolidate the results of its operations with ours. Only the activities of our wholly owned drilling and oil field services subsidiaries are included in the financial results of our drilling and oil field services segment. On April 15, 2009, Lariat completed an assignment to CWEI of Lariat’s 50% equity interest in Larclay pursuant to the terms of the Larclay Assignment entered into between Lariat and CWEI. Pursuant to the Larclay Assignment, Lariat assigned all of its right, title and interest in and to Larclay to CWEI effective as of April 15, 2009, and CWEI assumed all of the obligations and liabilities of Lariat relating to Larclay.

Drilling and Oil Field Services Segment — Three months ended September 30, 2010 compared to the three months ended September 30, 2009

Drilling and oil field services segment revenues decreased to $5.3 million in the three-month period ended September 30, 2010 from $5.8 million in the three-month period ended September 30, 2009 and drilling and oil field services segment expenses decreased $3.3 million to $7.1 million during the same period. The decrease in expense resulted in a reduced operating loss of $1.8 million in the three-month period ended September 30, 2010 compared to $4.6 million for the same period in 2009. The decline in revenues and expenses was primarily attributable to a decrease in services performed for third parties during 2010 as the amount of work performed for our own account increased.

Drilling and Oil Field Services Segment — Nine months ended September 30, 2010 compared to the nine months ended September 30, 2009

Drilling and oil field services segment revenues decreased to $14.9 million in the nine-month period ended September 30, 2010 from $17.2 million in the nine-month period ended September 30, 2009. Drilling and oil field services segment expenses decreased $6.0 million to $21.5 million for the nine-month period ended September 30, 2010. The decrease in expenses resulted in a reduced operating loss of $6.4 million for the nine-month period ended September 30, 2010 compared to $10.2 million in the same period in 2009. The decline in revenues and expenses was primarily attributable to a decrease in sales to and services performed for third parties during 2010 as the amount of work performed for our own account increased.

47

Midstream Gas Services Segment

Midstream gas services segment revenues consist mostly of revenue from gas marketing, which is a very low-margin business. 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 gas. Gas marketing operating costs represent payments made to third parties for the proceeds from the sale of gas owned by such parties, net of any applicable margin and actual costs we charge to gather, compress and treat the gas. The primary factors affecting midstream gas services are the quantity of gas we gather, treat and market and the prices we pay and receive for natural gas.

In June 2009, we completed the sale of our gathering and compression assets located in the Piñon Field of the WTO. Net proceeds from the sale were approximately $197.5 million, which resulted in a loss on the sale of $26.1 million. In conjunction with the sale, we entered into a gas gathering agreement and an operations and maintenance agreement. Under the gas gathering agreement, we have dedicated our Piñon Field acreage for priority gathering services for a period of 20 years and we will pay a fee for such services that was negotiated at arms’ length. Pursuant to the operations and maintenance agreement, we will operate and maintain the gathering system assets sold for a period of 20 years unless we or the buyer of the assets choose to terminate the agreement.

GRLP is a limited partnership that operates the Grey Ranch Plant located in Pecos County, Texas. We purchased our 50% equity investment in GRLP during 2003. On October 1, 2009, we executed amendments to certain agreements related to the ownership and operation of GRLP. As a result of these amendments, we became the primary beneficiary of GRLP. Accordingly, we began consolidating the activity of GRLP in our midstream gas services segment prospectively beginning on the effective date of the amendments.

Midstream Gas Services Segment — Three months ended September 30, 2010 compared to the three months ended September 30, 2009

Midstream gas services segment revenues for the three months ended September 30, 2010 were $22.9 million compared to $15.9 million in the same period in 2009. Operating income was $1.2 million for the three months ended September 30, 2010 compared to $0.5 million for the comparable period in 2009. The increase in midstream gas services segment revenues and operating income was due, in part, to the consolidation of GRLP activity into the midstream gas services segment for the three-month period ended September 30, 2010. Also contributing to the increase in revenues was an increase in natural gas prices for third party volumes we marketed in the three-month period ended September 30, 2010 compared to the same period in 2009. For the three-month period ended September 30, 2009, our share of GRLP activity was reported as income from equity investments.

Midstream Gas Services Segment — Nine months ended September 30, 2010 compared to the nine months ended September 30, 2009

Midstream gas services segment revenues for the nine months ended September 30, 2010 were $72.6 million compared to $60.4 million in the same period in 2009. Operating income was $3.4 million for the nine months ended September 30, 2010 compared to an operating loss of $27.3 million for the comparable period in 2009. The increase in midstream gas services segment revenues and operating income was due, in part, to the consolidation of GRLP activity into the midstream gas services segment for the nine-month period ended September 30, 2010. An increase in natural gas prices for third party volumes we marketed in the nine-month period ended September 30, 2010 compared to the same period in 2009 also contributed to the increase in revenues. The increase in operating income was primarily due to the inclusion of a $26.1 million loss on the sale of our gathering and compression assets in the nine months ended September 30, 2009. Prior to October 1, 2009 when we began consolidating GRLP, our share of GRLP activity was reported as income from equity investments.

48

Consolidated Results of Operations

Three months ended September 30, 2010 compared to the three months ended September 30, 2009

Revenues.Total revenues increased 81.8% to $245.2 million for the three months ended September 30, 2010 from $134.9 million in the same period in 2009. This increase was primarily due to a $105.7 million increase in oil and natural gas sales.

