SANDRIDGE ENERGY INC - FORM 10-Q

SANDRIDGE ENERGY INC - FORM 10-Q - November 5, 2009

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2009

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

For the transition period from to

Commission File Number: 001-33784

SANDRIDGE ENERGY, INC.

(Exact name of registrant as specified in its charter)


Delaware		20-8084793
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

123 Robert S. Kerr Avenue Oklahoma City, Oklahoma		73102
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code:

(405) 429-5500

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

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

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

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

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

The number of shares outstanding of the registrant’s common stock, par value $0.001 per share, as of the close of business on October 30, 2009, was 183,494,775.

SANDRIDGE ENERGY, INC.

FORM 10-Q

Quarter Ended September 30, 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	36
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	53
ITEM 4.	Controls and Procedures	56
PART II. OTHER INFORMATION
ITEM 1.	Legal Proceedings	57
ITEM 1A.	Risk Factors	57
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	58
ITEM 6.	Exhibits	58

DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (“Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Various statements contained in this Quarterly 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, among other things, 2009 and 2010 capital expenditures, our liquidity and capital resources 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 this Quarterly Report and of our Annual Report on Form 10-K for the fiscal year ended December 31, 2008 (the “2008 Form 10-K”), the opportunities that may be pursued by us, competitive actions by other companies, changes in laws or regulations and other factors, many of which are beyond our control. The results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on our company, business or operations. The forward-looking statements contained herein are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statements.

PART I. Financial Information

ITEM 1.

Financial Statements

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except per share data)


	September 30, 2009			December 31, 2008
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	14,642		$	636
Accounts receivable, net:
Trade		80,328			102,746
Related parties		257			6,327
Derivative contracts		129,453			201,111
Inventories		3,405			3,686
Other current assets		32,358			41,407

Total current assets		260,443			355,913

Natural gas and crude oil properties, using full cost method of accounting
Proved		5,064,490			4,676,072
Unproved		229,687			215,698
Less: accumulated depreciation, depletion and impairment		(3,792,437	)		(2,369,840	)

		1,501,740			2,521,930

Other property, plant and equipment, net		462,487			653,629
Derivative contracts		—			45,537
Investments		9,158			6,088
Restricted deposits		32,872			32,843
Other assets		44,268			39,118

Total assets	$	2,310,968		$	3,655,058

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of long-term debt	$	13,925		$	16,532
Accounts payable and accrued expenses:
Trade		230,506			366,337
Related parties		155			230
Derivative contracts		7,223			5,106
Asset retirement obligation		2,077			275
Billings in excess of costs incurred		5,141			14,144

Total current liabilities		259,027			402,624

Long-term debt		2,126,286			2,358,784
Other long-term obligations		6,967			11,963
Derivative contracts		21,640			3,639
Asset retirement obligation		88,033			84,497

Total liabilities		2,501,953			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 September 30, 2009 and no shares issued and outstanding in 2008; aggregate liquidation preference of $265,000 at September 30, 2009		3			—
Common stock, $0.001 par value, 400,000 shares authorized; 184,986 issued and 183,524 outstanding at September 30, 2009 and 167,372 issued and 166,046 outstanding at December 31, 2008		178			163
Additional paid-in capital		2,537,690			2,170,986
Treasury stock, at cost		(20,427	)		(19,332	)
Accumulated deficit		(2,708,459	)		(1,358,296	)

Total SandRidge Energy, Inc. stockholders’ (deficit) equity		(191,015	)		793,521
Noncontrolling interest		30			30

Total (deficit) equity		(190,985	)		793,551

Total liabilities and equity	$	2,310,968		$	3,655,058

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

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
				(Unaudited)
Revenues:
Natural gas and crude oil	$	104,348		$	259,141		$	328,628		$	756,762
Drilling and services		5,878			12,054			17,449			36,345
Midstream and marketing		16,453			58,343			62,051			174,240
Other		8,176			4,485			19,839			13,812

Total revenues		134,855			334,023			427,967			981,159
Expenses:
Production		41,350			41,070			128,379			115,512
Production taxes		1,069			6,717			3,153			29,456
Drilling and services		9,676			8,191			21,697			20,426
Midstream and marketing		14,889			51,908			56,702			157,059
Depreciation, depletion and amortization — natural gas and crude oil		33,060			71,964			127,503			209,296
Depreciation, depletion and amortization — other		12,092			17,597			38,851			51,342
Impairment		—			—			1,304,418			—
General and administrative		25,006			29,235			77,123			76,432
Loss (gain) on derivative contracts		47,933			(292,526	)		(139,722	)		4,086
Loss (gain) on sale of assets		9			(1,420	)		26,359			(9,131	)

Total expenses		185,084			(67,264	)		1,644,463			654,478

(Loss) income from operations		(50,229	)		401,287			(1,216,496	)		326,681

Other income (expense):
Interest income		89			923			287			3,068
Interest expense		(53,201	)		(41,026	)		(136,368	)		(88,421	)
Income (loss) from equity investments		593			(60	)		1,027			1,355
Other (expense) income, net		(1,144	)		(83	)		100			856

Total other (expense) income		(53,663	)		(40,246	)		(134,954	)		(83,142	)

(Loss) income before income tax (benefit) expense		(103,892	)		361,041			(1,351,450	)		243,539
Income tax (benefit) expense		(2,580	)		130,693			(4,114	)		89,308

Net (loss) income		(101,312	)		230,348			(1,347,336	)		154,231
Less: net income attributable to noncontrolling interest		4			2			11			853

Net (loss) income (applicable) attributable to SandRidge Energy, Inc.		(101,316	)		230,346			(1,347,347	)		153,378
Preferred stock dividends and accretion		2,816			—			2,816			16,232

(Loss) income (applicable) available to SandRidge Energy, Inc. common stockholders	$	(104,132	)	$	230,346		$	(1,350,163	)	$	137,146

(Loss) income per share (applicable) available to SandRidge Energy, Inc. common stockholders:
Basic	$	(0.58	)	$	1.41		$	(7.85	)	$	0.90

Diluted	$	(0.58	)	$	1.40		$	(7.85	)	$	0.89

Weighted average number of SandRidge Energy, Inc. common shares outstanding:
Basic		178,069			163,020			171,902			153,125

Diluted		178,069			164,554			171,902			154,489

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

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(In thousands)


