SandRidge Energy (SD) 10-Q 2009 Q1 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 March 31, 2009
OR
o	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 (Address of principal executive offices)	73102 (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 o

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 ofRegulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes o     No o

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

Large accelerated filer þ Accelerated filer o Non-accelerated filer o Smaller reporting company o

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined inRule 12b-2 of the Exchange Act).  Yes o     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 April 30, 2009, was 181,898,103.

SANDRIDGE ENERGY, INC.
FORM 10-Q
Quarter Ended March 31, 2009

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	32
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	44
ITEM 4.	Controls and Procedures	47
PART II. OTHER INFORMATION
ITEM 1.	Legal Proceedings	47
ITEM 1A.	Risk Factors	47
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47
ITEM 6.	Exhibits	47
EX-31.1
EX-31.2
EX-32.1
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

2

DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS

This quarterly report onForm 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Various statements contained in this report, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements. The forward-looking statements include projections and estimates concerning 2009 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 and assumptions about future events. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including the risk factors discussed in Item 1A of our Annual Report onForm 10-K for the year ended December 31, 2008, the opportunities that may be presented to and pursued by us, competitive actions by other companies, changes in laws or regulations and other factors, many of which are beyond our control. 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 or our business or operations. The forward-looking statements contained herein are not guarantees of future performance and actual results or developments may differ materially from those projected in the 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

	March 31,			December 31,
	2009			2008
	(Unaudited)
	(In thousands,
	except per share data)
ASSETS
Current assets:
Cash and cash equivalents	$	76		$	636
Accounts receivable, net:
Trade		78,122			102,746
Related parties		483			6,327
Derivative contracts		270,170			201,111
Inventories		3,682			3,686
Costs in excess of billings		16,234			—
Other current assets		39,055			41,407
Total current assets		407,822			355,913
Natural gas and crude oil properties, using full cost method of accounting
Proved		4,933,712			4,676,072
Unproved		221,161			215,698
Less: accumulated depreciation, depletion and impairment		(3,732,599	)		(2,369,840	)
		1,422,274			2,521,930
Other property, plant and equipment, net		676,551			653,629
Derivative contracts		84,736			45,537
Investments		7,374			6,088
Restricted deposits		32,796			32,843
Other assets		39,032			39,118
Total assets	$	2,670,585		$	3,655,058
LIABILITIES AND EQUITY
Current liabilities:
Current maturities of long-term debt	$	16,408		$	16,532
Accounts payable and accrued expenses:
Trade		267,832			366,337
Related parties		—			230
Derivative contracts		5,184			5,106
Asset retirement obligation		126			275
Billings in excess of costs incurred		—			14,144
Total current liabilities		289,550			402,624
Long-term debt		2,392,289			2,358,784
Other long-term obligations		11,967			11,963
Derivative contracts		3,809			3,639
Asset retirement obligation		87,233			84,497
Total liabilities		2,784,848			2,861,507
Commitments and contingencies (Note 13)
Equity:
SandRidge Energy, Inc. stockholders’ equity:
Preferred stock, $0.001 par value, 50,000 shares authorized:
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at March 31, 2009 and no shares issued and outstanding in 2008; aggregate liquidation preference of $265,000 at March 31, 2009		3			—
Common stock, $0.001 par value, 400,000 shares authorized; 168,968 issued and 167,572 outstanding at March 31, 2009 and 167,372 issued and 166,046 outstanding at December 31, 2008		163			163
Additional paid-in capital		2,418,547			2,170,986
Treasury stock, at cost		(19,845	)		(19,332	)
Accumulated deficit		(2,513,153	)		(1,358,296	)
Total SandRidge Energy, Inc. stockholders’ (deficit) equity		(114,285	)		793,521
Noncontrolling interest		22			30
Total (deficit) equity		(114,263	)		793,551
Total liabilities and equity	$	2,670,585		$	3,655,058

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

4

SandRidge Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations

	Three Months Ended March 31,
	2009			2008
	(Unaudited)
	(In thousands,
	except per share data)
Revenues:
Natural gas and crude oil	$	121,241		$	205,487
Drilling and services		6,395			12,334
Midstream and marketing		25,956			46,409
Other		5,421			4,856
Total revenues		159,013			269,086
Expenses:
Production		45,579			34,188
Production taxes		1,491			9,220
Drilling and services		5,606			7,169
Midstream and marketing		23,362			40,418
Depreciation, depletion and amortization — natural gas and crude oil		60,093			65,076
Depreciation, depletion and amortization — other		12,726			17,965
Impairment		1,304,418			—
General and administrative		28,485			20,994
(Gain) loss on derivative contracts		(206,647	)		136,844
Loss on sale of assets		180			23
Total expenses		1,275,293			331,897
Loss from operations		(1,116,280	)		(62,811	)
Other income (expense):
Interest income		11			813
Interest expense		(40,748	)		(25,172	)
Income from equity investments		234			859
Other income (expense), net		760			(17	)
Total other (expense) income		(39,743	)		(23,517	)
Loss before income tax benefit		(1,156,023	)		(86,328	)
Income tax benefit		(1,169	)		(30,538	)
Net loss		(1,154,854	)		(55,790	)
Less: net income attributable to noncontrolling interest		3			835
Net loss attributable to SandRidge Energy, Inc.		(1,154,857	)		(56,625	)
Preferred stock dividends and accretion		—			9,582
Loss applicable to SandRidge Energy, Inc. common stockholders	$	(1,154,857	)	$	(66,207	)
Basic and diluted loss per share applicable to SandRidge Energy, Inc. common stockholders	$	(7.07	)	$	(0.47	)
Weighted average number of common shares outstanding:
Basic		163,321			141,044
Diluted		163,321			141,044

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

	SandRidge Energy, Inc. Stockholders
	8.5% Convertible
	Perpetual Preferred								Additional
	Stock				Common Stock				Paid-In			Treasury			Accumulated			Noncontrolling
	Shares		Amount		Shares		Amount		Capital			Stock			Deficit			Interest			Total
	(Unaudited)
	(In thousands)
Three months ended March 31, 2009
Balance, December 31, 2008		—	$	—		166,046	$	163	$	2,170,986		$	(19,332	)	$	(1,358,296	)	$	30		$	793,551
Distributions to noncontrolling interest owners		—		—		—		—		—			—			—			(11	)		(11	)
Issuance of 8.5% convertible perpetual preferred stock		2,650		3		—		—		243,286			—			—			—			243,289
Purchase of treasury stock		—		—		—		—		—			(513	)		—			—			(513	)
Stock-based compensation		—		—		—		—		6,388			—			—			—			6,388
Stock-based compensation excess tax benefit		—		—		—		—		(2,113	)		—			—			—			(2,113	)
Issuance of restricted stock awards, net of cancellations		—		—		1,526		—		—			—			—			—			—
Net (loss) income		—		—		—		—		—			—			(1,154,857	)		3			(1,154,854	)
Balance, March 31, 2009		2,650	$	3		167,572	$	163	$	2,418,547		$	(19,845	)	$	(2,513,153	)	$	22		$	(114,263	)

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

	Three Months Ended
	March 31,
	2009			2008
	(Unaudited)
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(1,154,854	)	$	(55,790	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		72,819			83,041
Impairment		1,304,418			—
Debt issuance cost amortization		1,611			1,097
Deferred income taxes		4			(30,617	)
Unrealized (gain) loss on derivative contracts		(108,010	)		143,367
Loss on sale of assets		180			23
Investment loss (income) — restricted deposits		47			(192	)
Income from equity investments		(234	)		(859	)
Stock-based compensation		5,205			3,241
Stock-based compensation excess tax benefit		(2,113	)		—
Changes in operating assets and liabilities		(45,842	)		13,378
Net cash provided by operating activities		73,231			156,689
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant and equipment		(350,184	)		(418,650	)
Proceeds from sale of assets		247			452
Fundings of restricted deposits		—			(781	)
Net cash used in investing activities		(349,937	)		(418,979	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		559,099			340,220
Repayments of borrowings		(525,718	)		(128,937	)
Dividends paid — preferred		—			(9,516	)
Noncontrolling interest distributions		(11	)		(632	)
Proceeds from issuance of 8.5% convertible perpetual preferred stock		243,289			—
Purchase of treasury stock		(513	)		(1,254	)
Net cash provided by financing activities		276,146			199,881
NET DECREASE IN CASH AND CASH EQUIVALENTS		(560	)		(62,409	)
CASH AND CASH EQUIVALENTS, beginning of year		636			63,135
CASH AND CASH EQUIVALENTS, end of period	$	76		$	726
Supplemental Disclosure of Noncash Investing and Financing Activities:
Change in accrued capital expenditures	$	(53,024	)	$	—
Accretion on redeemable convertible preferred stock	$	—		$	1,487

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. and its subsidiaries (collectively, the “Company” or “SandRidge”) is an independent natural gas and crude oil company concentrating on exploration, development and production activities. The Company also owns and operates natural gas gathering and treating facilities and CO₂ treating and transportation facilities and has marketing and tertiary oil recovery operations. In addition, Lariat Services, Inc. (“Lariat”), a wholly owned subsidiary, 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. The Company also operates interests in the Mid-Continent, the Cotton Valley Trend in East Texas, the Gulf Coast and the Gulf of Mexico.

Interim Financial Statements.  The accompanying condensed consolidated financial statements as of December 31, 2008 have been derived from the audited financial statements contained in the Company’s Annual Report onForm 10-K for the fiscal year ended December 31, 2008 (the “2008Form 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 2008Form 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, consisting 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 2008Form 10-K.

2.   Significant Accounting Policies

For a description of the Company’s accounting policies, refer to Note 1 of the consolidated financial statements included in the 2008Form 10-K.

Reclassifications.  Certain reclassifications have been made in prior period financial statements to conform with current period presentation.

Recent Accounting Pronouncements.  Effective January 1, 2008, the Company implemented Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements,” for its financial assets and liabilities measured on a recurring basis. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands required disclosures about fair value measurements. See Note 3.

In October 2008, the Financial Accounting Standards Board (“FASB”) issued Staff PositionFAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active,”(“FSP 157-3”) which was effective upon issuance.FSP 157-3 clarifies the application of SFAS No. 157 in determining the fair value of a financial asset when the market for that financial asset is not active. As of March 31, 2009, the Company had no financial assets with a market that was not active. Accordingly,FSP 157-3 had no effect on the Company’s current financial statements.

Effective January 1, 2009, the Company implemented SFAS No. 157 for certain of its nonfinancial liabilities, in accordance with Staff PositionFAS 157-2, “Effective Date of FASB Statement No. 157”(“FSP 157-2”), which delayed the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and liabilities except those recognized or disclosed at fair value in the financial statements on a recurring basis, at least annually. This implementation did not have a material impact on the Company’s financial position or results of operations.

8

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

Effective January 1, 2009, the Company implemented SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an Amendment of Accounting Research Bulletin No. 51,” which established accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. SFAS No. 160 also establishes disclosure requirements to clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. The implementation of SFAS No. 160 resulted in changes to the presentation for noncontrolling interests and did not have a material impact on the Company’s results of operations and financial condition. All historical periods presented in the condensed consolidated financial statements reflect these changes to the presentation for noncontrolling interests. See Note 15.

Effective January 1, 2009, the Company implemented SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” which changed disclosure requirements for derivative instruments and hedging activities. SFAS No. 161 requires enhanced disclosure, including qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses on derivative instruments and disclosures about credit-risk-related contingent features in derivative agreements. The implementation of SFAS No. 161 did not have a material impact on the Company’s results of operations or financial condition. See Note 10.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations,” which replaces SFAS No. 141. SFAS No. 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any noncontrolling interest in the acquiree and the goodwill acquired. SFAS No. 141(R) also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS No. 141(R) is effective for business combinations with acquisition dates on or after fiscal years beginning after December 15, 2008. The Company will evaluate this standard with respect to business combinations with acquisition dates on or after January 1, 2009.

On December 31, 2008, the Securities and Exchange Commission (“SEC”) issued ReleaseNo. 33-8995, “Modernization of Oil and Gas Reporting,” which revises disclosure requirements for oil and gas companies. In addition to changing the definition and disclosure requirements for natural gas and crude oil reserves, the new rules change the requirements for determining natural gas and crude oil reserve quantities to permit the use of new technologies to determine proved reserves under certain criteria and allow companies to disclose their probable and possible reserves. The new rules also require companies to report the independence and qualifications of their reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit. The new rules also require natural gas and crude oil reserves to be reported and the full cost ceiling limitation to be calculated using a twelve-month average price rather than period-end prices. The use of a twelve-month average price could have had an effect on the Company’s 2008 and 2009 depletion rates for its natural gas and crude oil properties. The new rules are effective for annual reports onForm 10-K for fiscal years ending on or after December 31, 2009, pending the contemplated alignment of certain accounting standards by the FASB with the new rules. The Company plans to implement the new requirements beginning in its Annual Report onForm 10-K for the year ended December 31, 2009. The Company is currently evaluating the impact of the new requirements on its consolidated financial statements.