	Three Months Ended September 30,
	2010		2009		$ Change			% Change
	(In thousands)
Revenues:
Oil and natural gas	$	209,998	$	104,348	$	105,650			101.2	%
Drilling and services		5,252		5,798		(546	)		(9.4	)%
Midstream and marketing		23,281		16,453		6,828			41.5	%
Other		6,702		8,256		(1,554	)		(18.8	)%
Total revenues	$	245,233	$	134,855	$	110,378			81.8	%

Total oil and natural gas revenues increased $105.7 million to $210.0 million for the three months ended September 30, 2010 compared to $104.3 million for the same period in 2009, primarily as a result of an increase in the prices received on our production of oil and natural gas and increased oil production, offset slightly by decreased natural gas production. The combined average price received, excluding the impact of derivative contracts, for our oil and natural gas production increased 56.5% in the 2010 period to $6.48 per Mcfe compared to $4.14 per Mcfe in 2009. The 1,496 MBbl increase in oil production was primarily due to the properties acquired from Forest and Arena and a focus on increased oil drilling in 2010.

Midstream and marketing revenues increased $6.8 million, or 41.5%, with revenues of $23.3 million in the three-month period ended September 30, 2010 compared to $16.5 million in the three-month period ended September 30, 2009. The increase in midstream and marketing revenues was attributable to an increase in natural gas prices for third party volumes we marketed in the three-month period ended September 30, 2010 compared to the same period in 2009. Also, contributing to the increase was the inclusion of GRLP activity for the three-month period ended September 30, 2010. Prior to October 2009, GRLP was not consolidated.

Other revenues decreased to $6.7 million for the three months ended September 30, 2010 from $8.3 million for the same period in 2009. The decrease was due to lower CO₂ prices and volumes sold to third parties as well as higher CO₂ volumes provided for our own account during the three-month period ended September 30, 2010 compared to the same period in 2009.

49

Operating Costs and Expenses. Total operating costs and expenses increased to $332.7 million for the three months ended September 30, 2010 compared to $185.1 million for the same period in 2009. The increase was primarily due to increases in production expenses, production taxes, depreciation and depletion on oil and natural gas properties, general and administrative expenses and loss on derivative contracts.

	Three Months Ended September 30,
	2010			2009		$ Change			% Change
	(In thousands)
Operating costs and expenses:
Production	$	66,086		$	41,486	$	24,600			59.3	%
Production taxes		8,904			1,069		7,835			732.9	%
Drilling and services		4,187			9,168		(4,981	)		(54.3	)%
Midstream and marketing		20,779			15,261		5,518			36.2	%
Depreciation and depletion — oil and natural gas		91,237			33,060		58,177			176.0	%
Depreciation, depletion and amortization — other		12,441			12,092		349			2.9	%
General and administrative		61,878			25,006		36,872			147.5	%
Loss on derivative contracts		67,195			47,933		19,262			40.2	%
(Gain) loss on sale of assets		(44	)		9		(53	)		(588.9	)%
Total operating costs and expenses	$	332,663		$	185,084	$	147,579			79.7	%

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 $24.6 million primarily due to the addition of operating expenses associated with properties acquired from Forest and Arena. Additionally, higher production costs were incurred on oil production compared to production costs on natural gas volumes.

Production taxes increased $7.8 million, or 732.9%, to $8.9 million due to the additional taxes for production from properties acquired from Forest and Arena and a decrease in the amount of high-cost gas severance tax refunds received in the three-month period ended September 30, 2010 compared to the same period in 2009.

Drilling and services expenses, which include operating expenses attributable to the drilling and oil field services segment and our CO₂ services companies, decreased $5.0 million or 54.3% for the three months ended September 30, 2010 compared to the same period in 2009 primarily due to an increase in the amount of work performed and increased CO₂ volumes provided for our own account during the three-month period ended September 30, 2010 compared to the same period in 2009.

Midstream and marketing expenses increased $5.5 million, or 36.2%, to $20.8 million due to the consolidation of GRLP activity as well as increased prices of natural gas purchased from third parties during the three-month period ended September 30, 2010.

Depreciation and depletion for our oil and natural gas properties increased to $91.2 million for the three-month period ended September 30, 2010 from $33.1 million in the same period in 2009. The increase was primarily due to an increase in our depreciation and depletion per Mcfe to $2.81 in the third quarter of 2010 from $1.31 in the comparable period in 2009 as a result of an increase to our depreciable oil and natural gas properties, primarily due to the acquisition of properties from Forest and Arena.

General and administrative expenses increased $36.9 million, or 147.5% to $61.9 million for the three months ended September 30, 2010 from $25.0 million for the comparable period in 2009 primarily due to $10.7 million of fees incurred related to our acquisition of Arena, $16.0 million for the settlement of a dispute with certain working interest owners and increased compensation costs of $6.0 million resulting from an increase in non-cash stock compensation and the number of employees.

50

We recorded a net loss of $67.2 million ($77.7 million realized gain and $144.9 million unrealized loss) on our commodity derivative contracts for the three-month period ended September 30, 2010 compared to a net loss of $47.9 million ($83.0 million realized gain and $130.9 million unrealized loss) in the same period of 2009. 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 $62.2 million in the three-month period ended September 30, 2010 from $53.7 million in the three-month period ended September 30, 2009. The increase is reflected in the table below.