	SandRidge Energy, Inc. Stockholders															Noncontrolling Interest			Total
	8.5% Convertible Perpetual Preferred Stock			Common Stock			Additional Paid-In Capital			Treasury Stock			Accumulated Deficit
	Shares	Amount		Shares	Amount		Additional Paid-In Capital			Treasury Stock			Accumulated Deficit
							(Unaudited)
Nine months ended September 30, 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
Issuance of common stock	—		—	14,480		15		107,588			—			—			—			107,603
Purchase of treasury stock	—		—	—		—		—			(1,095	)		—			—			(1,095	)
Stock-based compensation	—		—	—		—		19,694			—			—			—			19,694
Stock-based compensation excess tax benefit	—		—	—		—		(3,864	)		—			—			—			(3,864	)
Issuance of restricted stock awards, net of cancellations	—		—	2,998		—		—			—			—			—			—
8.5% Convertible perpetual preferred stock dividends	—		—	—		—		—			—			(2,816	)		—			(2,816	)
Net (loss) income	—		—	—		—		—			—			(1,347,347	)		11			(1,347,336	)

Balance, September 30, 2009	2,650	$	3	183,524	$	178	$	2,537,690		$	(20,427	)	$	(2,708,459	)	$	30		$	(190,985	)

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

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Nine Months Ended September 30,
	2009			2008
	(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income	$	(1,347,336	)	$	154,231
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Provision for doubtful accounts		62			1,623
Depreciation, depletion and amortization		166,354			260,638
Impairment		1,304,418			—
Debt costs amortization		6,037			4,026
Deferred income taxes		4			83,225
Unrealized loss (gain) on derivative contracts		137,313			(81,603	)
Loss (gain) on sale of assets		26,359			(9,131	)
Investment income — restricted deposits		(29	)		(304	)
Income from equity investments		(1,027	)		(1,355	)
Stock-based compensation		16,526			14,283
Stock-based compensation excess tax benefit		(3,864	)		—
Changes in operating assets and liabilities		(31,597	)		108,735

Net cash provided by operating activities		273,220			534,368

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant and equipment		(628,153	)		(1,609,355	)
Proceeds from sale of assets		263,630			158,534
Loans to unconsolidated investees		—			(5,500	)
Fundings of restricted deposits		—			(781	)

Net cash used in investing activities		(364,523	)		(1,457,102	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		1,638,365			1,768,722
Repayments of borrowings		(1,874,046	)		(864,100	)
Dividends paid — preferred		—			(17,552	)
Noncontrolling interest distributions		(11	)		(5,497	)
Proceeds from issuance of 8.5% convertible perpetual preferred stock		243,289			—
Proceeds from issuance of common stock		107,603			—
Purchase of treasury stock		(1,095	)		(3,536	)
Debt issuance costs		(8,796	)		(17,540	)

Net cash provided by financing activities		105,309			860,497

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		14,006			(62,237	)
CASH AND CASH EQUIVALENTS, beginning of period		636			63,135

CASH AND CASH EQUIVALENTS, end of period	$	14,642		$	898

Supplemental Disclosure of Noncash Investing and Financing Activities:
Change in accrued capital expenditures	$	(85,952	)	$	—
8.5% Convertible perpetual preferred stock dividends payable	$	2,816		$	—
Accretion on redeemable convertible preferred stock	$	—		$	7,636

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

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

Nature of Business. SandRidge Energy, Inc. (including its subsidiaries, 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 carbon dioxide (“CO₂”) treating and transportation facilities and has marketing and tertiary oil recovery operations. In addition, Lariat Services, Inc. (“Lariat”), a wholly owned subsidiary of the Company, owns and operates drilling rigs and a related oil field services business. The Company’s primary exploration, development and production areas are concentrated in West Texas. 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 2008 Form 10-K. The unaudited interim condensed consolidated financial statements have been prepared by the Company in accordance with the accounting policies stated in the audited consolidated financial statements contained in the 2008 Form 10-K. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted, although the Company believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments, 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 2008 Form 10-K.

2. Significant Accounting Policies

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

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

Recent Accounting Pronouncements. In December 2007, the Financial Accounting Standards Board (“FASB”) issued new guidance establishing 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. This new guidance, included in the Consolidation Topic of the FASB Accounting Standards Codification (“ASC”), also establishes disclosure requirements to clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. Effective January 1, 2009, the Company implemented the new guidance, which resulted in changes to the presentation for noncontrolling interests. This implementation did not have a material impact on the Company’s financial position or results of operations. All historical periods presented in the accompanying condensed consolidated financial statements reflect these changes to the presentation for noncontrolling interests. See Note 15.

In February 2008, the FASB issued guidance that delayed the effective date of certain requirements under the Fair Value Measurements and Disclosures Topic of the ASC 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. Effective January 1, 2009, the Company began following the

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Fair Value Measurements and Disclosures Topic of the ASC for all nonfinancial assets and liabilities. This implementation did not have a material impact on the Company’s financial position or results of operations.

In March 2008, the FASB issued new guidance regarding disclosures in the Derivatives and Hedging Topic of the ASC (“Derivative and Hedging Topic”), which requires expanded disclosure to provide greater transparency about (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedge items are accounted for under the Derivatives and Hedging Topic, and (iii) how derivative instruments and related hedged items affect an entity’s financial position, results of operations and cash flows. The Derivative and Hedging Topic requires 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 new guidance regarding disclosures in the Derivative and Hedging Topic became effective for the Company on January 1, 2009 and did not have a material impact on its financial position or results of operations. See Note 10.

In April 2009, the FASB amended the Financial Instruments Topic of the ASC (“Fair Value Disclosure Amendment”) to require publicly traded companies to provide disclosures about fair value of financial instruments in interim financial information as well as in annual financial statements. Under the Fair Value Disclosure Amendment, entities must disclose, in the body or in the accompanying notes of its summarized financial information for interim reporting periods and in its financial statements for annual reporting periods, the fair value of all financial instruments for which it is practicable to estimate the value, whether or not recognized in the statement of financial position. The Fair Value Disclosure Amendment became effective for the Company in the quarter ended June 30, 2009 and had no impact on the Company’s financial position or results of operations. See Note 3.

In May 2009, the FASB issued guidance to establish general standards of accounting for, and disclosure of, events that occur after the balance sheet date but before financial statements are issued or available to be issued (“Subsequent Events Topic”). In particular, the Subsequent Events Topic sets forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements for both interim and annual financial statements. The Company has applied the provisions of the Subsequent Events Topic to its consolidated interim financial statements for periods ended after June 15, 2009. See Note 18.