In April 2009, the FASB issued Staff PositionFAS 107-1 and APB28-1, “Interim Disclosures about Fair Value of Financial Instruments,” (“FSPFAS 107-1 and APB28-1”) which amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” and Accounting Principles Board Opinion 28, “Interim Financial Reporting,” to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. FSPFAS 107-1 and APB28-1 is effective for interim reporting periods ending after June 15, 2009. This implementation is expected to have no impact on the Company’s results of operations and financial condition, but will require additional disclosures about the fair value of financial

9

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

instruments in the Company’s financial statements. The Company plans to implement the new requirements in its June 30, 2009 financial statements.

3.   Fair Value Measurements

Effective January 1, 2008, the Company implemented SFAS No. 157 for its financial assets and liabilities measured on a recurring basis. Effective January 1, 2009, the Company implemented SFAS No. 157 for certain nonfinancial liabilities based onFSP 157-2, which delayed the effective date of SFAS No. 157 by one year for certain nonfinancial assets and liabilities, with no material impact to the Company’s financial position or results of operations as a result of this implementation. SFAS No. 157 applies to all assets and liabilities that are measured and reported on a fair value basis.

As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. SFAS No. 157 requires disclosure that establishes a framework for measuring fair value and expands disclosure about fair value measurements. The statement requires fair value measurements be classified and disclosed in one of the following categories:

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 required 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).

As required by SFAS No. 157, assets and liabilities measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. 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 under SFAS No. 157. 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.

As required by SFAS No. 157, the Company has classified its derivative contracts into one of three levels based upon the data relied upon to determine the fair value. The fair values of the Company’s natural gas and crude oil swaps and interest rate swap are based upon quotes obtained from counterparties to the derivative contracts. The Company reviews other readily available market prices for its derivative contracts as there is an active market for these contracts; however, the Company does not have access to the specific valuation models used by the counterparties. Included in these models are discount factors that the Company must estimate in its calculation. Additionally, the Company applies a credit default risk rating factor for its counterparties in determining the fair value of its derivative contracts. Based on the inputs for the fair value measurement, the Company classified its derivative contract assets and liabilities as Level 3.

10

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

The following table summarizes the fair value of the Company’s financial assets and liabilities by SFAS No. 157 pricing levels as of March 31, 2009:

	Fair Value Measurements Using:
	Quoted Prices in		Significant
	Active Markets for		Other		Significant
	Identical Assets		Observable		Unobservable			Assets/
	or Liabilities		Inputs		Inputs			Liabilities at
Description	(Level 1)		(Level 2)		(Level 3)			Fair Value
	(In thousands)
Derivative assets	$	—	$	—	$	354,906		$	354,906
Derivative liabilities		—		—		(8,993	)		(8,993	)
	$	—	$	—	$	345,913		$	345,913

The table below sets forth a reconciliation of the Company’s financial assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three months ended March 31, 2009 (in thousands):

	Derivatives
Balance at December 31, 2008	$	237,903
Total gains or losses (realized/unrealized)		205,360
Purchases, issuances and settlements		(97,350	)
Transfers in and/or out of Level 3		—
Balance at March 31, 2009	$	345,913
Change in unrealized gains (losses) on derivative contracts still held as of March 31, 2009	$	108,010

11

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

4.   Property, Plant and Equipment

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

	March 31,			December 31,
	2009			2008
Natural gas and crude oil properties:
Proved	$	4,933,712		$	4,676,072
Unproved		221,161			215,698
Total natural gas and crude oil properties		5,154,873			4,891,770
Less accumulated depreciation, depletion and impairment(1)		(3,732,599	)		(2,369,840	)
Net natural gas and crude oil properties capitalized costs		1,422,274			2,521,930
Land		13,938			11,250
Non natural gas and crude oil equipment		800,108			764,792
Buildings and structures		69,215			71,859
Total		883,261			847,901
Less accumulated depreciation, depletion and amortization		(206,710	)		(194,272	)
Net capitalized costs		676,551			653,629
Total property, plant and equipment, net	$	2,098,825		$	3,175,559

(1) Includes the cumulative full cost ceiling limitation impairment charges of $3,159.4 million and $1,855.0 million at March 31, 2009 and December 31, 2008, respectively.

In January 2009, the asset lives of certain of the drilling, oil field services and midstream assets were changed to align with industry average lives for similar assets.

The amount of capitalized interest included in the above non natural gas and crude oil equipment balance at both March 31, 2009 and December 31, 2008 was approximately $3.8 million.

5.   Impairment

Full Cost Ceiling Limitation.  Under the full cost method of accounting, the net book value of natural gas and crude oil properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the discounted estimated after-tax future net revenue from proved natural gas and crude oil properties, excluding future cash outflows associated with settling asset retirement obligations included in the net book value of natural gas and crude oil properties, plus the cost of properties not subject to amortization. In calculating future net revenues, prices and costs used are those as of the end of the appropriate period. These prices are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. The Company has entered into various commodity derivative contracts; however, these derivative contracts are not accounted for as cash flow hedges. Accordingly, the effect of these derivative contracts has not been considered in calculating the full cost ceiling limitation as of March 31, 2009.

The net book value, less related deferred tax liabilities, is compared to the ceiling limitation on a quarterly and annual basis. Any excess of the net book value, less related deferred taxes, is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher natural gas and crude oil prices may have increased the ceiling limitation in the subsequent period.

During the first quarter of 2009, the Company reduced the carrying value of its oil and gas properties by $1,304.4 million due to the full cost ceiling limitation.

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Notes to Condensed Consolidated Financial Statements — (Continued)

6.   Costs in Excess of Billings (Billings in Excess of Costs Incurred)

In June 2008, the Company entered into an agreement with a subsidiary of Occidental Petroleum Corporation (“Occidental”) to construct a CO₂ treating plant (the “Century Plant”) and associated compression and pipeline facilities for $800.0 million. Occidental will pay a minimum of 100% of the contract price, plus any subsequentagreed-upon revisions, to the Company through periodic cost reimbursements based upon the percentage of the project completed. Uponstart-up, the Century Plant, located in Pecos County, Texas, will be owned and operated by Occidental for the purpose of separating and removing CO₂ from natural gas delivered by the Company. Pursuant to a30-year treating agreement executed simultaneously with the construction agreement, Occidental will remove CO₂ from the Company’s delivered natural gas. The Company will retain all methane gas from the Century Plant and its other existing plants.

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. Provisions for a contract loss are recognized when it is determined that a loss will be incurred. Costs in excess of billings (billings in excess of costs incurred) were $16.2 million and ($14.1) million and were reported as a current asset and current liability in the condensed consolidated balance sheets at March 31, 2009 and December 31, 2008, respectively. During April 2009, the Company issued and received payment for a progress billing in the amount of $42.2 million.

7.   Asset Retirement Obligation

A reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligation for the period from December 31, 2008 to March 31, 2009 is as follows (in thousands):

Asset retirement obligation, December 31, 2008	$	84,772
Liability incurred upon acquiring and drilling wells		995
Revisions in estimated cash flows		(162	)
Liability settled in current period		—
Accretion of discount expense		1,754
Asset retirement obligation, March 31, 2009		87,359
Less: Current portion		126
Asset retirement obligation, net of current	$	87,233

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SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

8.   Long-Term Debt

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

	March 31,		December 31,
	2009		2008
Senior credit facility	$	610,857	$	573,457
Other notes payable:
Drilling rig fleet and related crude oil field services equipment		29,229		33,030
Mortgage		18,611		18,829
Senior Floating Rate Notes due 2014		350,000		350,000
8.625% Senior Notes due 2015		650,000		650,000
8.0% Senior Notes due 2018		750,000		750,000
Total debt		2,408,697		2,375,316
Less: Current maturities of long-term debt		16,408		16,532
Long-term debt	$	2,392,289	$	2,358,784

Senior Credit Facility.  The amount the Company can borrow under its senior secured revolving credit facility (the “senior credit facility”) is limited to a borrowing base, which was $1.1 billion at March 31, 2009. The senior credit facility matures on November 21, 2011 and is available to be drawn on and repaid without restriction so long as the Company is in compliance with its terms, including certain financial covenants.

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 senior notes.

The senior credit facility also contains financial covenants, including maintenance of agreed upon levels for the (i) ratio of total funded debt to EBITDAX (as defined in the senior credit facility), which may not exceed 4.5:1.0 calculated using the last four completed fiscal quarters, (ii) ratio of EBITDAX to interest expense plus current maturities of long-term debt, which must be at least 2.5:1.0 calculated using the last four completed fiscal quarters, and (iii) current ratio, which must be at least 1.0:1.0. 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 March 31, 2009, 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 natural gas and crude oil reserves representing at least 80% of the discounted present value (as defined in the senior credit facility) of proved natural gas and crude oil 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 the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 2.00% and 3.00% per annum, or the ‘base rate,’ which is the higher of the federal funds rate plus 0.5% or the prime rate plus, in either case, an applicable margin between 1.00% and 2.00% per annum, or the Eurodollar rate (as defined in the senior credit facility) plus 1.00% per annum. Interest is payable quarterly for prime rate loans and at the applicable maturity date for LIBOR

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SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

loans, except that if the interest period for a LIBOR loan is six months, interest is paid at the end of each three-month period. The average annual interest rate paid on amounts outstanding under the senior credit facility was 1.96% for the three months ended March 31, 2009. The interest rate on the senior credit facility was 2.14% at March 31, 2009.

The Company’s borrowing base is redetermined in April and October of each year. The borrowing base remained unchanged at $1.1 billion as a result of the April 2009 redetermination. The Company’s ability to develop properties and changes in commodity prices impact the borrowing base. The Company incurred additional costs related to the senior credit facility as a result of changes to the borrowing base. These costs have been deferred and are included in other assets in the accompanying condensed consolidated balance sheets. At March 31, 2009, the Company had $610.9 million outstanding and $459.6 million available to be drawn under the senior credit facility after consideration of the Company’s $24.5 million in outstanding letters of credit.

On October 3, 2008, Lehman Brothers Commodity Services, Inc. (“Lehman Brothers”), a lender under the Company’s senior credit facility, filed for bankruptcy. At the time that its parent, Lehman Brothers Holdings Inc., declared bankruptcy on September 15, 2008, Lehman Brothers elected not to fund its pro rata share, or 0.29%, of borrowings requested by the Company under the senior credit facility. Accordingly, the Company does not anticipate that Lehman Brothers will fund its pro rata share of any future borrowing requests. The Company does not expect this reduced availability of amounts under the senior credit facility to impact its liquidity or business operations.

Other Indebtedness.  The Company has financed a portion of its drilling rig fleet and related oil field services equipment through the issuance of notes secured by the equipment. At March 31, 2009, the aggregate outstanding balance of these notes was $29.2 million, with annual fixed interest rates ranging from 7.64% 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 $1.2 million. The notes have a prepayment penalty (currently ranging from 1% to 2%) that is triggered if the Company repays the notes prior to maturity.

The Company’s mortgage on downtown property purchased by the Company in July 2007 to serve as its corporate headquarters is fully secured by one of the buildings and a parking garage located on the property. 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 2009, 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.  In May 2008, the Company exchanged its senior term loans for senior unsecured notes with registration rights, as required under the senior term loan credit agreement, pursuant to an exchange offer exempted from registration under the Securities Act of 1933, as amended (“Securities Act”). The Company issued $350.0 million of Senior Floating Rate Notes due 2014 (“Senior Floating Rate Notes”) in exchange for the total outstanding principal amount of its senior floating rate term loan and $650.0 million of 8.625% Senior Notes due 2015 (“8.625% Senior Notes”) in exchange for the total outstanding principal amount of its 8.625% senior term loan. Terms of these senior notes are substantially identical to those of the exchanged senior term loans, except that the senior notes were issued with registration rights. These senior notes are jointly and severally, unconditionally guaranteed on an unsecured basis by all of the Company’s wholly owned subsidiaries, except certain minor subsidiaries. See Note 19.

In conjunction with the issuance of the senior notes, the Company agreed to file a registration statement with the SEC in connection with its offer to exchange the notes for substantially identical notes that are registered under the Securities Act. The Company filed a registration statement relating to the exchange offer during the third quarter of 2008, and all unregistered notes were exchanged for substantially identical notes registered under the Securities Act.