	Three Months Ended September 30,
	2010			2009			$ Change			% Change
	(In thousands)
Other income (expense):
Interest income	$	69		$	89		$	(20	)		(22.5	)%
Interest expense		(63,641	)		(53,201	)		(10,440	)		19.6	%
Income from equity investments		—			593			(593	)		(100.0	)%
Other income (expense), net		1,356			(1,144	)		2,500			(218.5	)%
Total other expense		(62,216	)		(53,663	)		(8,553	)		15.9	%
Loss before income taxes		(149,646	)		(103,892	)		(45,754	)		44.0	%
Income tax benefit		(457,248	)		(2,580	)		(454,668	)		17,622.8	%
Net income (loss)	$	307,602		$	(101,312	)	$	408,914			(403.6	)%

Interest expense increased to $63.6 million for the three months ended September 30, 2010 from $53.2 million for the same period in 2009. This increase was primarily attributable to the higher average debt balances outstanding during the three months ended September 30, 2010 compared to the same period in 2009 mainly due to increased borrowings under our senior credit facility during the period, and the issuance of our 8.75% Senior Notes in December 2009. The increase was slightly offset by a $1.2 million decrease in the net loss on our interest rate swaps for the three-month period ending September 30, 2010 compared to the same period in 2009.

We reported an income tax benefit of $457.3 million, net of income tax expense attributable to noncontrolling interest, for the three-month period ended September 30, 2010, compared to an income tax benefit of $2.6 million for the same period in 2009. The increase was primarily attributable to the release of a portion of the Company’s valuation allowance against its net deferred tax asset during the three months ended September 30, 2010. Net deferred tax liabilities recorded as a result of the Arena acquisition in July 2010 reduced our existing net deferred tax asset position, allowing a corresponding reduction in the valuation allowance against the net deferred tax asset.

51

Nine months ended September 30, 2010 compared to the nine months ended September 30, 2009

Revenues.Total revenues increased 49.2% to $638.7 million for the nine months ended September 30, 2010 from $428.0 million in the same period in 2009. This increase was primarily due to a $201.0 million increase in oil and natural gas sales.

	Nine Months Ended September 30,
	2010		2009		$ Change			% Change
	(In thousands)
Revenues:
Oil and natural gas	$	529,578	$	328,628	$	200,950			61.1	%
Drilling and services		14,913		17,207		(2,294	)		(13.3	)%
Midstream and marketing		73,868		62,051		11,817			19.0	%
Other		20,308		20,081		227			1.1	%
Total revenues	$	638,667	$	427,967	$	210,700			49.2	%

Total oil and natural gas revenues increased $201.0 million to $529.6 million for the nine months ended September 30, 2010 compared to $328.6 million for the same period in 2009, primarily as a result of an increase in the prices received on our production of oil and natural gas and increased oil production, offset slightly by decreased natural gas production. The combined average price received, excluding the impact of derivative contracts, for our oil and natural gas production increased 50.7% in the 2010 period to $6.15 per Mcfe compared to $4.08 per Mcfe in 2009. The increase in oil production was primarily due to the addition of properties acquired from Forest and Arena and a focus on increased oil drilling in 2010.

Drilling and services revenues decreased 13.3% to $14.9 million for the nine months ended September 30, 2010 compared to $17.2 million for the same period in 2009. The decrease was due to a decrease in sales of supplies to third parties and an increase in oil field services work performed for our own account with a corresponding decline in oil field services performed for third parties.

Midstream and marketing revenues increased $11.8 million, or 19.0%, with revenues of $73.9 million in the nine-month period ended September 30, 2010 compared to $62.1 million in the nine-month period ended September 30, 2009. The increase in revenues was primarily attributable to the inclusion of GRLP activity for the nine-month period ended September 30, 2010. Prior to October 2009, GRLP was not consolidated. Also contributing to the increase was an increase in the price of natural gas marketed for third parties.

52

Operating Costs and Expenses. Total operating costs and expenses decreased to $517.5 million for the nine months ended September 30, 2010 compared to $1,644.5 million for the same period in 2009. The decrease was primarily due to the absence of a $1,304.4 million full cost ceiling impairment and a decrease in loss on sale of assets during the nine-month period ended September 30, 2010 compared to the same period in 2009. These decreases were partially offset by increases in production expenses, production taxes, depreciation and depletion on oil and natural gas properties and general and administrative expenses and a decrease in gain on derivative contracts.

	Nine Months Ended September 30,
	2010			2009			$ Change			% Change
	(In thousands)
Operating costs and expenses:
Production	$	172,367		$	128,811		$	43,556			33.8	%
Production taxes		19,146			3,153			15,993			507.2	%
Drilling and services		12,420			19,884			(7,464	)		(37.5	)%
Midstream and marketing		66,064			58,083			7,981			13.7	%
Depreciation and depletion — oil and natural gas		197,834			127,503			70,331			55.2	%
Depreciation, depletion and amortization — other		36,564			38,851			(2,287	)		(5.9	)%
Impairment		—			1,304,418			(1,304,418	)		(100.0	)%
General and administrative		127,419			77,123			50,296			65.2	%
Gain on derivative contracts		(114,378	)		(139,722	)		25,344			(18.1	)%
Loss on sale of assets		39			26,359			(26,320	)		(99.9	)%
Total operating costs and expenses	$	517,475		$	1,644,463		$	(1,126,988	)		(68.5	)%

Production expenses increased $43.6 million for the nine months ended September 30, 2010 compared to the same period in 2009 primarily due to the addition of operating expenses associated with properties acquired from Forest and Arena. Also contributing to the increase were higher production costs associated with oil volumes compared to production costs on natural gas volumes. Oil production increased by 2,611 MBbls to 4,774 MBbls from the comparable period in 2009.