In June 2009, the FASB issued Accounting Standards Update 2009-01, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles—a replacement of FASB Statement No. 162” (“ASU 2009-01”). The FASB ASC is intended to be the source of authoritative GAAP and reporting standards as issued by the FASB. The primary purpose of the FASB ASC is to improve clarity and use of existing standards by grouping authoritative literature under common topics. ASU 2009-01 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Codification does not change or alter existing GAAP. The implementation of ASU 2009-01 had no impact to the Company’s financial position or results of operations.

In September 2009, the FASB issued its proposed updates to oil and gas accounting rules to align the oil and gas reserve estimation and disclosure requirements of Extractive Industries—Oil and Gas Topic of the ASC with the requirements in the Securities and Exchange Commission’s final rule, Modernization of the Oil and Gas Reporting Requirements, which was issued on December 31, 2008 and is effective for the year ending December 31, 2009. The public comment period for the FASB’s proposed updates ended October 15, 2009; however, no final guidance has been issued by the FASB. The Company is currently evaluating the potential impact on its depreciation, depletion and amortization rates, full cost ceiling limitation calculation and

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

disclosures of any updates to the oil and gas accounting rules and will comply with any new accounting and disclosure requirements once they become effective.

3. Fair Value Measurements

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


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

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

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

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels as described in the Fair Value Measurements and Disclosures Topic of the ASC. The determination of the fair values, stated below, takes into account the market for the Company’s financial assets and liabilities, the associated credit risk and other factors as required by the Fair Value Measurements and Disclosures Topic of the ASC. 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.

Fair Value of Derivative Contracts

The Company has classified its derivative contracts into one of the three levels of the fair value hierarchy 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 swaps are based upon quotes obtained from counterparties to the derivative contracts. The Company reviews other readily available market prices for its derivative contracts as there is an active market for these contracts. However, the Company does not have access to the specific valuation models used by its counterparties or other market participants. Included in these models are discount factors that the Company must estimate in its calculation. Additionally, the Company applies a value weighted average credit default risk rating factor for its counterparties 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.

The following table summarizes the Company’s financial assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy as of September 30, 2009 (in thousands):


	Fair Value Measurements							Assets/ Liabilities at Fair Value
Description	Level 1		Level 2		Level 3			Assets/ Liabilities at Fair Value
Derivative assets	$	—	$	—	$	129,453		$	129,453
Derivative liabilities		—		—		(28,863	)		(28,863	)

	$	—	$	—	$	100,590		$	100,590

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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


Three Months Ended September 30, 2009
Balance at June 30, 2009	$	236,080
Total gains or losses (realized/unrealized)		(54,278	)
Purchases, issuances and settlements		(81,212	)
Transfers in and/or out of Level 3		—

Balance at September 30, 2009	$	100,590


Nine Months Ended September 30, 2009
Balance at December 31, 2008	$	237,903
Total gains or losses (realized/unrealized)		134,731
Purchases, issuances and settlements		(272,044	)
Transfers in and/or out of Level 3		—

Balance at September 30, 2009	$	100,590


Changes in unrealized gains (losses) on derivative contracts held as of September 30, 2009	$	(137,313	)

See Note 10 for further discussion of the Company’s derivative contracts.

Fair Value of Debt

The Company measures fair value of its long-term debt in accordance with the Fair Value Measurements and Disclosures Topic of the ASC, giving consideration to the effect of the Company’s credit risk. The estimated fair value of the Company’s senior notes, based on quoted market prices, and the carrying value at September 30, 2009 were as follows (in thousands):


	Fair Value		Carrying Value
Senior Floating Rate Notes due 2014	$	309,016	$	350,000
8.625% Senior Notes due 2015		650,515		650,000
9.875% Senior Notes due 2016(1)		388,766		350,627
8.0% Senior Notes due 2018		730,337		750,000

(1)	Carrying value is net of a $14,873 discount.

The carrying value for the Company’s senior credit facility and remaining fixed rate debt instruments approximate fair value based on current rates applicable to similar instruments. See Note 8 for further discussion of the Company’s long-term debt.

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

4. Property, Plant and Equipment

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


	September 30, 2009			December 31, 2008
Natural gas and crude oil properties:
Proved	$	5,064,490		$	4,676,072
Unproved		229,687			215,698

Total natural gas and crude oil properties		5,294,177			4,891,770
Less accumulated depreciation, depletion and impairment(1)		(3,792,437	)		(2,369,840	)

Net natural gas and crude oil properties capitalized costs		1,501,740			2,521,930

Land		13,937			11,250
Non natural gas and crude oil equipment(2)		581,436			764,792
Buildings and structures		74,575			71,859

Total		669,948			847,901
Less accumulated depreciation, depletion and amortization		(207,461	)		(194,272	)

Net capitalized costs		462,487			653,629

Total property, plant and equipment, net	$	1,964,227		$	3,175,559

(1)	Includes cumulative full cost ceiling limitation impairment charges of $3,159.4 million and $1,855.0 million at September 30, 2009 and December 31, 2008, respectively. See Note 5.

(2)	Includes capitalized interest of approximately $3.8 million at both September 30, 2009 and December 31, 2008.

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

Sale of Midstream Assets. In June 2009, the Company completed the sale of its gathering and compression assets located in the Piñon Field, part of the West Texas Overthrust (“WTO”) located in Pecos and Terrell counties, Texas. Net proceeds to the Company were approximately $197.5 million, resulting in a loss of approximately $26.5 million. In conjunction with the sale, the Company entered into a gas gathering agreement and an operations and maintenance agreement. Under the gas gathering agreement, the Company has dedicated its Piñon Field acreage for priority gathering services for a period of twenty years and the Company will pay a fee that was negotiated at arms’ length for such services. Pursuant to the operations and maintenance agreement, the Company will operate and maintain the gathering system assets sold for a period of twenty years unless the Company or the buyer of the assets chooses to terminate the agreement.

Sale of East Texas Deep Rights. In June 2009, the Company completed the sale of its drilling rights in East Texas below the depth of the Cotton Valley formation for net proceeds of approximately $55.9 million, subject to certain post-closing adjustments. In October 2009, the Company received an additional $1.3 million in proceeds as a result of the post-closing adjustments. The sale of the drilling rights was accounted for as an adjustment to the full cost pool with no gain or loss recognized by the Company.

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

5. Impairment

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 September 30, 2009.

The net book value, less related deferred tax liabilities, is compared to the ceiling limitation on both 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 natural gas and crude oil properties by $1,304.4 million due to the full cost ceiling limitation. As the full cost ceiling exceeded the net capitalized costs at June 30, 2009 and September 30, 2009, there was no such reduction of the Company’s carrying value of its natural gas and crude oil properties during the second or third quarter of 2009.