The Senior Floating Rate Notes bear interest at LIBOR plus 3.625% (5.06% at March 31, 2009), except for the period from April 1, 2008 to June 30, 2008, for which the interest rate was 6.323%. Interest is payable quarterly with

15

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

principal due on April 1, 2014. The average interest rate paid on amounts outstanding under the Senior Floating Rate Notes for the three months ended March 31, 2009 was 5.06% without consideration of the interest rate swap. 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 and, through the interest payment due on April 1, 2011, interest may be paid, at the Company’s option, either entirely in cash or entirely with additional fixed rate senior notes. If the Company elects to pay the interest due during any period in additional fixed rate senior notes, the interest rate will increase to 9.375% during that period. All interest payments made to date related to the 8.625% Senior Notes have been paid in cash.

In January 2008, the Company entered into a $350.0 million notional interest rate swap agreement to fix the variable LIBOR interest rate on the floating rate senior term loan for the period from April 1, 2008 to April 1, 2011. As a result of the exchange of the floating rate senior term loan to Senior Floating Rate Notes, the interest rate swap is now being used to fix the variable LIBOR interest rate on the Senior Floating Rate Notes at an annual rate of 6.26% through April 2011. This swap has not been designated as a hedge.

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

The Company incurred $26.1 million of debt issuance costs in connection with the senior term loans. As the senior term loans were exchanged for unsecured senior notes with substantially identical terms, the remaining unamortized debt issuance costs on the senior term loans will be amortized over the terms of the Senior Floating Rate Notes and the 8.625% Senior Notes. These costs are included in other assets in the consolidated balance sheets.

8.0% Senior Notes Due 2018.  In May 2008, the Company issued $750.0 million of unsecured 8.0% Senior Notes due 2018 (“8.0% Senior Notes”). The notes 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. The 8.0% Senior Notes are jointly and severally, unconditionally guaranteed on an unsecured basis by all of the Company’s wholly owned subsidiaries, except certain minor subsidiaries. See Note 19. The notes became freely tradable on November 17, 2008, 180 days after their issuance, pursuant to Rule 144 under the Securities Act.

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 consolidated balance sheet and amortized over the term of the notes.

The indentures governing all of the senior notes contain financial covenants similar to those of the senior credit facility and include limitations on the incurrence of indebtedness, payment of dividends, asset sales, certain asset purchases, transactions with related parties and consolidation or merger agreements. As of March 31, 2009, the Company was in compliance with all of the covenants contained in the indentures governing the senior notes.

For the three months ended March 31, 2009 and 2008, interest payments, net of amounts capitalized, were approximately $10.0 million and $25.4 million, respectively.

9.   Other Long-Term Obligations

The Company has recorded a long-term obligation for amounts to be paid under a settlement agreement with Conoco, Inc. entered into in January 2007. The Company agreed to pay approximately $25.0 million plus interest, payable in $5.0 million increments on April 1, 2007, July 1, 2008, July 1, 2009, July 1, 2010 and July 1, 2011. The payment to be made on July 1, 2009 has been included in accounts payable-trade in the consolidated balance sheets at March 31, 2009 and December 31, 2008. The non-current unpaid settlement amount of $10.0 million has been included in other long-term obligations in the consolidated balance sheets at March 31, 2009 and December 31, 2008.

16

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

10.   Derivatives

The Company is exposed to commodity price risk which impacts the predictability of its cash flows related to the sale of natural gas and crude oil. The primary risk managed by the Company’s use of commodity derivative contracts is commodity price risk. These derivative contracts allow the Company to limit its exposure to a portion of its projected natural gas and crude oil sales. None of the Company’s derivative contracts contain credit risk related contingent features. At March 31, 2009 and December 31, 2008, the Company’s commodity derivative contracts consisted of fixed price swaps and basis swaps, which are included in the derivative descriptions 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	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.

In January 2008, the Company entered into a $350.0 million notional interest rate swap agreement to fix the variable LIBOR interest rate on its floating rate senior term loan at 6.26% per annum for the period April 1, 2008 to April 1, 2011 to manage the interest rate risk on a portion of its floating rate debt. Due to the exchange of the floating rate senior term loan for Senior Floating Rate Notes, the interest rate swap is now being used to fix the variable LIBOR interest rate on the Senior Floating Rate Notes at 6.26% per annum through April 2011. This swap has not been designated as a hedge.

The Company’s derivative contracts have not been designated as hedges. The Company records all derivative contracts at fair value. Changes in derivative contract fair values are recognized in earnings. Cash settlements and valuation gains and losses are included in (gain) loss on derivative contracts in the consolidated statements of operations. All swaps are settled on a monthly basis.

The balance sheet classification of the assets and liabilities related to derivative contracts is summarized below at March 31, 2009 and December 31, 2008 (in thousands):

	Balance Sheet	Fair Value
Type of Contract	Classification	March 31, 2009		December 31, 2008
Derivative assets
Natural gas swaps	Derivative assets-current	$	260,801	$	188,045
Crude oil price swaps	Derivative assets-current		9,369		13,066
Natural gas swaps	Derivative assets-noncurrent		84,736		45,537
Total derivative assets		$	354,906	$	246,648
Derivative liabilities
Interest rate swap	Derivative liabilities-current	$	5,184	$	5,106
Interest rate swap	Derivative liabilities-noncurrent		3,809		3,639
Total derivative liabilities		$	8,993	$	8,745

17

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

The following table summarizes the effect of the Company’s derivative contracts on the condensed consolidated statements of operations for the three-month periods ended March 31, 2009 and 2008 (in thousands):

		Amount of (Gain) Loss
	Location of (Gain) Loss	Recognized in Income
Type of Contract	Recognized in Income	2009			2008
Interest rate swap	Interest expense	$	1,287		$	(807	)
Natural gas and crude oil swaps	(Gain) loss on derivative contracts		(206,647	)		136,844
Total		$	(205,360	)	$	136,037

A counterparty to one of the Company’s derivative contracts, Lehman Brothers, declared bankruptcy on October 3, 2008. Due to Lehman Brothers’ bankruptcy and the declaration of bankruptcy by its parent, Lehman Brothers Holdings Inc., on September 15, 2008, the Company has not assigned any value to this derivative contract as of March 31, 2009.

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SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

At March 31, 2009, the Company’s open natural gas and crude oil commodity derivative contracts consisted of the following:

Natural Gas

	Notional		Weighted Avg.
Period and Type of Contract	(MMcf)(1)		Fixed Price
April 2009 — June 2009
Price swap contracts		20,930	$	7.96
Basis swap contracts		15,470	$	(0.74	)
July 2009 — September 2009
Price swap contracts		18,710	$	8.09
Basis swap contracts		15,640	$	(0.74	)
October 2009 — December 2009
Price swap contracts		19,010	$	8.46
Basis swap contracts		15,640	$	(0.74	)
January 2010 — March 2010
Price swap contracts		20,475	$	7.95
Basis swap contracts		20,250	$	(0.74	)
April 2010 — June 2010
Price swap contracts		19,793	$	7.46
Basis swap contracts		20,475	$	(0.74	)
July 2010 — September 2010
Price swap contracts		20,010	$	7.55
Basis swap contracts		20,700	$	(0.74	)
October 2010 — December 2010
Price swap contracts		20,010	$	7.97
Basis swap contracts		20,700	$	(0.74	)
January 2011 — March 2011
Basis swap contracts		11,250	$	(0.60	)
April 2011 — June 2011
Basis swap contracts		11,375	$	(0.60	)
July 2011 — September 2011
Basis swap contracts		11,500	$	(0.60	)
October 2011 — December 2011
Basis swap contracts		11,500	$	(0.60	)

(1) Assumes ratio of 1:1 for Mcf to MMBtu and excludes a total notional of 5,500 MMcf from 2009 contracts for the Lehman Brothers’ basis swap contract.

19

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

Crude Oil

	Notional		Weighted Avg.
Period and Type of Contract	(in MBbls)		Fixed Price
April 2009 — June 2009
Price swap contracts		46	$	126.71
July 2009 — September 2009
Price swap contracts		46	$	126.61
October 2009 — December 2009
Price swap contracts		46	$	126.51

The following table summarizes the cash settlements and valuation gains and losses on the commodity derivative contracts for the three months ended March 31 (in thousands):

	2009			2008
Realized gain	$	(98,389	)	$	(7,329	)
Unrealized (gain) loss		(108,258	)		144,173
(Gain) loss on derivative contracts	$	(206,647	)	$	136,844

An unrealized loss of $0.3 million and realized losses of $1.0 million related to the interest rate swap were included in interest expense in the condensed consolidated statement of operations for the three months ended March 31, 2009. An unrealized gain of $0.8 million was included in the condensed consolidated statement of operations for the three months ended March 31, 2008.

Refer to Note 3 for additional discussion on the fair value measurement of the Company’s derivative contracts.

11.   Income Taxes

In accordance with GAAP, 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 provisions (benefits) for income taxes consisted of the following components for the three-month periods ended March 31 (in thousands):

	2009			2008
Current:
Federal	$	(2,170	)	$	—
State		997			79
		(1,173	)		79
Deferred:
Federal		4			(30,487	)
State		—			(130	)
		4			(30,617	)
Total (benefit) provision	$	(1,169	)	$	(30,538	)

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax reporting. Deferred tax assets are reduced by a valuation allowance if a determination is made that it is more likely than not that some or all

20

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

of the deferred assets will not be realized based on the weight of all available evidence. For the year ended December 31, 2008, the Company determined it was appropriate to record a full valuation allowance against its net deferred tax asset. For the period ended March 31, 2009, the Company recorded a $408.3 million increase to the previously established valuation allowance. The increase is primarily a result of not recording a tax benefit for the current period loss before income taxes of $1,156.0 million.

Internal Revenue Code (“IRC”) Section 382 addresses company ownership changes and specifically limits the utilization of certain tax attributes on an annual basis following an ownership change. The Company has experienced several owner shifts, within the meaning of IRC Section 382, since the time of its last ownership change, which occurred in June 2008. Further owner shifts occurring during the three-year period beginning as of June 2008 may result in another ownership change. In the event another ownership change occurs, the application of IRC Section 382 may limit the amount of tax attributes, including the 2009 projected net operating loss, that the Company can utilize on an annual basis. The Company will continue to closely monitor its ownership activity.

No reserves for uncertain income tax positions have been recorded pursuant to FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109” (“FIN 48”). Tax years 1994 to present remain open for the majority of taxing authorities due to net operation loss utilization. The Company’s accounting policy is to recognize interest and penalties, if any, related to unrecognized tax benefits as income tax expense. The Company does not have an accrued liability for interest and penalties at March 31, 2009.

For the three months ended March 31, 2009 and March 31, 2008, net income tax (refunds) payments were approximately ($0.5) million and $0.2 million, respectively.

12.   Earnings (Loss) Per Share

Basic earnings per share are computed using the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average shares outstanding during the period, but also include the dilutive effect of awards of restricted stock. The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings per share for the three-month periods ended March 31 (in thousands):

	2009		2008
Weighted average basic common shares outstanding		163,321		141,044
Effect of dilutive securities:
Restricted stock		—		—
Weighted average diluted common and potential common shares outstanding		163,321		141,044

For the three-month periods ended March 31, 2009 and 2008, restricted stock awards covering 4.2 million shares and 2.2 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 for the three-month period ended March 31, 2009 and with respect to its outstanding redeemable convertible preferred stock for the three-month period ended March 31, 2008. 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. The Company determined the if-converted method is not more dilutive for the three-month periods ended March 31, 2009 and 2008.

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SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

13.   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 which, individually or in the aggregate, could have a material effect on the financial condition, operations or cash flows of the Company.

14.   Redeemable Convertible Preferred Stock

In November 2006, the Company sold 2,136,667 shares of redeemable convertible preferred stock to finance a portion of its acquisition of NEG Oil & Gas, LLC. Each holder of redeemable convertible preferred stock was entitled to quarterly cash dividends at the annual rate of 7.75% of the accreted value, or $210 per share, of their redeemable convertible preferred stock. Each share of redeemable convertible preferred stock was initially convertible into ten shares, and ultimately convertible into 10.2 shares, of common stock at the option of the holder, subject to certain anti-dilution adjustments. A summary of dividends declared and paid on the redeemable convertible preferred stock is as follows (in thousands, except per share data):

		Dividends
Declared	Dividend Period	per Share		Total		Payment Date
January 31, 2007	November 21, 2006 — February 1, 2007	$	3.21	$	6,859	February 15, 2007
May 8, 2007	February 2, 2007 — May 1, 2007		3.97		8,550	May 15, 2007
June 8, 2007	May 2, 2007 — August 1, 2007		4.10		8,956	August 15, 2007
September 24, 2007	August 2, 2007 — November 1, 2007		4.10		8,956	November 15, 2007
December 16, 2007	November 2, 2007 — February 1, 2008		4.10		8,956	February 15, 2008
March 7, 2008	February 2, 2008 — May 1, 2008		4.01		8,095	(1)
May 7, 2008	May 2, 2008 — May 7, 2008		4.01		501	May 7, 2008

(1) Includes $0.6 million of prorated dividends paid to holders of redeemable convertible preferred shares at the time their shares converted to common stock in March 2008. The remaining dividends of $7.5 million were paid during May 2008.