Production taxes increased $16.0 million, or 507.2%, to $19.1 million due to the additional taxes for production from properties acquired from Forest and Arena and a decrease in the amount of high-cost gas severance tax refunds received in the nine-month period ended September 30, 2010 compared to the same period in 2009.

Drilling and services expenses decreased $7.5 million, or 37.5%, for the nine months ended September 30, 2010 compared to the same period in 2009 primarily due to a decrease in purchases of supplies and an increase in the amount of work performed for our own account, partially offset by costs associated with performing maintenance on idle rigs to prepare for operation during the nine-month period ended September 30, 2010 compared to the same period in 2009.

Midstream and marketing expenses increased $8.0 million, or 13.7%, to $66.1 million due to the consolidation of GRLP activity as well as increased prices on natural gas purchased from third parties during the nine-month period ended September 30, 2010.

Depreciation and depletion of our oil and natural gas properties increased to $197.8 million for the nine-month period ended September 30, 2010 from $127.5 million in the same period in 2009. The increase was primarily due to an increase in our depreciation and depletion per Mcfe to $2.30 in the first nine months of 2010 from $1.58 in the comparable period in 2009 as a result of an increase to our depreciable oil and natural gas properties, primarily due to the acquisition of properties from Forest and Arena.

53

During the first nine months of 2009, we reduced the carrying value of our oil and natural gas properties by $1,304.4 million due to a full cost ceiling limitation at March 31, 2009. There were no full cost ceiling impairments recorded during the first nine months of 2010.

General and administrative expenses increased $50.3 million, or 65.2%, to $127.4 million for the nine months ended September 30, 2010 from $77.1 million for the comparable period in 2009 primarily due to $15.4 million in fees incurred related to our acquisition of Arena, $16.0 million for the settlement of a dispute with certain working interest owners and increased compensation costs resulting from an increase in non-cash stock compensation and the number of employees.

We recorded a net gain of $114.4 million ($238.2 million realized gain and $123.8 million unrealized loss) on our commodity derivative contracts for the nine-month period ended September 30, 2010 compared to a net gain of $139.7 million ($276.2 million realized gains and $136.5 million unrealized loss) in the same period of 2009. See further discussion of gains and losses on commodity derivative contracts under “Results by Segment — Exploration and Production Segment.”

Loss on sale of assets decreased $26.3 million, or 99.9%, for the nine months ended September 30, 2010 from a $26.4 million loss for the comparable period in 2009, primarily due to a $26.1 million loss recorded on the sale of our gathering and compression assets during the 2009 period.

Other Income (Expense). Total other expense increased to $187.7 million in the nine-month period ended September 30, 2010 from $135.0 million in the nine-month period ended September 30, 2009. The increase is reflected in the table below.

	Nine Months Ended September 30,
	2010			2009			$ Change			% Change
	(In thousands)
Other income (expense):
Interest income	$	236		$	287		$	(51	)		(17.8	)%
Interest expense		(189,989	)		(136,368	)		(53,621	)		39.3	%
Income from equity investments		—			1,027			(1,027	)		(100.0	)%
Other income, net		2,062			100			1,962			1,962.0	%
Total other expense		(187,691	)		(134,954	)		(52,737	)		39.1	%
Loss before income taxes		(66,499	)		(1,351,450	)		1,284,951			(95.1	)%
Income tax benefit		(457,086	)		(4,114	)		(452,972	)		11,010.5	%
Net income (loss)	$	390,587		$	(1,347,336	)	$	1,737,923			(129.0	)%

Interest expense increased to $190.0 million for the nine months ended September 30, 2010 from $136.4 million for the same period in 2009. This increase was primarily attributable to the higher average debt balances outstanding during the nine months ended September 30, 2010 compared to the same period in 2009 mainly due to increased borrowings under our senior credit facility during the period, and the issuance of our 8.75% Senior Notes in December 2009. Also contributing to the increase was a $17.5 million net loss on our interest rate swaps for the nine-month period ended September 30, 2010 compared to a $5.0 million net loss for the same period in 2009.

We reported an income tax benefit of $457.2 million, net of income tax expense attributable to noncontrolling interest, for the nine-month period ended September 30, 2010, compared to an income tax benefit of $4.1 million for the same period in 2009. The increase was primarily attributable to the release of a portion of the Company’s valuation allowance against its net deferred tax asset during the nine months ended September 30, 2010. Net deferred tax liabilities recorded as a result of the Arena acquisition in July 2010 reduced our existing net deferred tax asset position, allowing a corresponding reduction in the valuation allowance against the net deferred tax asset.

54

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, to a lesser extent, the sale of assets. 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 senior credit agreement.