6. 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 and sell a CO₂ treating plant in Pecos County, Texas (the “Century Plant”) and associated compression and pipeline facilities for $800.0 million. The Company will construct the Century Plant and Occidental will pay a minimum of 100% of the contract price, plus any subsequent agreed-upon revisions, to the Company through periodic cost reimbursements based upon the percentage of the project completed by the Company. Upon start-up, the Century Plant will be owned and operated by Occidental for the purpose of separating and removing CO₂ from natural gas delivered by the Company. Pursuant to a thirty-year treating agreement executed simultaneously with the construction agreement, Occidental will remove CO₂ from the Company’s delivered production volumes. The Company will retain all methane gas from the Century Plant.

The Company accounts for construction of the Century Plant using the completed-contract method, under which contract revenues and costs are recognized when work under 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 will be recorded, as appropriate, when it is determined that a loss will be incurred. Billings in excess of costs incurred were $5.1 million and $14.1 million and were reported as a current liability in the accompanying condensed consolidated balance sheets at September 30, 2009 and December 31, 2008, respectively.

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

7. Asset Retirement Obligation

The table below provides a reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligation for the period from December 31, 2008 to September 30, 2009 (in thousands).


Asset retirement obligation, December 31, 2008	$	84,772
Liability incurred in current period		2,689
Revisions in estimated cash flows		(162	)
Liability settled in current period		(2,505	)
Accretion of discount expense		5,316

Asset retirement obligation, September 30, 2009		90,110
Less: Current portion		2,077

Asset retirement obligation, net of current	$	88,033

8. Long-Term Debt

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


	September 30, 2009		December 31, 2008
Senior credit facility	$	—	$	573,457
Other notes payable:
Drilling rig fleet and related crude oil field services equipment		21,410		33,030
Mortgage		18,174		18,829
Senior Floating Rate Notes due 2014		350,000		350,000
8.625% Senior Notes due 2015		650,000		650,000
9.875% Senior Notes due 2016, net of $14,873 discount		350,627		—
8.0% Senior Notes due 2018		750,000		750,000

Total debt		2,140,211		2,375,316
Less: Current maturities of long-term debt		13,925		16,532

Long-term debt	$	2,126,286	$	2,358,784

For the three and nine months ended September 30, 2009, interest payments, including net amounts from current period settlements of the Company’s interest rate swap agreements (described below), were $8.8 million and $87.9 million, respectively. For the three and nine months ended September 30, 2008, interest payments, net of amounts capitalized, were $9.4 million and $60.2 million, respectively.

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 $985.4 million at September 30, 2009. The senior credit facility matures on November 21, 2011 and is available to be drawn on subject to limitations based on its terms and certain financial covenants, as fully described below.

The senior credit facility contains various covenants that limit the ability of the Company and certain of its subsidiaries to grant certain liens; make certain loans and investments; make distributions; redeem stock; redeem

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

or prepay debt; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets. Additionally, the senior credit facility limits the ability of the Company and certain of its subsidiaries to incur additional indebtedness with certain exceptions, including under the series of senior notes discussed below.

The senior credit facility contains financial covenants, including maintaining agreed 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) ratio of current assets to current liabilities, 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 September 30, 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 (a) the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 2.00% and 3.00% per annum or (b) the ‘base rate,’ which is the higher of (i) the federal funds rate plus 0.5%, (ii) the prime rate published by Bank of America or (iii) the Eurodollar rate (as defined in the senior credit facility) plus 1.00% per annum, plus, in each case under scenario (b), an applicable margin between 1.00% and 2.00% per annum. Interest is payable quarterly for 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 rates paid on amounts outstanding under the senior credit facility were 2.49% and 2.30% for the three months and nine months ended September 30, 2009, respectively.

The Company’s borrowing base is redetermined in April and October of each year. With respect to each redetermination, the administrative agent and the lenders under the senior credit facility consider several factors, including the Company’s proved reserves and projected cash requirements, and make assumptions regarding, among other things, natural gas and crude oil prices and production. Accordingly, the Company’s ability to develop its properties and changes in commodity prices impact the borrowing base. The borrowing base remained unchanged at $985.4 million as a result of the October 2009 redetermination. The Company has, at times, incurred additional costs related to the senior credit facility as a result of changes to the borrowing base. During 2009, additional costs of approximately $0.9 million were incurred. These costs have been deferred and are included in other assets in the accompanying condensed consolidated balance sheets. At September 30, 2009, the Company had $41.3 million in outstanding letters of credit with no amounts drawn on the senior credit facility.

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

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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 Notes Payable. The Company has financed a portion of its drilling rig fleet and related oil field services equipment through the issuance of notes secured by such equipment. At September 30, 2009, the aggregate outstanding balance of these notes was $21.4 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 0.50% to 1.00%) that is triggered if the Company repays the notes prior to maturity.

The debt incurred to purchase the downtown Oklahoma City property that serves as the Company’s corporate headquarters is fully secured by a mortgage on one of the buildings and a parking garage located on the property. The note underlying the mortgage bears interest at 6.08% annually and matures on November 15, 2022. Payments of principal and interest in the amount of approximately $0.5 million are due on a quarterly basis through the maturity date. During 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 senior term loans for senior unsecured notes with registration rights which were subsequently exchanged for substantially identical notes pursuant to a registered exchange offer. The effect of the exchange offers resulted in the Company issuing $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 and the terms of the unregistered notes for which the senior term loans were exchanged. 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 20 for condensed consolidating financial information of the subsidiary guarantors.

The Senior Floating Rate Notes bear interest at LIBOR plus 3.625% (4.22% at September 30, 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 principal due on April 1, 2014. The average interest rates paid on outstanding Senior Floating Rate Notes for the three months and nine months ended September 30, 2009 were 4.22% and 4.70%, respectively, without consideration of the interest rate swap discussed below. The 8.625% Senior Notes bear interest at a fixed rate of 8.625% per annum with the principal due on April 1, 2015. Under the terms of the 8.625% Senior Notes, interest is payable semi-annually 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 on 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 used to fix the variable LIBOR interest rate on the Senior Floating Rate Notes at an annual rate of 6.26% through April 1, 2011. In May 2009, the Company entered into a $350.0 million notional interest rate swap agreement to fix the variable LIBOR interest rate on the Senior Floating Rate Notes at an annual rate of

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

6.69% for the period from April 1, 2011 to April 1, 2013. The two interest rate swaps effectively serve to fix the Company’s variable interest rate on its Senior Floating Rate Notes for the majority of the term of these notes. These swaps have not been designated as hedges.

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

The 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 are being 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 condensed consolidated balance sheets.