On March 30, 2007, certain holders of the Company’s common units (consisting of shares of common stock and a warrant to purchase redeemable convertible preferred stock upon the surrender of common stock) exercised warrants to purchase redeemable convertible preferred stock. The holders converted 526,316 shares of common stock into 47,619 shares of redeemable convertible preferred stock.

During March 2008, holders of 339,823 shares of the Company’s redeemable convertible preferred stock elected to convert those shares into 3,465,593 shares of the Company’s common stock. This conversion resulted in an increase to additional paid-in capital of $71.3 million, which represents the difference between the par value of the common stock issued and the carrying value of the redeemable convertible shares converted. The Company also recorded a charge to retained earnings for $1.1 million in accelerated accretion expense related to the converted redeemable convertible preferred shares.

Approximately $8.1 million in paid and unpaid dividends on the redeemable convertible preferred stock has been included in the Company’s earnings per share calculations for the three-month period ended March 31, 2008 as presented in the condensed consolidated statements of operations.

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SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

15.   Equity

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

	March 31,		December 31,
	2009		2008
Shares authorized		50,000		50,000
Shares outstanding at end of period		2,650		—

In January 2009, the Company completed a private placement of 2,650,000 shares of 8.5% convertible perpetual preferred stock to qualified institutional buyers eligible under Rule 144A of the Securities Act. The offering included 400,000 shares of convertible perpetual preferred stock issued upon the full exercise of the initial purchaser’s option to cover over-allotments. Net proceeds from the offering were approximately $243.3 million after deducting offering expenses of approximately $8.6 million. The Company used the net proceeds from the offering to repay outstanding borrowings under the senior credit facility and for general corporate purposes.

Each share of 8.5% convertible perpetual preferred stock has a liquidation preference of $100 per share and is convertible at the holder’s option at any time initially into approximately 12.4805 shares of the Company’s common stock, 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 to be paid semi-annually in cash, common stock or a combination thereof at the Company’s election with the first dividend payment due in February 2010. The convertible perpetual preferred stock is not redeemable by the Company at any time. After February 20, 2014, the Company may cause all outstanding shares of the convertible perpetual preferred stock to automatically convert into common stock at the then-prevailing conversion rate if certain conditions are met.

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

	March 31,		December 31,
	2009		2008
Shares authorized		400,000		400,000
Shares outstanding at end of period		167,572		166,046
Shares held in treasury		1,396		1,326

During March 2008, the Company issued 3,465,593 shares of common stock upon the conversion of 339,823 shares of its redeemable convertible preferred stock. See additional discussion in Note 14.

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 70,000 shares at a total value of $0.5 million and approximately 38,000 shares at a total value of $1.3 million during the three-month periods ended March 31, 2009 and 2008, respectively. These shares were accounted for as treasury stock.

In February 2008, the Company transferred 184,484 shares of its treasury stock into an account established for the benefit of the Company’s 401(k) Plan. The transfer was made in order to satisfy the Company’s $5.0 million accrued payable to match employee contributions made to the plan during 2007. The historical cost of the shares transferred totaled approximately $2.4 million and resulted in an increase to the Company’s additional paid-in capital of approximately $2.6 million.

Restricted Stock.  The Company issues restricted common stock awards 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

23

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

restricted common stock are subject to restriction on transfer. Unvested restricted stock awards are included in the Company’s outstanding shares of common stock.

For the three-month periods ended March 31, 2009 and 2008, the Company recognized stock-based compensation expense, net of $1.2 million and $0 capitalized, respectively, related to restricted common stock of $5.2 million and $3.2 million, respectively. Stock-based compensation expense is reflected in general and administrative expenses in the condensed consolidated statements of operations.

Noncontrolling Interest.  On January 1, 2009, the Company implemented SFAS No. 160, which established accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. As required by SFAS No. 160, the noncontrolling interest in one of the Company’s subsidiaries represents an ownership interest in the consolidated entity and is included as a component of equity in the condensed consolidated balance sheets and condensed consolidated statement of changes in equity.

16.   Related Party Transactions

The Company has transactions with certain stockholders and other related parties in the ordinary course of business. These transactions primarily consist of purchases of drilling equipment and sales of oil field service supplies. Following is a summary of significant transactions with related parties for the three-month periods ended March 31, 2009 and 2008 (in thousands):

	2009		2008
Sales to and reimbursements from related parties	$	3,813	$	25,356
Purchases from related parties	$	8,942	$	19,890

The Company leases office space in Oklahoma City from a member of its Board of Directors. The Company believes that the payments made under this lease are at fair market rates. Rent expense related to the lease totaled $0.3 million and $0.4 million for the three-month periods ended March 31, 2009 and 2008, respectively. The lease expires in August 2009.

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. Larclay currently owns twelve rigs, one of which has not yet been assembled. Larclay financed the acquisition cost of its twelve rigs with a loan from a third party, secured by the purchased rigs, and a loan from CWEI. In addition, CWEI has guaranteed a portion of the third party debt. Until April 15, 2009, Lariat operated the rigs owned by the partnership.

Under the partnership agreement, if Larclay had an operating shortfall, Lariat and CWEI were obligated to provide loans to the partnership. In April 2008, Lariat and CWEI each made loans of $2.5 million to Larclay under promissory notes. The notes yielded interest at a floating rate based on a LIBOR average plus 3.25% as provided in the Larclay partnership agreement. In June 2008, Larclay executed a $15.0 million revolving promissory note with each of Lariat and CWEI. Amounts drawn under each revolving promissory note bear interest at a floating rate based on a LIBOR average plus 3.25% as provided in the Larclay partnership agreement. Lariat advanced $5.0 million to Larclay under the revolving promissory note during the year ended December 31, 2008. Total advances outstanding to Larclay were $7.5 million ($2.5 million promissory note and $5.0 million drawn on revolving promissory note) at December 31, 2008. Due to economic conditions and cash shortfalls within Larclay, the Company impaired both the notes receivable and its investment in Larclay as of December 31, 2008. No additional advances were made by the Company to Larclay during the three-month period ended March 31, 2009.

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 “Agreement”) entered into between Lariat

24

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

and CWEI on March 13, 2009. As a result of the transactions contemplated by the Agreement, CWEI owns 100% of Larclay. Pursuant to the Agreement, 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 from and after April 15, 2009, including Lariat’s obligations as operator of the Larclay drilling rigs. Under the terms of the Agreement, Lariat assigned to CWEI all of its right, title and interest in the subordinated loans previously advanced by Lariat to Larclay. Pursuant to the Agreement, Lariat and CWEI agreed to indemnify each other for certain losses, and to waive certain claims, whether known or unknown, Lariat and CWEI may have against each other arising from their interests in Larclay. As a result of the Company’s impairment of both the notes receivable from and investment in Larclay at December 31, 2008, there were no additional losses on Larclay during the three-months ended March��31, 2009 or as a result of the Agreement with CWEI.

The following table summarizes the Company’s other transactions with Larclay (in thousands):

	Three Months Ended
	March 31,
	2009		2008
Sales to and reimbursements from Larclay	$	2,748	$	10,938
Purchases from Larclay	$	1,762	$	10,670

	March 31,		December 31,
	2009		2008
Accounts receivable from Larclay	$	221	$	6,060
Accounts payable to Larclay	$	—	$	152

17.   Subsequent Events

In April 2009, the Company completed a registered underwritten offering of 14,480,000 shares of its common stock, including 2,280,000 shares of common stock acquired by the underwriters from the Company to cover over-allotments. Net proceeds to the Company from the offering were approximately $108.0 million after deducting offering expenses of approximately $2.0 million and were used to repay a portion of the amount outstanding under the senior credit facility and for general corporate purposes.

In April 2009, the Company’s borrowing base under its senior credit facility was redetermined and remained unchanged at $1.1 billion.

In May 2009, the Company signed an agreement to sell the rights to its East Texas leasehold below the Cotton Valley formation for $60.0 million. The transaction is subject to customary adjustments and closing conditions and is expected to close during the second quarter of 2009.

18.   Industry 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 natural gas and crude oil properties. The drilling and oil field services segment is engaged in the land contract drilling of natural gas and crude oil wells. The midstream gas services segment is engaged in the purchasing, gathering, processing, treating and selling of natural gas. The all other column includes items not related to the Company’s reportable segments including the Company’s CO₂ gathering and sales operations and corporate operations.

25

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

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

	Exploration and			Drilling and Oil			Midstream Gas						Consolidated
	Production			Field Services			Services			All Other			Total
Three Months Ended March 31, 2009
Revenues	$	121,933		$	93,814		$	94,367		$	5,896		$	316,010
Inter-segment revenue		(66	)		(87,503	)		(68,953	)		(475	)		(156,997	)
Total revenues	$	121,867		$	6,311		$	25,414		$	5,421		$	159,013
Operating (loss) income(1)	$	(1,095,862	)	$	(2,755	)	$	210		$	(17,873	)	$	(1,116,280	)
Interest expense, net		(39,818	)		(633	)		—			(286	)		(40,737	)
Other income, net		760			—			234			—			994
(Loss) income before income taxes	$	(1,134,920	)	$	(3,388	)	$	444		$	(18,159	)	$	(1,156,023	)
Capital expenditures(2)	$	261,884		$	2,377		$	23,948		$	8,951		$	297,160
Depreciation, depletion and amortization	$	60,760		$	7,286		$	1,842		$	2,931		$	72,819
At March 31, 2009
Total assets	$	1,975,508		$	263,938		$	318,774		$	112,365		$	2,670,585
Three Months Ended March 31, 2008
Revenues	$	206,966		$	79,838		$	148,235		$	5,854		$	440,893
Inter-segment revenue		(44	)		(67,516	)		(103,148	)		(1,099	)		(171,807	)
Total revenues	$	206,922		$	12,322		$	45,087		$	4,755		$	269,086
Operating (loss) income	$	(47,389	)	$	(2,148	)	$	32		$	(13,306	)	$	(62,811	)
Interest expense, net		(23,412	)		(642	)		—			(305	)		(24,359	)
Other (expense) income, net		(68	)		217			642			51			842
Loss before income taxes	$	(70,869	)	$	(2,573	)	$	674		$	(13,560	)	$	(86,328	)
Capital expenditures(2)	$	354,765		$	17,921		$	38,721		$	7,243		$	418,650
Depreciation, depletion and amortization	$	65,590		$	12,348		$	2,774		$	2,329		$	83,041
At December 31, 2008
Total assets	$	2,986,070		$	275,164		$	284,281		$	109,543		$	3,655,058

(1)	The operating loss for the exploration and production segment for the three-month period ended March 31, 2009 includes a $1,304.4 million non-cash full cost ceiling impairment on the Company’s natural gas and crude oil properties.
(2)	Capital expenditures are presented on an accrual basis.

26

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

19.   Condensed Consolidating Financial Information

The Company is providing condensed consolidating financial information for its subsidiaries that are guarantors of its public debt. Subsidiary guarantors are wholly owned and have, jointly and severally, unconditionally guaranteed on an unsecured basis the Company’s 8.625% Senior Notes due 2015, Senior Floating Rate Notes due 2014 and 8.0% Senior Notes due 2018. The subsidiary guarantees (i) rank equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) rank senior to all of the existing and future subordinated debt of the subsidiary guarantors; (iii) are effectively subordinated in right of payment to any existing or future secured obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; and (iv) are structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors who are not themselves guarantors.

The Company has not presented separate financial and narrative information for each of the subsidiary guarantors because it believes that such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the guarantees.

The following condensed consolidating financial information represents the financial information of SandRidge Energy, Inc. and its wholly owned subsidiary guarantors, prepared on the equity basis of accounting. The non-guarantor subsidiaries are minor and, therefore, not presented separately. The information is presented in accordance with the requirements ofRule 3-10 under the SEC’sRegulation S-X. 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.