At September 30, 2010, we had a working capital deficit of $304.3 million compared to a surplus of $30.4 million at December 31, 2009. Current assets decreased $97.8 million at September 30, 2010, compared to current assets at December 31, 2009, primarily due to a $94.6 million decrease in our current derivative contract assets resulting from the settlement of commodity derivative contracts during 2010, including settlement of commodity derivative contracts with original contractual maturities after September 30, 2010. Current liabilities increased $237.0 million primarily as a result of a $191.1 million increase in accounts payable and accrued expenses due to increased drilling activity and liabilities assumed as part of the Arena acquisition. Our current derivative contract liabilities increased $27.0 million due to increased liability positions on our natural gas basis swaps. Additionally, we recorded a provision of $98.0 million for the estimated contract loss related to construction of the Century Plant. The contract loss provision was net of accumulated costs on the contract and included in current liabilities.

Cash Flows

Our cash flows for the nine months ended September 30, 2010 and 2009 were as follows:

	Nine Months Ended September 30,
	2010			2009
	(In thousands)
Cash flows provided by operating activities	$	339,212		$	277,084
Cash flows used in investing activities		(714,098	)		(364,523	)
Cash flows provided by financing activities		369,614			101,445
Net (decrease) increase in cash and cash equivalents	$	(5,272	)	$	14,006

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 nine months ended September 30, 2010 and 2009 was $339.2 million and $277.1 million, respectively. The increase in cash provided by operating activities in 2010

55

compared to 2009 was primarily due to a 50.7% increase in the combined average prices we received for our oil and natural gas production, and increased oil production, resulting from the Forest and Arena acquisitions and a focus on increased oil drilling in 2010.

Cash Flows from Investing Activities

We dedicate and expect to continue to dedicate a substantial portion of our capital expenditure program toward the exploration, 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 $714.1 million in the nine-month period ended September 30, 2010 from $364.5 million in the comparable 2009 period primarily due to the Arena acquisition in July 2010 and receipt of proceeds from the sale of assets in the 2009 period that significantly offset capital expenditures during that period.

Capital Expenditures. Our capital expenditures, on an accrual basis, by segment for the nine-month periods ended September 30, 2010 and 2009 are summarized below:

	Nine Months Ended September 30,
	2010		2009
	(In thousands)
Capital Expenditures:
Exploration and production	$	706,056	$	470,519
Drilling and oil field services		26,509		2,770
Midstream gas services		46,902		43,788
Other		16,126		25,124
Total	$	795,593	$	542,201

Cash Flows from Financing Activities

Our financing activities provided $369.6 million in cash for the nine-month period ended September 30, 2010 compared to $101.4 million in the comparable period in 2009. Cash provided by financing activities during the nine months ended September 30, 2010 was primarily comprised of $416.8 million of net borrowings, representing borrowings under our senior credit facility reduced by payments on our debt, offset slightly by the payment of dividends on our 8.5% convertible perpetual preferred stock and our 6.0% convertible perpetual preferred stock and fees related to the amendment and restatement of the senior credit facility. Cash provided by financing activities during the nine months ended September 30, 2009 was generated primarily by the private placement of 8.5% convertible perpetual preferred stock and the registered underwritten offering of common stock that provided combined proceeds of approximately $351.0 million, the majority of which were used to pay down amounts outstanding under the senior credit facility.

Indebtedness

Senior Credit Facility.The amount we may borrow under our senior credit facility is limited to a borrowing base, which is currently $850.0 million, and is subject to periodic redeterminations. The borrowing base is available to be drawn on subject to limitations based on its terms and certain financial covenants. The borrowing base is determined based upon proved developed producing reserves, proved developed non-producing reserves and proved undeveloped 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.

56

In April 2010, we amended and restated our $1.75 billion senior credit facility, extending the maturity date to April 15, 2014 from November 21, 2011 and affirming the borrowing base at $850.0 million. The senior credit facility received commitments from 27 participating lender institutions, three of which were new to the bank group. The largest commitment held by any individual lender is 5.9%. Under the terms of the amended and restated facility, (a) the ratio of EBITDAX to interest expense plus current maturities of long-term debt has been eliminated and (b) our ability to make investments has been increased from the previous terms. In October 2010, the senior credit facility was further amended and effective with this amendment, the ratio of the secured indebtedness of the parties to the senior credit facility to EBITDAX may not exceed 2.0:1.0 at quarter end. The remaining covenants are largely unchanged from the agreement in effect prior to April 2010. We remain in compliance with all debt covenants and the next redetermination of the borrowing base is scheduled to occur in the second quarter of 2011.

Long-term obligations under the senior credit facility and other long-term debt consist of the following at September 30, 2010 (in thousands):

Senior credit facility	$	426,500
Other notes payable		25,657
Senior Floating Rate Notes due 2014		350,000
8.625% Senior Notes due 2015		650,000
9.875% Senior Notes due 2016, net of $13,231 discount		352,269
8.0% Senior Notes due 2018		750,000
8.75% Senior Notes due 2020, net of $7,063 discount		442,937
Total debt	$	2,997,363

The senior credit facility and the indentures governing the senior notes included in the table above contain financial covenants and include 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):

2010	$	2,335
2011		7,294
2012		1,051
2013		1,120
2014		777,690
Thereafter		2,228,167
Total debt	$	3,017,657

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.

Outlook

We have budgeted approximately $300.0 million for capital expenditures in the remainder of 2010 and $1.1 billion for 2011. Budgeted amounts include planned expenditures related to properties acquired from Arena and exclude acquisitions. The majority of our capital expenditures will be 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, asset sales and the availability of capital through the issuance of additional equity or long-term debt.