9.875% Senior Notes Due 2016. In May 2009, the Company completed a private placement of $365.5 million of unsecured 9.875% Senior Notes due 2016 (“9.875% Senior Notes”) to qualified institutional investors eligible under Rule 144A of the Securities Act of 1933, as amended (the “Securities Act”). These notes were issued at a discount which will be amortized into interest expense over the term of the notes. Net proceeds from the offering were approximately $342.1 million after deducting offering expenses of $7.9 million. The Company used the net proceeds from the offering to repay outstanding borrowings under the senior credit facility and for general corporate purposes. The notes bear interest at a fixed rate of 9.875% per annum, payable semi-annually, with the principal due on May 15, 2016. The 9.875% Senior Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices. The notes are jointly and severally, unconditionally guaranteed on an unsecured basis by all of the Company’s wholly owned subsidiaries, except certain minor subsidiaries.

In conjunction with the issuance of the 9.875% Senior Notes, the Company entered into a Registration Rights Agreement requiring the Company to register these notes by May 16, 2010 if they are not already freely tradable at that time. The Company expects the notes to become freely tradable 180 days after their issuance pursuant to Rule 144 under the Securities Act. The Company is required to pay additional interest if it fails to fulfill its obligations under the agreement within the specified time periods.

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

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. The notes are freely tradable.

The Company incurred $16.0 million of debt issuance costs in connection with the offering of the 8.0% Senior Notes. These costs are included in other assets in the condensed consolidated balance sheet and are being 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, investments, asset

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

sales, certain asset purchases, transactions with related parties and consolidations or mergers. As of September 30, 2009, the Company was in compliance with all of the covenants contained in the indentures governing the senior notes.

9. Other Long-Term Obligations

Pursuant to 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. The current portion of the unpaid settlement of $5.0 million was included in accounts payable-trade in the accompanying condensed consolidated balance sheets as of September 30, 2009 and December 31, 2008. The non-current unpaid settlement amounts of $5.0 million and $10.0 million have been included in other long-term obligations in the accompanying condensed consolidated balance sheets at September 30, 2009 and December 31, 2008, respectively.

10. Derivatives

The Company’s derivative contracts have not been designated as hedges. The Company records all derivative contracts, which include commodity derivatives and interest rate swaps, at fair value. Changes in derivative contract fair values are recognized in earnings. Cash settlements and valuation gains and losses are included in loss (gain) on derivative contracts for the commodity derivative contracts and in interest expense for the interest rate swaps in the consolidated statements of operations. Commodity derivative contracts are settled on a monthly basis. Settlements on the interest rate swaps occur quarterly. Derivative assets and liabilities arising from the Company’s derivative contracts with the same counterparty that provide for net settlement are reported on a net basis in the consolidated balance sheet.

Commodity Derivatives. The Company is exposed to commodity price risk, which impacts the predictability of its cash flows related to the sale of natural gas and crude oil. This risk is managed by the Company’s use of commodity derivative contracts. 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 may be terminated early as a result of a party having its credit rating downgraded. At September 30, 2009 and December 31, 2008, the Company’s commodity derivative contracts consisted of fixed price swaps and basis swaps, which are described below:


Fixed price swaps		The Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

Basis swaps		The Company receives a payment from the counterparty if the settled price differential is greater than the stated terms of the contract and pays the counterparty if the settled price differential is less than the stated terms of the contract, which guarantees the Company a price differential for natural gas from a specified delivery point.

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

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

The Company has entered into two interest rate swap agreements to manage the interest rate risk on a portion of its floating rate debt by effectively fixing the variable interest rate on its Senior Floating Rate Notes. See Note 8 for further discussion of the Company’s interest rate swaps.

Fair Value of Derivatives. The balance sheet classification of assets and liabilities related to derivative contracts is summarized below at September 30, 2009 and December 31, 2008 (in thousands):


	Balance Sheet Classification	Fair Value
Type of Contract	Balance Sheet Classification	September 30, 2009		December 31, 2008
Derivative assets
Natural gas swaps	Derivative assets-current	$	126,934	$	188,045
Crude oil price swaps	Derivative assets-current		2,519		13,066
Natural gas swaps	Derivative assets-noncurrent		—		45,537

Total derivative assets		$	129,453	$	246,648

Derivative liabilities
Interest rate swaps	Derivative liabilities-current	$	7,223	$	5,106
Interest rate swaps	Derivative liabilities-noncurrent		2,383		—
Natural gas basis swaps	Derivative liabilities-noncurrent		19,257		3,639

Total derivative liabilities		$	28,863	$	8,745

A counterparty to one of the Company’s derivative contracts, Lehman Brothers, declared bankruptcy on October 3, 2008. Due to Lehman Brothers’ bankruptcy, the declaration of bankruptcy by its parent, Lehman Brothers Holdings Inc., on September 15, 2008, and the asset position of the contract, the Company did not assign any value to this derivative contract from September 30, 2008 until September 30, 2009. During August 2009, the Company entered into an agreement with Lehman Brothers to settle all unsettled positions under this derivative contract through September 30, 2009. As of October 1, 2009, Lehman Brothers assigned this contract to a third-party to serve as the counterparty for the remaining three months of the contract. Accordingly, both the realized portion and the future value of this derivative contract were included in the accompanying condensed consolidated financial statements at September 30, 2009.

The following table summarizes the effect of the Company’s derivative contracts on the condensed consolidated statements of operations for the three and nine-month periods ended September 30, 2009 and 2008 (in thousands):


		Amount of (Gain) Loss Recognized in Income
		Three Months Ended September 30,					Nine Months Ended September 30,
Type of Contract	Location of (Gain) Loss Recognized in Income	2009		2008			2009			2008
Interest rate swap	Interest expense	$	6,345	$	2,714		$	4,991		$	(7,736	)
Natural gas and crude oil swaps	Loss (gain) on derivative contracts		47,933		(292,526	)		(139,722	)		4,086

Total		$	54,278	$	(289,812	)	$	(134,731	)	$	(3,650	)

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

The following table summarizes the cash settlements and valuation gains and losses on commodity derivative contracts for the three and nine-month periods ended September 30, 2009 and 2008 (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Realized (gain) loss	$	(83,038	)	$	27,279		$	(276,175	)	$	77,954
Unrealized loss (gain)		130,971			(319,805	)		136,453			(73,868	)

Loss (gain) on commodity derivative contracts	$	47,933		$	(292,526	)	$	(139,722	)	$	4,086

Net losses of $6.3 million ($4.5 million unrealized loss and $1.8 million realized losses) and $5.0 million ($0.9 million unrealized loss and $4.1 million realized losses) related to the interest rate swaps discussed above were included in interest expense in the accompanying condensed consolidated statement of operations for the three months and nine months ended September 30, 2009, respectively. An unrealized loss of $2.7 million and an unrealized gain of $7.7 million were included in the accompanying condensed consolidated statements of operations for the three months and nine months ended September 30, 2008, respectively.