27

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

Condensed Consolidating Balance Sheet

	March 31, 2009
	Parent			Guarantor
	Company			Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	46		$	30	$	—		$	76
Accounts and notes receivable, net		1,026,032			54,846		(1,002,273	)		78,605
Derivative contracts		270,170			—		—			270,170
Other current assets		2,966			56,005		—			58,971
Total current assets		1,299,214			110,881		(1,002,273	)		407,822
Property, plant and equipment, net		650,146			1,448,679		—			2,098,825
Investment in subsidiaries		283,930			—		(283,930	)		—
Other assets		172,749			42,573		(51,384	)		163,938
Total assets	$	2,406,039		$	1,602,133	$	(1,337,587	)	$	2,670,585
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	126,891		$	1,143,214	$	(1,002,273	)	$	267,832
Other current liabilities		5,184			16,534		—			21,718
Total current liabilities		132,075			1,159,748		(1,002,273	)		289,550
Long-term debt		2,360,857			82,816		(51,384	)		2,392,289
Asset retirement obligation		13,558			73,675		—			87,233
Other liabilities		13,834			1,942		—			15,776
Total liabilities		2,520,324			1,318,181		(1,053,657	)		2,784,848
(Deficit) equity		(114,285	)		283,952		(283,930	)		(114,263	)
Total liabilities and equity	$	2,406,039		$	1,602,133	$	(1,337,587	)	$	2,670,585

28

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

	December 31, 2008
	Parent		Guarantor
	Company		Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	18	$	618	$	—		$	636
Accounts and notes receivable, net		863,129		66,463		(820,519	)		109,073
Derivative contracts		201,111		—		—			201,111
Other current assets		3,194		41,899		—			45,093
Total current assets		1,067,452		108,980		(820,519	)		355,913
Property, plant and equipment, net		1,106,623		2,068,936		—			3,175,559
Investment in subsidiaries		1,002,336		—		(1,002,336	)		—
Other assets		135,161		39,809		(51,384	)		123,586
Total assets	$	3,311,572	$	2,217,725	$	(1,874,239	)	$	3,655,058
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	163,068	$	1,024,018	$	(820,519	)	$	366,567
Other current liabilities		5,106		30,951		—			36,057
Total current liabilities		168,174		1,054,969		(820,519	)		402,624
Long-term debt		2,323,458		86,710		(51,384	)		2,358,784
Asset retirement obligation		12,759		71,738		—			84,497
Other liabilities		13,660		1,942		—			15,602
Total liabilities		2,518,051		1,215,359		(871,903	)		2,861,507
Equity		793,521		1,002,366		(1,002,336	)		793,551
Total liabilities and equity	$	3,311,572	$	2,217,725	$	(1,874,239	)	$	3,655,058

29

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

Condensed Consolidating Statements of Operations

	Parent			Guarantor
	Company			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Three Months Ended March 31, 2009
Revenues	$	48,683		$	112,388		$	(2,058	)	$	159,013
Expenses:
Direct operating expenses		22,176			56,100			(2,058	)		76,218
General and administrative		10,363			18,122			—			28,485
Depreciation, depletion, amortization and impairment		622,789			754,448			—			1,377,237
Gain on derivative contracts		(206,647	)		—			—			(206,647	)
Total expenses		448,681			828,670			(2,058	)		1,275,293
Loss from operations		(399,998	)		(716,282	)		—			(1,116,280	)
Equity earnings from subsidiaries		(716,361	)		—			716,361			—
Interest expense, net		(39,769	)		(968	)		—			(40,737	)
Other income, net		102			892			—			994
Loss before income tax benefit		(1,156,026	)		(716,358	)		716,361			(1,156,023	)
Income tax benefit		(1,169	)		—			—			(1,169	)
Net loss		(1,154,857	)		(716,358	)		716,361			(1,154,854	)
Less: net income attributable to noncontrolling interests		—			3			—			3
Net loss attributable to SandRidge Energy, Inc.	$	(1,154,857	)	$	(716,361	)	$	716,361		$	(1,154,857	)
Three Months Ended March 31, 2008
Revenues	$	64,316		$	205,880		$	(1,110	)	$	269,086
Expenses:
Direct operating expenses		15,513			76,615			(1,110	)		91,018
General and administrative		7,170			13,824			—			20,994
Depreciation, depletion, and amortization		22,929			60,112			—			83,041
Loss on derivative contracts		136,844			—			—			136,844
Total expenses		182,456			150,551			(1,110	)		331,897
(Loss) income from operations		(118,140	)		55,329			—			(62,811	)
Equity earnings from subsidiaries		54,641			—			(54,641	)		—
Interest expense, net		(23,608	)		(751	)		—			(24,359	)
Other income (expense), net		(56	)		898			—			842
(Loss) income before income tax benefit		(87,163	)		55,476			(54,641	)		(86,328	)
Income tax benefit		(30,538	)		—			—			(30,538	)
Net (loss) income		(56,625	)		55,476			(54,641	)		(55,790	)
Less: net income attributable to noncontrolling interests		—			835			—			835
Net (loss) income attributable to SandRidge Energy, Inc.	$	(56,625	)	$	54,641		$	(54,641	)	$	(56,625	)

30

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

Condensed Consolidating Statements of Cash Flows

	Parent			Guarantor
	Company			Subsidiaries			Eliminations		Consolidated
	(In thousands)
Three Months Ended March 31, 2009
Net cash (used in) provided by operating activities	$	(101,533	)	$	174,764		$	—	$	73,231
Net cash used in investing activities		(178,614	)		(171,323	)		—		(349,937	)
Net cash provided by (used in) financing activities		280,175			(4,029	)		—		276,146
Net increase (decrease) in cash and cash equivalents		28			(588	)		—		(560	)
Cash and cash equivalents at beginning of year		18			618			—		636
Cash and cash equivalents at end of period	$	46		$	30		$	—	$	76
Three Months Ended March 31, 2008
Net cash (used in) provided by operating activities	$	(59,892	)	$	216,581		$	—	$	156,689
Net cash used in investing activities		(206,626	)		(212,353	)		—		(418,979	)
Net cash provided by (used in) financing activities		204,230			(4,349	)		—		199,881
Net decrease in cash and cash equivalents		(62,288	)		(121	)		—		(62,409	)
Cash and cash equivalents at beginning of year		62,967			168			—		63,135
Cash and cash equivalents at end of period	$	679		$	47		$	—	$	726

31

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 report, as well as our audited consolidated financial statements and the accompanying notes included in our Annual Report onForm 10-K for the year ended December 31, 2008 (the “2008Form 10-K”).

The financial information with respect to the three-month periods ended March 31, 2009 and March 31, 2008 that is discussed below is unaudited. In the opinion of management, this information contains all adjustments, consisting 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 currently generate the majority of our revenues, earnings and cash flow from the production and sale of natural gas and crude oil. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and crude oil and on our ability to find and economically develop and produce natural gas and crude oil reserves. Prices for natural gas and crude oil fluctuate widely. In order to reduce our exposure to these fluctuations, we enter into derivative commodity contracts for a portion of our anticipated future natural gas and crude oil 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 net income largely is determined by the amount of work each performs for third parties. Revenues and costs related to work performed by our businesses for our own account are eliminated in consolidation and, therefore, do not contribute to our consolidated net income.

Recent Events

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 “Agreement”) entered into between Lariat and CWEI on March 13, 2009. As a result of the transactions contemplated by the Agreement, CWEI owns 100% of Larclay. Pursuant to the Agreement, 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 from and after April 15, 2009, including Lariat’s obligations as operator of the Larclay drilling rigs. Under the terms of the Agreement, Lariat assigned to CWEI all of its right, title and interest in the subordinated loans previously advanced by Lariat to Larclay. Pursuant to the Agreement, Lariat and CWEI agreed to indemnify each other for certain losses, and to waive certain claims, whether known or unknown, Lariat and CWEI may have against each other arising from their interests in Larclay. As a result of the impairment of both the notes receivable from and investment in Larclay at December 31, 2008, there were no additional losses on Larclay during thethree-months ended March 31, 2009 or as a result of the Agreement with CWEI.

Common Stock Offering.  On April 29, 2009, we completed a registered underwritten offering of 14,480,000 shares of our common stock, including 2,280,000 shares of common stock acquired by the underwriters from us to cover over-allotments. Net proceeds from the offering were approximately $108.0 million after deducting offering expenses of approximately $2.0 million and were used to repay a portion of the amount outstanding under our senior credit facility and for general corporate purposes.

East Texas Leasehold.  In May 2009, we signed an agreement to sell the rights to our East Texas leasehold below the Cotton Valley formation for $60.0 million. The transaction is subject to customary adjustments and closing conditions and is expected to close during the second quarter of 2009.

32

Segment Overview

We operate in three related business segments: exploration and production, drilling and oil field services and midstream gas services. The all other column includes items not related to our reportable segments including our CO₂ gathering and sales operations and corporate operations. Management evaluates the performance of our business segments based on operating income, which is defined as segment operating revenue less operating expenses and depreciation, depletion and amortization. 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.

	Exploration and			Drilling and Oil			Midstream Gas						Consolidated
	Production			Field Services			Services			All Other			Total
Three Months Ended March 31, 2009
Revenues	$	121,933		$	93,814		$	94,367		$	5,896		$	316,010
Inter-segment revenue		(66	)		(87,503	)		(68,953	)		(475	)		(156,997	)
Total revenues	$	121,867		$	6,311		$	25,414		$	5,421		$	159,013
Operating (loss) income(1)	$	(1,095,862	)	$	(2,755	)	$	210		$	(17,873	)	$	(1,116,280	)
Interest expense, net		(39,818	)		(633	)		—			(286	)		(40,737	)
Other income (expense), net		760			—			234			—			994
(Loss) income before income taxes	$	(1,134,920	)	$	(3,388	)	$	444		$	(18,159	)	$	(1,156,023	)
Three Months Ended March 31, 2008
Revenues	$	206,966		$	79,838		$	148,235		$	5,854		$	440,893
Inter-segment revenue		(44	)		(67,516	)		(103,148	)		(1,099	)		(171,807	)
Total revenues	$	206,922		$	12,322		$	45,087		$	4,755		$	269,086
Operating (loss) income	$	(47,389	)	$	(2,148	)	$	32		$	(13,306	)	$	(62,811	)
Interest expense, net		(23,412	)		(642	)		—			(305	)		(24,359	)
Other (expense) income, net		(68	)		217			642			51			842
Loss before income taxes	$	(70,869	)	$	(2,573	)	$	674		$	(13,560	)	$	(86,328	)

(1) The operating loss for the exploration and production segment for the three-month period ended March 31, 2009 includes a $1,304.4 million non-cash full cost ceiling impairment on our natural gas and crude oil properties.

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Exploration and Production Segment

The primary factors affecting the financial results of our exploration and production segment are the prices we receive for our natural gas and crude oil production, the quantity of our natural gas and crude oil production and changes in the fair value of commodity derivative contracts we use to reduce the volatility of the prices we receive for our natural gas and crude oil production. A three-month comparison of production and prices is presented in the following table:

	Three Months Ended
	March 31,
	2009		2008
Production data:
Natural gas (Mmcf)		24,432		19,173
Crude oil (MBbls)		718		611
Combined equivalent volumes (Mmcfe)		28,739		22,839
Average daily combined equivalent volumes (Mmcfe/d)		319.3		251.0
Average prices — as reported(1):
Natural gas (per Mcf)	$	3.83	$	7.86
Crude oil (per Bbl)(2)	$	38.44	$	89.81
Combined equivalent (per Mcfe)	$	4.22	$	9.00
Average prices — including impact of derivative contract settlements:
Natural gas (per Mcf)	$	7.71	$	8.32
Crude oil (per Bbl)(2)	$	43.65	$	87.42
Combined equivalent (per Mcfe)	$	7.64	$	9.32

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

Exploration and production segment revenues decreased to $121.9 million in the three months ended March 31, 2009 from $206.9 million in the three months ended March 31, 2008, a decrease of 41.1%, as a result of a 53.1% decrease in the combined average price we received for our natural gas and crude oil production, which was partially offset by the 25.8% increase in combined production volumes. In the three-month period ended March 31, 2009, we increased natural gas production by 5.3 Bcf to 24.4 Bcf and increased crude oil production by 107 MBbls to 718 MBbls from the comparable period in 2008. The total combined 5.9 Bcfe increase in production was primarily due to an increase in the number of producing wells we owned interests in as a result of our successful drilling program in the West Texas Overthrust (“WTO”) region of Pecos and Terrell counties in Texas.