57

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. The energy markets and 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 and 2012 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 2013 oil production and no fixed price swap contracts are in place for our natural gas production beyond 2012 or oil production beyond 2013. In addition, we have and will continue to need to incur capital expenditures in 2010 in order 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, to fund those capital expenditures. Based on anticipated oil and natural gas prices, availability under our senior credit facility and anticipated proceeds from the sales or other strategic monetizations of assets, we expect to be able to fund our planned capital expenditures for the remainder of 2010 and 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. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding our derivative contracts.

As of September 30, 2010, our cash and cash equivalents were $2.6 million and we had approximately $3.0 billion in total debt outstanding with $426.5 million outstanding under our senior credit facility. As of and for the three and nine-month periods ended September 30, 2010, we were in compliance with all of the covenants under all of our senior notes and our senior credit facility. As of November 3, 2010, our cash and cash equivalents were approximately $1.7 million, the balance outstanding under our senior credit facility was $513.0 million and we had $25.4 million outstanding in letters of credit.

If future capital expenditures exceed operating cash flow and cash on hand, funds would likely be supplemented as needed by borrowings under our senior credit facility. We may choose to refinance borrowings outstanding under the facility by issuing equity or long-term debt in the public or private markets, or both.

Volatility in the capital markets may increase costs associated with issuing debt due to increased interest rates, and may affect our ability to access these markets. Currently, we do not believe our liquidity has been, or in the near future will be, materially affected by recent events in the global financial markets. Nevertheless, we continue to monitor events and circumstances surrounding each of the lenders under our senior credit facility. We cannot predict with any certainty the impact to us of any disruptions in the credit markets.

Based upon the current level of operations and anticipated growth, we believe our cash flow from operations, current cash on hand and availability under our senior credit facility, together with anticipated proceeds from asset sales and potential access to the credit markets, will be sufficient to meet our capital expenditures budget, debt service requirements and working capital needs for the next twelve months. We have the ability to reduce our capital expenditures budget if cash flows are not available.

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,

58

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. We do not intend to enter into derivative contracts that would exceed our expected production volumes for the period covered by the derivative arrangement. Our senior credit agreement limits our ability to enter into derivative transactions to 85% of expected production volumes from estimated proved reserves. Future credit agreements could require a minimum level of commodity price hedging.

The use of derivative contracts also 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 September 30, 2010, we had 21 approved derivative counterparties, 19 of which are lenders under our senior credit facility. We currently have derivative contracts outstanding with 17 of these counterparties, 15 of which are lenders under our senior credit facility.

We use, and may continue to use, a variety of commodity-based derivative contracts, including fixed-price swaps 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.

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.

59

On September 30, 2010, our open oil and natural gas commodity derivative contracts consisted of the following:

Oil

Period and Type of Contract	Notional (in MBbl)		Weighted Avg. Fixed Price		Collar High		Collar Low
October 2010 — December 2010
Price swap contracts		1,564	$	80.46	$	—	$	—
Collars		276	$	—	$	92.95	$	66.67
January 2011 — March 2011
Price swap contracts		1,953	$	86.20	$	—	$	—
April 2011 — June 2011
Price swap contracts		1,975	$	86.20	$	—	$	—
July 2011 — September 2011
Price swap contracts		2,180	$	85.96	$	—	$	—
October 2011 — December 2011
Price swap contracts		2,180	$	85.96	$	—	$	—
January 2012 — March 2012
Price swap contracts		2,275	$	87.18	$	—	$	—
April 2012 — June 2012
Price swap contracts		2,366	$	87.10	$	—	$	—
July 2012 — September 2012
Price swap contracts		2,422	$	87.08	$	—	$	—
October 2012 — December 2012
Price swap contracts		2,484	$	87.04	$	—	$	—
January 2013 — March 2013
Price swap contracts		360	$	87.23	$	—	$	—
April 2013 — June 2013
Price swap contracts		364	$	87.23	$	—	$	—
July 2013 — September 2013
Price swap contracts		368	$	87.23	$	—	$	—
October 2013 — December 2013
Price swap contracts		368	$	87.23	$	—	$	—

60

Natural Gas

Period and Type of Contract	Notional (MMcf)(1)		Weighted Avg. Fixed Price			Collar High		Collar Low
October 2010 — December 2010
Price swap contracts		9,760	$	4.20		$	—	$	—
Basis swap contracts		20,700	$	(0.74	)		—		—
Collars		460	$	—		$	7.87	$	4.00
January 2011 — March 2011
Price swap contracts		12,600	$	4.72		$	—	$	—
Basis swap contracts		25,650	$	(0.47	)	$	—		—
April 2011 — June 2011
Price swap contracts		12,740	$	4.72		$	—	$	—
Basis swap contracts		25,935	$	(0.47	)	$	—	$	—
July 2011 — September 2011
Price swap contracts		12,880	$	4.72		$	—	$	—
Basis swap contracts		26,220	$	(0.47	)	$	—	$	—
October 2011 — December 2011
Price swap contracts		12,880	$	4.72		$	—	$	—
Basis swap contracts		26,220	$	(0.47	)	$	—	$	—
January 2012 — March 2012
Price swap contracts		9,100	$	5.23		$	—	$	—
Basis swap contracts		28,210	$	(0.55	)	$	—	$	—
April 2012 — June 2012
Price swap contracts		9,100	$	5.23		$	—	$	—
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	)	$	—	$	—