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

Open Derivative Contracts. At September 30, 2009, the Company’s open natural gas and crude oil commodity derivative contracts consisted of the following:

Natural Gas


Period and Type of Contract	Notional (MMcf)(1)	Weighted Avg. Fixed Price
October 2009 — December 2009
Price swap contracts	19,010	$	8.46
Basis swap contracts	17,480	$	(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	$	7.32
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	25,650	$	(0.47	)
April 2011 — June 2011
Basis swap contracts	25,935	$	(0.47	)
July 2011 — September 2011
Basis swap contracts	26,220	$	(0.47	)

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)


Period and Type of Contract	Notional (MMcf)(1)	Weighted Avg. Fixed Price
October 2011 — December 2011
Basis swap contracts	26,220	$	(0.47	)
January 2012 — March 2012
Basis swap contracts	28,210	$	(0.55	)
April 2012 — June 2012
Basis swap contracts	28,210	$	(0.55	)
July 2012 — September 2012
Basis swap contracts	28,520	$	(0.55	)
October 2012 — December 2012
Basis swap contracts	28,520	$	(0.55	)

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

Crude Oil


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

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 and nine-month periods ended September 30 (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Current:
Federal	$	(1,763	)	$	(848	)	$	(3,983	)	$	(848	)
State		(817	)		4,542			(135	)		5,566

		(2,580	)		3,694			(4,118	)		4,718

Deferred:
Federal		—			122,832			4			81,596
State		—			4,167			—			2,994

		—			126,999			4			84,590

Total (benefits) provisions	$	(2,580	)	$	130,693		$	(4,114	)	$	89,308

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 of the deferred assets will not be realized based on the weight of all available evidence. For the year ended

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

December 31, 2008, the Company determined it was appropriate to record a full valuation allowance against its net deferred tax asset. For the nine-month period ended September 30, 2009, the Company recorded a $467.2 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 $1,351.5 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 experienced an ownership change, within the meaning of IRC Section 382, during December 2008. Although the Company does expect a limitation on certain of its tax attributes as a result of the ownership change, such limitation is not expected to result in a current federal tax liability for the year ending December 31, 2009.

No reserves for uncertain income tax positions have been recorded pursuant to the guidance for uncertainty in income taxes under the Income Taxes Topic of the ASC. Tax years 1999 to present remain open for the majority of taxing authorities due to net operating 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 September 30, 2009.

For the three-month period ended September 30, 2009 and 2008, income tax payments, net of refunds, were $0.0 million and $0.1 million, respectively. For the nine-month period ended September 30, 2009 and 2008, income tax payments, net of refunds, were approximately $3.0 million and $2.0 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 and outstanding convertible preferred stock. The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings per share, for the three and nine-month periods ended September 30, 2009 and 2008 (in thousands):


	Three Months Ended September 30,		Nine Months Ended September 30,
	2009	2008	2009	2008
Weighted average basic common shares outstanding	178,069	163,020	171,902	153,125
Effect of dilutive securities:
Restricted stock	—	1,534	—	1,364
Convertible preferred stock	—	—	—	—

Weighted average diluted common and potential common shares outstanding	178,069	164,554	171,902	154,489

For the three and nine-month periods ended September 30, 2009, 3.2 million shares and 2.7 million shares of restricted stock not yet vested, 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 (see Note 15) for the three and nine-month periods ended September 30, 2009 and with respect to its then outstanding redeemable convertible preferred stock for the nine-month period ended September 30, 2008. Under this method, the Company assumes the conversion of the

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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 was not more dilutive for the three and nine-month periods ended September 30, 2009. The Company determined the if-converted method was not more dilutive and included preferred stock dividends in the determination of income available to common stockholders for the nine-month period ended September 30, 2008. No shares of redeemable convertible preferred stock were outstanding during the three-month period ended September 30, 2008.

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 that, individually or in the aggregate, could have a material effect on the financial condition, results of 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. A summary of dividends declared and paid on the redeemable convertible preferred stock is as follows (in thousands, except per share data):


Declared	Dividend Period	Dividends 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. Additionally, during May 2008, the Company converted the remaining outstanding 1,844,464 shares of its redeemable convertible preferred stock into 18,810,260 shares of its common stock as permitted under the terms of the redeemable convertible preferred stock. These conversions resulted in increases to additional paid-in capital totaling

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

$452.2 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 charges to retained earnings totaling $7.2 million in accelerated accretion expense related to the converted redeemable convertible preferred shares. Prorated dividends totaling $0.5 million for the period from May 2, 2008 to the date of conversion (May 7, 2008) were paid to the holders of the converted shares on May 7, 2008. On and after the conversion date, dividends ceased to accrue and the rights of common unit holders to exercise outstanding warrants to purchase redeemable convertible preferred shares terminated.

Approximately $8.6 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 nine-month period ended September 30, 2008, as presented in the accompanying condensed consolidated statement of operations. No shares of redeemable convertible preferred stock were outstanding during the three-month period ended September 30, 2008.

15. Equity

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


	September 30, 2009	December 31, 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 investors 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 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 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 per share 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. Approximately $2.8 million in unpaid dividends on the 8.5% convertible perpetual preferred stock has been included in the Company’s earnings per share calculations for the three and nine-month periods ended September 30, 2009 as presented in the accompanying condensed consolidated statements of operations. 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.

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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


	September 30, 2009	December 31, 2008
Shares authorized	400,000	400,000
Shares outstanding at end of period	183,524	166,046
Shares held in treasury	1,462	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. In May 2008, the Company converted the remaining 1,844,464 outstanding shares of its redeemable convertible preferred stock into 18,810,260 shares of its common stock as permitted under the terms of the redeemable convertible preferred stock. See additional discussion in Note 14.

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 $107.6 million, after deducting offering expenses of approximately $2.4 million, and were used to repay a portion of the amount outstanding under the senior credit facility and for general corporate purposes.

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 136,000 shares having a total value of $1.1 million and approximately 79,000 shares having a total value of $3.5 million during the nine-month periods ended September 30, 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.