The average price we received for our natural gas production for the three-month period ended March 31, 2009 decreased 51.3%, or $4.03 per Mcf, to $3.83 per Mcf from $7.86 per Mcf in the comparable period in 2008. The average price received for our crude oil production decreased 57.2%, or $51.37 per barrel, to $38.44 per barrel during the three months ended March 31, 2009 from $89.81 per barrel during the same period in 2008. Including the impact of derivative contract settlements, the effective price received for natural gas for the three-month period ended March 31, 2009 was $7.71 per Mcf as compared to $8.32 per Mcf during the same period in 2008. Including the impact of derivative contract settlements, the effective price received for crude oil for the three-month period ended March 31, 2009 was $43.65 per Bbl as compared to $87.42 per Bbl during the same period in 2008. During 2008 and continuing into 2009, we entered into derivatives contracts to mitigate the impact of commodity price fluctuations on our 2008, 2009, 2010 and 2011 production. 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 expense. Internally, management views the settlement of such derivative contracts as adjustments to the price received for natural gas and crude oil production to determine “effective prices.”

The SEC requires public companies utilizing the full cost method of accounting for oil and gas properties to perform a ceiling limitation calculation at the end of each quarterly reporting period. Under SEC guidelines, natural gas and crude oil reserves are calculated based on posted prices on the last day of the reporting period with consideration of price changes only to the extent provided by contractual arrangements. As of March 31, 2009, these

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prices were $3.63 per MMBtu for Henry Hub natural gas and $49.66 per barrel for NYMEX crude oil. These prices used to determine the future value of our reserves declined in an amount sufficient to necessitate a ceiling impairment of $1,304.4 million at March 31, 2009.

For the three months ended March 31, 2009, we had a $1,095.9 million operating loss in our exploration and production segment compared to a loss of $47.4 million for the same period in 2008. The $206.6 million net gain on our commodity derivative contracts, of which $108.3 million was unrealized, and a $7.7 million decrease in production taxes were offset by a full cost ceiling impairment of $1,304.4 million, an $85.1 million decrease in exploration and production revenues and an $11.4 million increase in production expenses. The full cost ceiling impairment was the result of the decline of the future value of our reserves due to depressed natural gas and crude oil prices at March 31, 2009. The increase in production expenses is attributable to the increase in the number of operating wells we own and an increase in our average working interest in those wells.

During the three-month period ended March 31, 2009, the exploration and production segment reported a $206.6 million net gain on our commodity derivative positions ($98.3 million realized gain and $108.3 million unrealized gain) compared to a $136.8 million net loss on our commodity derivative positions ($7.3 million realized gain and $144.1 million unrealized loss) in the comparable period in 2008. During 2008 and the first three months of 2009, we entered into natural gas and crude oil swaps and natural gas basis swaps. Given the long-term nature of our investment in the WTO development program, we believe it prudent to enter into natural gas and crude oil swaps and natural gas basis swaps for a portion of our production in order to stabilize future cash inflows for planning purposes. Unrealized gains or losses on derivative contracts represent the change in fair value of open derivative contracts during the period. The unrealized gain on natural gas and crude oil derivative contracts recorded during the three months ended March 31, 2009 was attributable to a decrease in average natural gas and crude oil prices at March 31, 2009 compared to the average natural gas and crude oil prices at December 31, 2008 or the contract price for contracts entered into during 2009.

Drilling and Oil Field Services Segment

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

As of March 31, 2009, we owned 31 drilling rigs through our drilling and oil field services subsidiary, Lariat Services, Inc. (“Lariat”). The table below presents information concerning rigs owned by Lariat:

	March 31,
	2009		2008
Rigs working for SandRidge		7		24
Rigs working for third parties		—		2
Idle rigs(1)		23		2
Total operational		30		28
Non-operational rigs		1		4
Total rigs owned		31		32

(1) Includes two rigs receiving stand-by rates from third parties at March 31, 2009.

In addition to the rigs we own directly, during the three-month periods ended March 31, 2009 and 2008 we also indirectly owned 11 operational rigs through our investment in Larclay, L.P. (“Larclay”), a limited partnership in which we held a 50% interest. 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

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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. Due to economic conditions and cash shortfalls within Larclay, we fully impaired our investment in and notes receivable from Larclay at December 31, 2008.

As discussed in “Recent Events,” on April 15, 2009, Lariat completed an assignment to CWEI of Lariat’s 50% equity interest in Larclay.

Drilling and oil field services segment revenue decreased to $6.3 million in the three-month period ended March 31, 2009 from $12.3 million in the three-month period ended March 31, 2008. This resulted in an operating loss of $2.8 million in the three-month period ended March 31, 2009 compared to $2.1 million in the same period in 2008. The decline in revenues and operating income was primarily attributable to a decrease in the number of our rigs operating and services performed for third parties. All seven of our rigs working at March 31, 2009, were working for our account, as compared to 24 of our 26 working rigs working for our account at March 31, 2008. As a result, during the three-month period ended March 31, 2009, approximately 93.3%, or $87.5 million, of our drilling and oil field service revenues were generated by work performed on our own account and eliminated in consolidation as compared to approximately 84.6%, or $67.5 million, for the comparable period in 2008. The average daily rate received per rig working for third parties declined to an average of $11,618 per rig per working day during the three-month period ended March 31, 2009 from an average of $16,012 per rig per working day during the comparable period in 2008. During the three-month period ended March 31, 2008, one of our rigs working for a third-party was operated under a turnkey contract, while none of our rigs were operated under turnkey contracts during the three-month period ended March 31, 2009. Additionally, we received reduced, or stand-by, rates on two of our rigs during the three-month period ended March 31, 2009.

Midstream Gas Services Segment

Gas marketing revenue is one of our largest revenue components; however, gas marketing is a very low-margin business. On a consolidated basis, gas purchases and other costs of sales include the total value we receive from third parties for the natural gas we sell and the amount we pay for natural gas, which are reported as midstream and marketing expense. The primary factors affecting our midstream gas services are the quantity of natural gas we gather, treat and market and the prices we pay and receive for natural gas.

Midstream gas services revenue for the three months ended March 31, 2009 was $25.4 million compared to $45.1 million in the comparable period of 2008. The quarterly decrease in midstream gas services revenues was attributable to a decrease in natural gas prices in the three-month period ended March 31, 2009 compared to the same period in 2008. We generally charge a flat fee per unit transported and charge a percentage of sales for marketed volumes.

Results of Operations

Three months ended March 31, 2009 compared to the three months ended March 31, 2008

Revenue.  Total revenue decreased 40.9% to $159.0 million for the three months ended March 31, 2009 from $269.1 million in the same period in 2008. This decrease was primarily due to a $84.2 million decrease in natural gas and crude oil sales along with decreases in midstream and marketing revenues.

	Three Months Ended
	March 31,
	2009		2008		$ Change			% Change
	(In thousands)
Revenues:
Natural gas and crude oil	$	121,241	$	205,487	$	(84,246	)		(41.0	)%
Drilling and services		6,395		12,334		(5,939	)		(48.2	)%
Midstream and marketing		25,956		46,409		(20,453	)		(44.1	)%
Other		5,421		4,856		565			11.6	%
Total revenues	$	159,013	$	269,086	$	(110,073	)		(40.9	)%

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Total natural gas and crude oil revenues decreased $84.2 million to $121.2 million for the three months ended March 31, 2009 compared to $205.5 million for the same period in 2008, primarily as a result of a decrease in prices received for our production of natural gas and crude oil slightly offset by an increase in the natural gas and crude oil produced. The average price received, excluding the impact of derivative contracts, for our natural gas and crude oil production decreased 53.1% in the 2009 period to $4.22 per Mcfe compared to $9.00 per Mcfe in 2008. Total natural gas production increased 27.4% to 24.4 Bcf in 2009 compared to 19.2 Bcf in 2008, while crude oil production increased 17.5% to 718 MBbls in 2009 from 611 MBbls in 2008.

Drilling and services revenues decreased 48.2% to $6.4 million for the three months ended March 31, 2009 compared to $12.3 million in the same period in 2008. The decline in revenues was due to a decrease in rigs operating for and services provided to third parties. The average daily rate received per rig working for third parties declined to an average of $11,618 per rig per working day during the three-month period ended March 31, 2009 from an average of $16,012 per rig per working day during the comparable period in 2008. During the three-month period ended March 31, 2008, one of our rigs working for a third-party was operated under a turnkey contract, while none of our rigs were operated under turnkey contracts during the three-month period ended March 31, 2009. Additionally, we received reduced, or stand-by, rates on two of our rigs during the three-month period ended March 31, 2009.

Midstream and marketing revenues decreased $20.5 million, or 44.1%, with revenues of $26.0 million in the three-month period ended March 31, 2009 as compared to $46.4 million in the three-month period ended March 31, 2008. The quarterly decrease in midstream gas services revenues was attributable to a decrease in natural gas prices in the three-month period ended March 31, 2009 compared to the same period in 2008.

Other revenue increased to $5.4 million for the three months ended March 31, 2009 from $4.9 million for the same period in 2008. Other revenue was generated primarily by our CO₂ gathering and sales operations.

Operating Costs and Expenses.  Total operating costs and expenses increased to $1,275.3 million for the three months ended March 31, 2009 compared to $331.9 million for the same period in 2008 primarily due to our full cost ceiling impairment along with increases in production and general and administrative expenses. These increases were partially offset by decreases in production taxes, depreciation, depletion and amortization (“DD&A”) and gains on derivative contracts.

	Three Months Ended
	March 31,
	2009			2008		$ Change			% Change
	(In thousands)
Operating costs and expenses:
Production	$	45,579		$	34,188	$	11,391			33.3	%
Production taxes		1,491			9,220		(7,729	)		(83.8	)%
Drilling and services		5,606			7,169		(1,563	)		(21.8	)%
Midstream and marketing		23,362			40,418		(17,056	)		(42.2	)%
Depreciation, depletion, and amortization — natural gas and crude oil		60,093			65,076		(4,983	)		(7.7	)%
Depreciation, depletion and amortization — other		12,726			17,965		(5,239	)		(29.2	)%
Impairment		1,304,418			—		1,304,418			100.0	%
General and administrative		28,485			20,994		7,491			35.7	%
(Gain) loss on derivative contracts		(206,647	)		136,844		(343,491	)		(251.0	)%
Loss on sale of assets		180			23		157			682.6	%
Total operating costs and expenses	$	1,275,293		$	331,897	$	943,396			284.2	%

Production expenses includes the costs associated with our exploration and production activities, including, but not limited to, lease operating expenses and treating costs. Production expenses increased $11.4 million primarily due to an increase in combined production volumes. In the three-month period ended March 31, 2009, we

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increased natural gas production by 5.3 Bcf to 24.4 Bcf and increased crude oil production by 107 MBbls to 718 MBbls from the comparable period in 2008. Production taxes decreased $7.7 million, or 83.8%, to $1.5 million primarily due to the severance tax refunds received in 2009 and the decreased prices received for production during the three months ended March 31, 2009.

Drilling and services expenses decreased 21.8% for the three months ended March 31, 2009 as compared to the same period in 2008 primarily due to the decrease in services provided to third parties.

Midstream and marketing expenses decreased $17.1 million, or 42.2%, to $23.4 million due to lower natural gas prices during the three months ended March 31, 2009 than during the comparable period in 2008.

DD&A for our natural gas and crude oil properties decreased to $60.1 million for the three months ended March 31, 2009 from $65.1 million in the same period in 2008. Our DD&A per Mcfe decreased $0.76 to $2.09 in the first quarter of 2009 from $2.85 in the comparable period in 2008 as a result of our $1,855.0 million full cost ceiling impairment at December 31, 2008. The effect of the decrease in DD&A per Mcfe was partially offset by increased DD&A due to an increase in production. Our production increased 25.8% to 28.7 Bcfe in 2009 from 22.8 Bcfe in 2008.

DD&A for our other assets consists primarily of depreciation of our drilling rigs, midstream gathering and compression facilities and other equipment. The decrease in DD&A for our other assets was attributable primarily to the change in asset lives on certain of our drilling, oil field services and midstream assets. We calculate depreciation of property and equipment using the straight-line method over the estimated useful lives of the assets, which range from 3 to 39 years.

At March 31, 2009, we recorded a non-cash impairment charge of $1,304.4 million as total capitalized costs of our natural gas and crude oil properties exceeded our full cost ceiling limitation. There was no full cost ceiling impairment as of March 31, 2008.

General and administrative expenses increased $7.5 million to $28.5 million for the three months ended March 31, 2009 from $21.0 million for the comparable period in 2008. The increase was principally attributable to an increase in corporate salaries and wages, including non-cash stock compensation expense. The increase in corporate salaries was primarily due to the increase in corporate and support staff. General and administrative expenses include non-cash stock compensation expense, net of amounts capitalized, of $5.2 million for the three months ended March 31, 2009 as compared to $3.2 million for the comparable period in 2008. The increases in salaries and wages and stock compensation were partially offset by $7.6 million in capitalized general and administrative expenses, which includes $1.2 million of capitalized stock compensation expense, for the three months ended March 31, 2009 compared to $3.2 million for the three months ended March 31, 2008.