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

The following table summarizes the cash settlements and valuation gains and losses on our commodity derivative contracts for the three and nine-month periods ended September 30, 2010 and 2009 (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Realized gain(1)	$	(77,692	)	$	(83,038	)	$	(238,240	)	$	(276,175	)
Unrealized loss		144,887			130,971			123,862			136,453
Loss (gain) on commodity derivative contracts	$	67,195		$	47,933		$	(114,378	)	$	(139,722	)

(1) Includes $48.2 million and $110.6 million of realized gains for the three and nine-month periods ended September 30, 2010, respectively, related to settlements of commodity derivative contracts with contractual maturities after the quarterly period in which they were settled.

61

Credit Risk. We minimize the volatility of our liquidity by entering into derivative contracts that enable us to mitigate a portion of our exposure to oil and natural gas prices and interest rate volatility. We periodically review the credit quality of each counterparty to our derivative contracts and the level of 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. The weighted average credit default swap rate for our counterparties was 0.7% and 0.3% at September 30, 2010 and December 31, 2009, respectively.

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 5.9%.

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. We have entered into 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 September 30, 2010, 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 and $2.6 million for the three and nine-month periods ended September 30, 2010, respectively.

The following table summarizes the cash settlements and valuation gains and losses on our interest rate swaps for the three and nine-month periods ended September 30, 2010 and 2009 (in thousands):

	Three Months  Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Realized loss	$	1,883	$	1,826	$	6,046	$	4,131
Unrealized loss		3,253		4,519		11,502		860
Loss on interest rate swaps	$	5,136	$	6,345	$	17,548	$	4,991

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

62

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 September 30, 2010 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 September 30, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

63

PART II. Other Information

ITEM 1.Legal Proceedings

On July 16, 2010, SandRidge and one of its subsidiaries completed the acquisition of all of the outstanding shares of common stock of Arena. As disclosed in SandRidge’s Quarterly Report on Form 10-Q for the period ended March 31, 2010, after the April 3, 2010 announcement of the transaction, nine putative class action lawsuits challenging the transaction were filed in state and federal court in Oklahoma and state court in Nevada by Arena shareholders. The titles of the nine shareholder lawsuits, the courts in which they were filed, and the dates they were filed are as follows:

1. Thomas Slater v. Arena Resources, Inc., et al. — filed in District Court in Tulsa County, Tulsa, Oklahoma on April 6, 2010;

2. City of Pontiac General Employees’ Retirement System v. Arena Resources, Inc., et al. — filed in District Court in Washoe County, Reno, Nevada on April 8, 2010;

3. West Palm Beach Police Pension Fund v. Rochford, et al. — filed in District Court in Clark County, Las Vegas, Nevada on April 12, 2010;

4. Henry Kolesnik v. Arena Resources, Inc., et al — filed in District Court in Washoe County, Reno, Nevada on April 14, 2010;

5. Richard J. Erickson v. Arena Resources, Inc., et al. — filed in Tulsa County, Tulsa, Oklahoma on April 16, 2010; and

6. Thomas Stevenson v. Rochford, et al. — filed in the United States District Court for the Northern District of Oklahoma on April 26, 2010.

7. Raymond M. Eberhardt v. Arena Resources, Inc., et al. — filed in District Court in Oklahoma County, Oklahoma City, Oklahoma on April 8, 2010;

8. Roger and Kanya Tiemchan Phillips v. Rochford, et al. — filed in District Court in Oklahoma County, Oklahoma City, Oklahoma on April 16, 2010; and

9. Reinfried v. Arena Resources, Inc., et al. — filed in Oklahoma County, Oklahoma City, Oklahoma on April 20, 2010.

All nine lawsuits asserted, based on substantially similar allegations, that Arena’s directors breached their fiduciary duties by negotiating and approving the transaction and by administering a sale process that failed to maximize shareholder value and that Arena, SandRidge and/or a subsidiary of SandRidge aided and abetted such alleged breaches of fiduciary duty. One of the lawsuits, the action filed in the United States District Court for the Northern District of Oklahoma, also alleged violations of federal securities laws in connection with allegedly issuing an incomplete and misleading proxy statement. The lawsuits sought, among other relief, an injunction preventing the consummation of the merger and, in certain cases, unspecified damages.

As disclosed in SandRidge’s Quarterly Report on Form 10-Q for the period ended June 30, 2010, in order to avoid the cost, disruption and uncertainty of litigation – and without admitting any liability or wrongdoing – on May 27, 2010, SandRidge and Arena reached an agreement to settle six of the putative stockholder class actions related to the merger, including five of the lawsuits filed in state courts in Nevada and Oklahoma and the lawsuit filed in federal court, all of which (collectively, the “Coordinated Actions”) had been proceeding on a coordinated basis for purposes of discovery before the District Court in Washoe County, Reno, Nevada (the “Nevada Court”).