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

Equity compensation provided to employees directly involved in natural gas and crude oil exploration and development activities is capitalized to the Company’s natural gas and crude oil properties. Equity compensation not capitalized is reflected in general and administrative expenses, production expenses, midstream and marketing expenses and drilling and services expenses in the consolidated statements of operations. For the three-month and nine-month periods ended September 30, 2009, the Company recognized equity compensation expense of $6.2 million and $16.5 million, net of $1.1 million and $3.2 million capitalized, respectively, related to restricted common stock. For the three-month and nine-month periods ended September 30, 2008, the Company recognized equity compensation expense of $5.5 million and $12.8 million, respectively, related to restricted common stock. There was no equity compensation capitalized in 2008.

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Effective June 5, 2009, the Company adopted the SandRidge Energy, Inc. 2009 Incentive Plan (the “2009 Incentive Plan”). Under the terms of the 2009 Incentive Plan, the Company may grant stock options, stock appreciation rights, shares of restricted stock, restricted stock units and other forms of awards based on the value (or increase in the value) of shares of the common stock of the Company for up to 12,000,000 shares of common stock. The 2009 Incentive Plan also permits cash incentive awards. Consistent with its other incentive plans, the Company intends for shares of restricted stock to be the primary form of awards granted under the 2009 Incentive Plan.

Noncontrolling Interest. 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 as required by the Consolidation Topic of the ASC.

16. Related Party Transactions

The Company enters into transactions in the ordinary course of business with certain of its stockholders and other related parties. These transactions primarily consist of purchases of gas treating services and drilling equipment and sales of oil field services and natural gas. Following is a summary of significant transactions with such related parties for the three and nine-month periods ended September 30, 2009 and 2008 (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Sales to and reimbursements from related parties	$	1,014	$	24,552	$	5,420	$	76,978

Purchases of services from related parties	$	4,550	$	11,380	$	18,956	$	50,441

Through August 2009, the Company leased office space in Oklahoma City from a member of its Board of Directors. The Company believes that the payments made under this lease were at fair market rates. Rent expense related to the lease totaled $0.1 million and $0.3 million for the three-month periods ended September 30, 2009 and 2008, respectively. For the nine-month periods ended September 30, 2009 and 2008, rent expense under this lease was $0.6 million and $1.0 million, respectively. The lease expired 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, and, until such time, Lariat operated the rigs owned by Larclay. On April 15, 2009, Lariat completed an assignment to CWEI of Lariat’s 50% equity interest in Larclay pursuant to the terms of an Assignment and Assumption Agreement (the “Larclay Assignment”) entered into between Lariat and CWEI on March 13, 2009. Pursuant to the Larclay Assignment, Lariat assigned all of its right, title and interest in and to Larclay to CWEI effective April 15, 2009, and CWEI assumed all of the obligations and liabilities of Lariat relating to Larclay. The Company fully impaired both the investment in and notes receivable due from Larclay at December 31, 2008. There were no additional losses on Larclay during the three or nine-month period ended September 30, 2009 or as a result of the Larclay Assignment.

For the three-month period ended September 30, 2008, sales to and reimbursements from Larclay were $11.2 million and purchases of services from Larclay were $7.1 million. There were no sales, reimbursements or purchases from Larclay during the three-month period ended September 30, 2009. For the nine-month periods ended September 30, 2009 and 2008, sales to and reimbursements from Larclay were $3.0 million and $34.2 million, respectively. Purchases of services from Larclay were $1.8 million and $31.1 million for the nine months ended September 30, 2009 and 2008, respectively.

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

17. Crusader Acquisition

On September 22, 2009, the Company entered into a Stock Purchase Agreement (“Crusader Purchase Agreement”) with Crusader Energy Group Inc. and its subsidiaries (collectively, “Crusader”) to purchase all of the shares of common stock of Crusader that will be issued upon the effectiveness of Crusader’s reorganization under Chapter 11 of the United States Bankruptcy Code. The closing of the transaction is subject to customary conditions, approval by Crusader’s creditors and the Bankruptcy Court, consideration of alternative transactions that may be submitted prior to a bid deadline, and an auction to be held after the bid deadline. The closing of the transaction is expected to occur during the fourth quarter of 2009.

The consideration payable by the Company consists of the following: $55.0 million cash, subject to certain adjustments; 13,015,797 shares of Company common stock, subject to certain adjustments; and warrants to purchase an aggregate of 2.0 million shares of Company common stock at an exercise price of $15.00 per share during an exercise period ending five years after the closing date of the transactions contemplated under the Crusader Purchase Agreement. Recipients of the stock consideration and warrants will not be permitted to dispose of such stock consideration or warrants for 180 days after the closing date of the transaction.

If the total amount of the claims against Crusader that are required to be paid or reserved for under Crusader’s plan of reorganization (the “Plan”) on the closing date exceeds the amount of the cash consideration payable by the Company plus Crusader’s cash assets on the closing date, then the Company will make up to a $30.0 million loan to the liquidating trust created under the Plan to pay or reserve for such claims. In the event of such a loan, a number of shares of the Company’s common stock with an aggregate value (calculated at $13.4452 per share) equal to the amount of the loan will be withheld and reserved from the shares required to be issued on the closing date. Approximately six months after the closing date, the Company will deliver the number of reserved shares that has an aggregate value (calculated at $13.4452 per share) equal to the amount of the loan that was repaid to the Company by the liquidating trust minus unpaid interest.

18. Subsequent Events

Grey Ranch. During October 2009, the Company executed amendments to certain agreements related to the ownership and operation of Grey Ranch Plant, LP (“GRLP”), the limited partnership that operates the Grey Ranch Plant located in Pecos County, Texas. As a result of these amendments, the Company became the primary beneficiary of GRLP. The Company currently accounts for its ownership interest in GRLP using the equity method of accounting; however, due to this change, the Company will include the activity of GRLP in its consolidated financial statements prospectively beginning on the agreements’ effective date, or October 1, 2009. The change from equity method of accounting to the consolidation of GRLP activity will have no effect on the Company’s net income.

Events occurring after September 30, 2009 were evaluated as of November 5, 2009, the date this Quarterly Report was issued to ensure that any subsequent events that met the criteria for recognition and/or disclosure in this report have been included.