Due to the decline in average natural gas and crude oil prices during the first three months of 2009, we recorded a gain of $206.6 million ($108.3 million unrealized gain and $98.3 million realized gain) on our commodity derivatives contracts for 2009 compared to a $136.8 million loss ($144.1 million unrealized loss and $7.3 million realized gain) in the same period of 2008. The unrealized gain recorded in the first quarter of 2009 was attributable to a decrease in average natural gas prices at March 31, 2009 compared to average natural gas prices at December 31, 2008 or the various contract dates for contracts entered into during the first three months of 2009.

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Other Income (Expense).  Total other expense increased to $39.7 million in the three-month period ended March 31, 2009 from $23.5 million in the three-month period ended March 31, 2008. The increase is reflected in the table below.

	Three Months Ended
	March 31,
	2009			2008			$ Change			% Change
	(In thousands)
Other income (expense):
Interest income	$	11		$	813		$	(802	)		(98.6	)%
Interest expense		(40,748	)		(25,172	)		(15,576	)		61.9	%
Income from equity investments		234			859			(625	)		(72.8	)%
Other income (expense), net		760			(17	)		777			(4,570.6	)%
Total other (expense) income		(39,743	)		(23,517	)		(16,226	)		69.0	%
Loss before income tax benefit		(1,156,023	)		(86,328	)		(1,069,695	)		1,239.1	%
Income tax benefit		(1,169	)		(30,538	)		29,369			(96.2	)%
Net loss	$	(1,154,854	)	$	(55,790	)	$	(1,099,064	)		1,970.0	%

Interest income decreased to $0.01 million for the three months ended March 31, 2009 from $0.8 million for the same period in 2008. This decrease was generally due to lower excess cash levels during the three months ended March 31, 2009 as compared to the same period in 2008.

Interest expense increased to $40.7 million for the three months ended March 31, 2009 from $25.2 million for the same period in 2008. This increase was attributable to the higher average debt balances outstanding during the three months ended March 31, 2009 as well as the $0.3 million unrealized loss and $1.0 million realized loss on our interest rate swap. Also contributing slightly to the increase was a $0.8 million unrealized gain related to our interest rate swap for the three months ended March 31, 2008.

We reported an income tax benefit of $1.2 million for the three months ended March 31, 2009, as compared to a benefit of $30.5 million for the same period in 2008. The current period income tax benefit represents an effective income tax rate of 0.1% compared to an effective income tax rate of 35% in the same period in 2008. The loss before income taxes for the period ended March 31, 2009 of $1,156.0 million included a full cost ceiling impairment of $1,304.4 million. The lower effective income tax rate associated with the current period loss before income taxes was primarily a result of not recording a tax benefit for the loss due to our full valuation allowance on our net deferred tax asset.

Liquidity and Capital Resources

Summary

Our operating cash flow is influenced mainly by the prices that we receive for our natural gas and crude oil production; the quantity of natural gas we produce and, to a lesser extent, the quantity of crude oil we produce; the success of our development and exploration activities; the demand for our drilling rigs and oil field services and the rates we receive for these services; and the margins we obtain from our natural gas and CO₂ gathering and treating contracts.

Debt and equity capital markets experienced adverse conditions during the latter part of 2008 and during the first three months of 2009. Continued 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 27 lenders under our senior credit facility. To date, the only disruption in our ability to access the full amounts available under our senior credit facility was the bankruptcy of Lehman Brothers Commodity Services, Inc. (“Lehman Brothers”), a lender responsible for 0.29% of the obligations under our senior credit facility. We cannot predict with any certainty

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the impact to us of any further disruptions in the credit markets. For additional information, please read “— Credit Facilities and Other Indebtedness — Senior Credit Facility.”

Our senior credit facility limits the amounts we can borrow to a borrowing base amount, currently $1.1 billion. The borrowing base is subject to review semi-annually; however, the lenders reserve the right to have one additional re-determination of the borrowing base per calendar year. We may request up to two unscheduled re-determinations per year. The borrowing base is determined based upon proved developed producing reserves, proved developed non-producing reserves, and proved undeveloped reserves. Our borrowing base is redetermined in April and October of each year based on proved reserves. Our ability to develop properties and changes in commodity prices may affect the borrowing base of our senior credit facility. Based on the April 2009 redetermination, our borrowing base remained unchanged at $1.1 billion.

As of March 31, 2009, our cash and cash equivalents were $0.08 million, and we had approximately $459.6 million available to be drawn under our senior credit facility based on a borrowing base of $1.1 billion. Amounts outstanding under our senior credit facility at March 31, 2009 totaled $610.9 million. As of March 31, 2009, we had approximately $2.4 billion in total debt outstanding. As of May 1, 2009, the balance outstanding under our senior credit facility was $564.4 million, and $506.1 million was available to be drawn under our senior credit facility after consideration of our $24.5 million in outstanding letters of credit.

In January 2009, we completed a private placement of 2,650,000 shares of 8.5% convertible perpetual preferred stock. The offering included 400,000 shares of convertible perpetual preferred stock issued upon the full exercise of the initial purchasers’ option to cover over-allotments. Net proceeds from the offering were approximately $243.3 million and were used to repay outstanding borrowings under our senior credit facility and for general corporate purposes.

On April 29, 2009, we completed an offering of 14,480,000 shares of our common stock. The offering included 2,280,000 shares issued upon the full exercise of the underwriters’ option to cover over-allotments. Net proceeds from the offering were $108.0 million and were used to repay a portion of the amounts outstanding on our senior credit facility and for general corporate purposes.

Capital Expenditures

We dedicate and expect to continue to dedicate a substantial portion of our capital expenditure program toward the exploration, development, production and acquisition of natural gas and crude oil reserves.

During the first quarter of 2009 and 2008, our capital expenditures, on an accrual basis, by segment were:

	Three Months Ended
	March 31,
	2009		2008
	(In thousands)
Capital Expenditures:
Exploration and production	$	261,884	$	354,765
Drilling and oil field services		2,377		17,921
Midstream gas services		23,948		38,721
Other		8,951		7,243
Total	$	297,160	$	418,650

For 2009, we have budgeted a range of $500.0 million to $700.0 million for capital expenditures, excluding acquisitions. The majority of our capital expenditures will be discretionary and could be curtailed if our cash flows decline from expected levels or we are unable to obtain capital on attractive terms. We may increase or decrease planned capital expenditures depending on natural gas prices, asset sales and the availability of capital through the issuance of additional long-term debt or equity.

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Cash Flows

Our cash flows for the three months ended March 31, 2009 and 2008 were as follows:

	Three Months Ended
	March 31,
	2009			2008
	(In thousands)
Cash flows provided by operating activities	$	73,231		$	156,689
Cash flows used in investing activities		(349,937	)		(418,979	)
Cash flows provided by financing activities		276,146			199,881
Net decrease in cash and cash equivalents	$	(560	)	$	(62,409	)

Operating Activities.  Net cash provided by operating activities for the three months ended March 31, 2009 and 2008 were $73.2 million and $156.7 million, respectively. The decrease in cash provided by operating activities in 2009 compared to 2008 was primarily due to a 53.1% decrease in the combined average prices we received for our natural gas and crude oil production. Increases in general and administrative costs, such as salaries and wages, also contributed to the decrease in operating cash flows.

Investing Activities.  Cash flows used in investing activities decreased to $349.9 million in the three-month period ended March 31, 2009 from $419.0 million in the comparable 2008 period due to reduced drilling activity during the first quarter of 2009. For the three-month period ended March 31, 2009, our capital expenditures were $261.9 million in our exploration and production segment, $2.4 million for our drilling and oil field services segment, $23.9 million for our midstream gas services segment and $9.0 million for other capital expenditures. During the same period in 2008, our capital expenditures were $354.8 million in our exploration and production segment, $17.9 million for our drilling and oil field services segment, $38.7 million for our midstream gas services segment and $7.2 million for other capital expenditures.

Financing Activities.  Proceeds from borrowings increased to $559.1 million for the three months ended March 31, 2009, and we repaid approximately $525.7 million leaving net borrowings during the period of approximately $33.4 million. We also received $243.3 million in net proceeds from the issuance of our 8.5% convertible perpetual preferred stock in January 2009. Our financing activities provided $276.1 million in cash for the three-month period ended March 31, 2009 compared to $199.9 million in the comparable period in 2008.

Credit Facilities and Other Indebtedness

Senior Credit Facility.  Our senior credit facility matures on November 21, 2011 and is available to be drawn on and repaid without restriction so long as we are in compliance with its terms, including certain financial covenants.

The senior credit facility bank group consists of 27 financial institutions. The largest commitment from any lender in the syndicate is 6.6% of the facility. The credit agreement for the facility contains various covenants that limit our ability, and the ability of certain of our 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 our assets. Additionally, the senior credit facility limits our ability and the ability of certain of our subsidiaries to incur additional indebtedness with certain exceptions, including under the senior notes (as discussed below).

On October 3, 2008, Lehman Brothers, a lender under our senior credit facility, filed for bankruptcy. At the time that its parent, Lehman Brothers Holdings Inc., declared bankruptcy on September 15, 2008, Lehman Brothers elected not to fund its pro rata share, or 0.29%, of borrowings requested by us under the senior credit facility. Accordingly, we do not anticipate that Lehman Brothers will fund its pro rata share of any future borrowing requests. We currently do not expect this reduced availability of amounts under the senior credit facility to impact our liquidity or business operations.

The senior credit facility also contains financial covenants, including maintenance of agreed upon levels for the (i) ratio of total funded debt to EBITDAX (as defined in the senior credit facility), which may not exceed 4.5:1.0

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calculated using the last four completed fiscal quarters, (ii) ratio of EBITDAX to interest expense plus current maturities of long-term debt, which must be at least 2.5:1.0 calculated using the last four completed fiscal quarters, and (iii) current ratio, which must be at least 1.0:1.0. In the current ratio calculation, as defined in the senior credit facility, any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on our derivative contracts are disregarded. As of March 31, 2009, we were in compliance with all of the financial covenants under the senior credit facility.

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

At our election, interest under the senior credit facility is determined by reference to LIBOR plus an applicable margin between 2.00% and 3.00% per annum or the ‘base rate,’ which is the higher of the federal funds rate plus 0.5% or the prime rate plus, in either case, an applicable margin between 1.00% and 2.00% per annum, or the Eurodollar rate plus 1.00% per annum. Interest is payable quarterly for prime rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest is paid at the end of each three-month period. The average annual interest rate paid on amounts outstanding under our senior credit facility was 1.96% for the three months ended March 31, 2009.

The borrowing base of the senior credit facility is subject to review semi-annually; however, the lenders reserve the right to have one additional redetermination of the borrowing base per calendar year. We also may request up to two unscheduled redeterminations per year. The borrowing base is determined based on proved developed producing reserves, proved developed non-producing reserves and proved undeveloped reserves. The borrowing base, as of March 31, 2009, was $1.1 billion. As of March 31, 2009, we had total outstanding indebtedness of $610.9 million under our senior credit facility.

Other Indebtedness.  We have financed a portion of our drilling rig fleet and related oil field services equipment through the issuance of notes secured by the equipment. At March 31, 2009, the aggregate outstanding balance of these notes was $29.2 million, with annual fixed interest rates ranging from 7.64% 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 $1.2 million. The notes have a prepayment penalty (currently ranging from 1% to 2%) that is triggered if we repay the notes prior to maturity.

Our mortgage on downtown property purchased in July 2007 to serve as our corporate headquarters is fully secured by one of the buildings and a parking garage located on the property. 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 2009, we expect 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.  In May 2008, we exchanged our senior term loans for senior unsecured notes with registration rights, as required under the senior term loan credit agreement, pursuant to an exchange offer exempted from registration under the Securities Act. We issued $350.0 million of Senior Floating Rate Notes due 2014 in exchange for the total outstanding principal amount of our senior floating rate term loan and $650.0 million of 8.625% Senior Notes due 2015 in exchange for the total outstanding principal amount of our 8.625% senior term loan. The newly issued senior notes had terms that were substantially identical to those of the exchanged senior term loans. During the third quarter of 2008, all unregistered notes were exchanged for substantially identical notes registered under the Securities Act.

In January 2008, we entered into a $350.0 million notional amount interest rate swap agreement with a financial institution that effectively fixed our interest rate on the floating rate senior term loan at an annual rate of 6.26%. As a result of the exchange of the floating rate senior term loan to Senior Floating Rate Notes, the interest rate swap is now being used to fix the variable LIBOR interest rate on the Senior Floating Rate Notes at an annual rate of 6.26% through April 2011.