On September 30, 2010, the Nevada Court entered an Order Approving Final Class Action Settlement (the “Final Approval Order”) and Award of Attorneys Fees, which approved the terms of the settlement, overruled all objections to the settlement, and certified a class (the “Settlement Class”) consisting, with certain exceptions, of

64

all persons and entities who owned Arena common stock during the period from April 3, 2010 through the Effective Time of the Merger (as defined in the Merger Agreement). Pursuant to the Court’s order and the Stipulation of Settlement, certain claims of the Settlement Class were released, and the Coordinated Actions were dismissed with prejudice. The Court’s order also released, and enjoined Settlement Class members from prosecuting, the claims filed by the plaintiffs in the three lawsuits that were not part of the Coordinated Action.

On November 1, 2010, Raymond M. Eberhardt and Tanya Kiemchan Phillips, two former shareholders of Arena who had filed objections to the settlement in the Nevada Court, filed a Notice of Appeal appealing the Final Approval Order to the Nevada Supreme Court. SandRidge intends to vigorously defend the enforcement of the Final Approval Order.

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

We describe certain of our business risk factors below. This description includes material changes to the description of the risk factors previously disclosed in Part I, Item 1A of the 2009 Form 10-K.

The integration of SandRidge and Arena will present significant challenges.

The integration of the operations of SandRidge and Arena requires the dedication of management resources, which temporarily detracts attention from our day-to-day business. The difficulties of assimilation may be increased by the necessity of coordinating geographically separated organizations, integrating operations and systems and personnel with disparate business backgrounds and combining different corporate cultures. The process of combining the organizations may cause an interruption of, or a loss of momentum in, the activities of any or all of our business, which could have an adverse effect on our revenues and operating results, at least in the near term. The failure to successfully integrate SandRidge and Arena or to successfully manage the challenges presented by the integration process may result in our inability to achieve the anticipated potential benefits of the merger.

New derivatives legislation and regulation could adversely affect our ability to hedge risks associated with our business.

On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”). The Dodd-Frank Act creates a new regulatory framework for oversight of derivatives transactions by the Commodity Futures Trading Commission (the “CFTC”) and the Securities and Exchange Commission (the “SEC”). Among other things, the Dodd-Frank Act subjects certain swap participants to new capital, margin and business conduct standards. In addition, the Dodd-Frank Act contemplates that where appropriate in light of outstanding exposures, trading liquidity and other factors, swaps (broadly defined to include most hedging instruments other than futures) will be required to be cleared through a registered clearing facility and traded on a designated exchange or swap execution facility. There are some exceptions to these requirements for entities that use swaps to hedge or mitigate commercial risk. While we may qualify for one or more of such exceptions, the scope of these exceptions is uncertain and will be further defined through rulemaking proceedings at the CFTC and SEC in the coming months. Further, although we may qualify for exceptions, our derivatives counterparties may be subject to new capital, margin and business conduct requirements imposed as a result of the new legislation, which may increase our transaction costs or make it more difficult for us to enter into hedging transactions on favorable terms. Our inability to enter into hedging transactions on favorable terms, or at all, could increase our operating expenses and put us at increased exposure to the risk of adverse changes in oil and natural gas prices, which could adversely affect the predictability of cash flows from sales of oil and natural gas.

65

The Dodd-Frank Act also expands the CFTC’s power to impose position limits on specific categories of swaps (excluding swaps entered into forbona fide hedging purposes), and establishes a new Energy and Environmental Markets Advisory Committee to make recommendations to the CFTC regarding matters of concern to exchanges, firms, end users and regulators with respect to energy and environmental markets.

Additionally, in January 2010, the CFTC proposed rules to establish position limits on derivatives that reference major energy commodities, including oil and natural gas. The proposed all-months-combined position limits would be 10% of the first 25,000 contracts of open interest and 2.5% of open interest beyond 25,000 contracts. Although the current version of the CFTC’s proposal includes an exemption forbona fide hedges relating to inventory or anticipatory purchases or sales of the commodity, the CFTC is evaluating whether position limits should be applied consistently across all markets and participants.

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 recorded as treasury shares. During the quarter ended September 30, 2010, 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
July 1, 2010 — July 31, 2010		262,999	$	6.26		N/A		N/A
August 1, 2010 — August 31, 2010		114,963	$	6.54		N/A		N/A
September 1, 2010 — September 30, 2010		17,900	$	4.78		N/A		N/A

ITEM 6. Exhibits

See the Exhibit Index accompanying this Quarterly Report.

66

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/    DIRK M. VAN DOREN
	Dirk M. Van Doren Executive Vice President and Chief Financial Officer

Date: November 8, 2010

67

EXHIBIT INDEX

		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date	Filed Herewith
3.1	Certificate of Incorporation of SandRidge Energy, Inc.	S-1	333-148956	3.1	01/30/2008
3.2	Certificate of Amendment to the Certificate of Incorporation of SandRidge Energy, Inc., dated July 16, 2010	10-Q	001-33784	3.2	08/09/2010
3.3	Amended and Restated Bylaws of SandRidge Energy, Inc.	8-K	001-33784	3.1	03/09/2009
31.1	Section 302 Certification — Chief Executive Officer					*
31.2	Section 302 Certification — Chief Financial Officer					*
32.1	Section 906 Certifications of Chief Executive Officer and Chief Financial Officer					*
101.INS	XBRL Instance Document					*
101.SCH	XBRL Taxonomy Extension Schema Document					*
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document					*
101.DEF	XBRL Taxonomy Extension Definition Document					*
101.LAB	XBRL Taxonomy Extension Label Linkbase Document					*
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document					*

68