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

We incurred $26.1 million of debt issuance costs in connection with the senior term loans. As the senior term loans were exchanged for senior unsecured notes with substantially identical terms, the remaining unamortized debt issuance costs of the senior term loans are being amortized over the term of the Senior Floating Rate Notes and the 8.625% Senior Notes.

8.0% Senior Notes Due 2018.  In May 2008, we issued $750.0 million of our unsecured 8.0% Senior Notes due 2018. The notes 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. The notes became freely tradable on November 17, 2008, 180 days after their issuance, pursuant to Rule 144 under the Securities Act.

We incurred $16.0 million of debt issuance costs in connection with the 8.0% Senior Notes. These costs are being amortized over the term of these notes.

Debt covenants under the 8.0% Senior Notes as well as under the Senior Floating Rate Notes and the 8.625% Senior Notes include financial covenants similar to those of the senior credit facility. The covenants include limitations on the incurrence of indebtedness, payment of dividends, asset sales, certain asset purchases, transactions with related parties and consolidation or merger agreements. As of March 31, 2009, we were in compliance with all of the covenants under all of the senior notes.

Redeemable Convertible Preferred Stock

Prior to the conversion of our redeemable convertible preferred stock to common stock during 2008, each holder of our redeemable convertible preferred stock was entitled to quarterly cash dividends at the annual rate of 7.75% of the accreted value, $210 per share, of their redeemable convertible preferred stock. Each share of redeemable convertible preferred stock was convertible into approximately 10.2 shares of common stock at the option of the holder, subject to certain anti-dilution adjustments.

During March 2008, holders of 339,823 shares of our redeemable convertible preferred stock elected to convert those shares into 3,465,593 shares of our common stock. In May 2008, we converted the remaining outstanding 1,844,464 shares of our redeemable convertible preferred stock into 18,810,260 shares of our common stock as permitted under the terms of the redeemable convertible preferred stock. These conversions resulted in total charges to retained earnings of $7.2 million in accelerated accretion expense related to the converted redeemable convertible preferred shares. We paid all dividends on our redeemable convertible preferred stock in cash, including $33.3 million in 2007 and $17.6 million in 2008. On and after the conversion date, dividends ceased to accrue and rights of common unit holders to exercise outstanding warrants to purchase shares of redeemable convertible preferred stock terminated.

8.5% Convertible Perpetual Preferred Stock

In January 2009, we completed a private placement of 2,650,000 shares of 8.5% convertible perpetual preferred stock to qualified institutional buyers eligible under Rule 144A under the Securities Act. The offering included 400,000 shares of convertible perpetual preferred stock issued upon the full exercise of the initial purchasers’ option to cover over-allotments. Net proceeds from the offering were approximately $243.3 million after deducting offering expenses of approximately $8.6 million. We used the net proceeds of the offering to repay outstanding borrowings under our senior credit facility and for general corporate purposes.

Each share of 8.5% convertible perpetual preferred stock has a liquidation preference of $100 per share and is convertible at the holder’s option at any time initially into approximately 12.4805 shares of our common stock, 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 to be paid semi-annually in cash, common stock or a combination thereof at our election with the first dividend payment due in February 2010. The convertible perpetual preferred stock is not redeemable by us at any time. After February 20, 2014, we may cause all outstanding shares of the

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convertible perpetual preferred stock to automatically convert into common stock at the then-prevailing conversion rate if certain conditions are met.

Common Stock

On April 29, 2009, we completed a registered underwritten offering of 14,480,000 shares of our common stock, including 2,280,000 shares of common stock acquired by the underwriters from us to cover over-allotments. Net proceeds from the offering were approximately $108.0 million after deducting offering expenses of approximately $2.0 million and were used to repay a portion of the amount outstanding under our senior credit facility and for general corporate purposes.

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 financial contracts, which are settled in cash and do not require the actual delivery of a commodity quantity to satisfy settlement.

Commodity Price Risk.  Our most significant market risk relates to the prices we receive for our natural gas and crude oil production. Due to the historical volatility of these commodities, we periodically have entered into, and expect in the future to enter into, derivative arrangements for the purpose of reducing the variability of natural gas and crude oil 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 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 current 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 March 31, 2009, we had eighteen approved derivative counterparties, seventeen of which are lenders under our senior credit facility. We currently have derivative contracts outstanding with eleven of these counterparties, excluding Lehman Brothers. We have no derivative contracts in 2009 and beyond with counterparties outside of those that are also part of our senior credit facility. Lehman Brothers is a counterparty on one of our derivative contracts. Due to the bankruptcy of Lehman Brothers and its parent, Lehman Brothers Holdings Inc., we did not assign any value to this derivative contract (notional of 5,500 MMcf) at March 31, 2009.

We use, and may continue to use, a variety of commodity-based derivative contracts, including collars,fixed-price swaps and basis protection swaps. Our fixed price swap transactions are settled based upon NYMEX prices, and our 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 natural gas derivative contracts occurs in the production month.

While we believe that the natural gas and crude oil price derivative arrangements we enter into are important to our program to manage price variability for our production, 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 natural gas and crude oil 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 fair value of our commodities derivative contracts. Changes in fair value are principally measured based on period-end prices compared to the contract price.

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At March 31, 2009, our open natural gas and crude oil commodity derivative contracts consisted of the following:

Natural Gas

	Notional		Weighted Avg.
Period and Type of Contract	(MMcf)(1)		Fixed Price
April 2009 — June 2009
Price swap contracts		20,930	$	7.96
Basis swap contracts		15,470	$	(0.74	)
July 2009 — September 2009
Price swap contracts		18,710	$	8.09
Basis swap contracts		15,640	$	(0.74	)
October 2009 — December 2009
Price swap contracts		19,010	$	8.46
Basis swap contracts		15,640	$	(0.74	)
January 2010 — March 2010
Price swap contracts		20,475	$	7.95
Basis swap contracts		20,250	$	(0.74	)
April 2010 — June 2010
Price swap contracts		19,793	$	7.46
Basis swap contracts		20,475	$	(0.74	)
July 2010 — September 2010
Price swap contracts		20,010	$	7.55
Basis swap contracts		20,700	$	(0.74	)
October 2010 — December 2010
Price swap contracts		20,010	$	7.97
Basis swap contracts		20,700	$	(0.74	)
January 2011 — March 2011
Basis swap contracts		11,250	$	(0.60	)
April 2011 — June 2011
Basis swap contracts		11,375	$	(0.60	)
July 2011 — September 2011
Basis swap contracts		11,500	$	(0.60	)
October 2011 — December 2011
Basis swap contracts		11,500	$	(0.60	)

(1) Assumes ratio of 1:1 for Mcf to MMBtu and excludes a total notional of 5,500 MMcf from 2009 contracts for the Lehman Brothers’ basis swap contract.

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Crude Oil

	Notional		Weighted Avg.
Period and Type of Contract	(in MBbls)		Fixed Price
April 2009 — June 2009
Price swap contracts		46	$	126.71
July 2009 — September 2009
Price swap contracts		46	$	126.61
October 2009 — December 2009
Price swap contracts		46	$	126.51

The following table summarizes the cash settlements and valuation gains and losses on our commodity derivative contracts for the three months ended March 31, 2009 and 2008 (in thousands):

	2009			2008
Realized gain	$	(98,389	)	$	(7,329	)
Unrealized (gain) loss		(108,258	)		144,173
(Gain) loss on derivative contracts	$	(206,647	)	$	136,844

Credit Risk.  Credit risk relates to the risk of loss as a result of non-performance by one or more of our counterparties under any of our credit arrangements. Recently, the ability of certain investment banks and other financial institutions to meet their financial obligations has been of increasing concern. A portion of our liquidity is concentrated in derivative contracts that enable us to mitigate a portion of our exposure to natural gas and crude oil 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.

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 consists of 27 financial institutions with commitments ranging from 0.25% to 6.6%. Lehman Brothers, a lender under our senior credit facility, declared bankruptcy on October 3, 2008. As a result of the bankruptcy of Lehman Brothers and its parent company, Lehman Brothers Holdings Inc., on September 15, 2008, Lehman Brothers elected not to fund its pro rata share, or 0.29%, of borrowings requested by us under the facility. Although we do not currently expect this reduced availability of amounts under the senior credit facility to impact our liquidity or business operations, the inability of one or more of our other lenders to fund their obligations under the facility could have a material adverse effect on our financial condition.

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.

We use sensitivity analysis to determine the impact that market risk exposures may have on our variable interest rate borrowings. Based on the $350.0 million outstanding balance of our Senior Floating Rate Notes at March 31, 2009, a one percent change in the applicable rates, with all other variables held constant, would have resulted in a change in our interest expense of approximately $0.9 million for the three months ended March 31, 2009.

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. In January 2008, we entered into a $350.0 million notional amount interest rate swap agreement with a financial institution that effectively fixed our

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interest rate on the variable rate term loan for the period from April 1, 2008 through April 1, 2011. As a result of the exchange of the variable rate term loan to Senior Floating Rate Notes, the interest rate swap is being used to fix the variable LIBOR interest rate on the Senior Floating Rate Notes at 6.26% through April 2011. This swap has not been designated as a hedge.

An unrealized loss of $0.3 million and an unrealized gain of $0.8 million were recorded in interest expense in the consolidated statements of operations for the change in fair value of the interest rate swap for the three months ended March 31, 2009 and 2008, respectively. Realized losses of $1.0 million were included in interest expense in the condensed consolidated statement of operations for the three months ended March 31, 2009.

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 ActRules 13a-15 and15d-15 as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2009 to provide reasonable assurance that the information required to be disclosed by us in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and such information is accumulated and communicated to management, as appropriate to allow timely decisions regarding required disclosure.

There was no change in our internal control over financial reporting during the quarter ended March 31, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. Other Information

ITEM 1.   Legal Proceedings

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 which, individually or in the aggregate, could have a material adverse effect on its results of operations, financial condition or cash flows.

ITEM 1A.   Risk Factors

There has been no material change to the risk factors previously disclosed in Item 1A — Risk Factors in our 2008Form 10-K.

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

As part of our restricted stock program, we make required tax payments on behalf of employees as their stock awards vest and then withhold a number of vested shares 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 March 31, 2009, the following shares were withheld in satisfaction of tax withholding obligations arising from the vesting of restricted stock:

					Total Number of		Maximum Number
					Shares Purchased		of Shares that May
	Total Number		Average		as Part of Publicly		Yet Be Purchased
	of Shares		Price Paid		Announced Plans		Under the Plans
Period	Purchased		per Share		or Programs		or Programs
January 1, 2009 — January 31, 2009		66,603	$	7.36		N/A		N/A
February 1, 2009 — February 28, 2009		1,338		6.76		N/A		N/A
March 1, 2009 — March 31, 2009		2,152		6.59		N/A		N/A

ITEM 6.   Exhibits

See the Exhibit Index accompanying this report.

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SIGNATURE

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

SandRidge Energy, Inc.

By:   /s/  Dirk M. Van Doren

Dirk M. Van Doren

Executive Vice President and

Chief Financial Officer

Date: May 7, 2009

EXHIBIT INDEX

				Incorporated by Reference
Exhibit					SEC			Filed
No.			Exhibit Description	Form	File No.	Exhibit	Filing Date	Herewith
	3	.1	Certificate of Incorporation of SandRidge Energy, Inc.	S-1	333-148956	3.1	01/30/2008
	3	.2	Certificate of Designation of 8.5% Convertible Perpetual Preferred Stock of SandRidge Energy, Inc.	8-K	001-33784	3.1	01/21/2009
	3	.3	Amended and Restated Bylaws of SandRidge Energy, Inc.	8-K	001-33784	3.1	03/09/2009
	4	.16	Registration Rights Agreement, dated February 16, 2009, among SandRidge Energy, Inc., George B. Kaiser and Pooled CIT Investments, O.K.	10-K	001-33784	4.16	02/26/2009
	10	.5.8†	Employment Agreement of Rodney E. Johnson, dated effective as of January 1, 2009	10-K	001-33784	10.5.8	02/26/2009
	10	.7	Amendment No. 6 to Senior Credit Facility, dated April 17, 2009	8-K	001-33784	10.1	04/21/2009
	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	.LAB	XBRL Taxonomy Extension Label Linkbase Document					*
	101	.PRE	XBRL Taxonomy Extension Presentation Linkbase Document					*
	101	.DEF	XBRL Taxonomy Extension Definition Document					*

† Management contract or compensatory plan or arrangement