19. Business Segment Information

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

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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


	Exploration and Production			Drilling and Oil Field Services			Midstream Gas Services			All Other			Consolidated Total
Three Months Ended September 30, 2009
Revenues	$	105,026		$	42,958		$	52,564		$	9,576		$	210,124
Inter-segment revenue		(66	)		(37,160	)		(36,644	)		(1,399	)		(75,269	)

Total revenues	$	104,960		$	5,798		$	15,920		$	8,177		$	134,855

Operating (loss) income	$	(31,123	)	$	(4,621	)	$	476		$	(14,961	)	$	(50,229	)
Interest expense, net		(52,344	)		(482	)		—			(286	)		(53,112	)
Other (expense) income, net		(1,144	)		—			593			—			(551	)

(Loss) income before income taxes	$	(84,611	)	$	(5,103	)	$	1,069		$	(15,247	)	$	(103,892	)

Capital expenditures(1)	$	87,288		$	569		$	2,500		$	7,360		$	97,717

Depreciation, depletion and amortization	$	33,759		$	7,042		$	558		$	3,793		$	45,152


Three Months Ended September 30, 2008
Revenues	$	259,878		$	121,376		$	198,220		$	5,851		$	585,325
Inter-segment revenue		(66	)		(109,343	)		(140,510	)		(1,383	)		(251,302	)

Total revenues	$	259,812		$	12,033		$	57,710		$	4,468		$	334,023

Operating income (loss)	$	418,751		$	4,054		$	(1,359	)	$	(20,159	)	$	401,287
Interest expense, net		(39,075	)		(729	)		—			(299	)		(40,103	)
Other (expense) income, net		(63	)		281			(418	)		57			(143	)

Income (loss) before income taxes	$	379,613		$	3,606		$	(1,777	)	$	(20,401	)	$	361,041

Capital expenditures(1)	$	590,167		$	25,749		$	40,696		$	18,442		$	675,054

Depreciation, depletion and amortization	$	72,702		$	10,015		$	4,057		$	2,787		$	89,561

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)


	Exploration and Production			Drilling and Oil Field Services			Midstream Gas Services			All Other			Consolidated Total
Nine Months Ended September 30, 2009
Revenues	$	330,686		$	192,747		$	218,769		$	21,983		$	764,185
Inter-segment revenue		(196	)		(175,540	)		(158,339	)		(2,143	)		(336,218	)

Total revenues	$	330,490		$	17,207		$	60,430		$	19,840		$	427,967

Operating loss(2)	$	(1,132,233	)	$	(10,177	)	$	(27,344	)	$	(46,742	)	$	(1,216,496	)
Interest expense, net		(133,550	)		(1,673	)		—			(858	)		(136,081	)
Other income, net		100			—			1,027			—			1,127

Loss before income taxes	$	(1,265,683	)	$	(11,850	)	$	(26,317	)	$	(47,600	)	$	(1,351,450	)

Capital expenditures(1)	$	470,519		$	2,770		$	43,788		$	25,124		$	542,201

Depreciation, depletion and amortization	$	129,544		$	21,237		$	4,515		$	11,058		$	166,354


At September 30, 2009
Total assets	$	1,837,704		$	234,445		$	112,526		$	126,293		$	2,310,968


Nine Months Ended September 30, 2008
Revenues	$	760,316		$	309,934		$	566,274		$	17,358		$	1,653,882
Inter-segment revenue		(154	)		(273,715	)		(395,181	)		(3,673	)		(672,723	)

Total revenues	$	760,162		$	36,219		$	171,093		$	13,685		$	981,159

Operating income (loss)	$	364,817		$	6,550		$	5,226		$	(49,912	)	$	326,681
Interest expense, net		(82,310	)		(2,141	)		—			(902	)		(85,353	)
Other income, net		716			389			891			215			2,211

Income (loss) before income taxes	$	283,223		$	4,798		$	6,117		$	(50,599	)	$	243,539

Capital expenditures(1)	$	1,404,067		$	61,540		$	110,125		$	33,623		$	1,609,355

Depreciation, depletion and amortization	$	211,290		$	31,707		$	10,190		$	7,451		$	260,638


At December 31, 2008
Total assets	$	2,986,070		$	275,164		$	284,281		$	109,543		$	3,655,058

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

(2)

The operating loss for the exploration and production segment for the nine-month period ended September 30, 2009 includes a $1,304.4 million non-cash full cost ceiling impairment recorded in the first quarter of 2009 on the Company’s natural gas and crude oil properties. The operating loss for the midstream gas services segment for the nine-month period ended September 30, 2009 includes the approximately $26.5 million loss on the sale of its gathering and compression assets in the Piñon Field during the second quarter of 2009.

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

20. Condensed Consolidating Financial Information

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

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

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 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.

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Condensed Consolidating Balance Sheets


	September 30, 2009
	Parent Company			Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	14,414		$	228	$	—		$	14,642
Accounts and notes receivable, net		69,173			414,127		(402,715	)		80,585
Derivative contracts		—			129,453		—			129,453
Other current assets		—			35,763		—			35,763

Total current assets		83,587			579,571		(402,715	)		260,443
Property, plant and equipment, net		—			1,964,227		—			1,964,227
Investment in subsidiaries		2,198,115			—		(2,198,115	)		—
Other assets		41,605			96,077		(51,384	)		86,298

Total assets	$	2,323,307		$	2,639,875	$	(2,652,214	)	$	2,310,968

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	404,089		$	229,287	$	(402,715	)	$	230,661
Other current liabilities		7,223			21,143		—			28,366

Total current liabilities		411,312			250,430		(402,715	)		259,027
Long-term debt		2,100,627			77,043		(51,384	)		2,126,286
Asset retirement obligation		—			88,033		—			88,033
Other liabilities		2,383			26,224		—			28,607

Total liabilities		2,514,322			441,730		(454,099	)		2,501,953

(Deficit) equity		(191,015	)		2,198,145		(2,198,115	)		(190,985	)

Total liabilities and equity	$	2,323,307		$	2,639,875	$	(2,652,214	)	$	2,310,968

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)


	December 31, 2008
	Parent Company		Guarantor 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

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Condensed Consolidating Statements of Operations


	Parent Company			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Three Months Ended September 30, 2009
Revenues	$	—		$	134,855		$	—		$	134,855
Expenses:
Direct operating expenses		—			66,993			—			66,993
General and administrative		—			25,006			—			25,006
Depreciation, depletion and amortization		—			45,152			—			45,152
Loss on derivative contracts		—			47,933			—			47,933

Total expenses		—			185,084			—			185,084

Loss from operations		—			(50,229	)		—			(50,229	)
Equity earnings from subsidiaries		(51,566	)		—			51,566			—
Interest expense, net		(52,330	)		(782	)		—			(53,112	)
Other (expense) income, net		—			(551	)		—			(551	)

Loss before income tax benefit		(103,896	)		(51,562	)		51,566			(103,892	)
Income tax benefit		(2,580	)		—			—			(2,580	)

Net loss		(101,316	)		(51,562	)		51,566			(101,312	)
Less: net income attributable to noncontrolling interest		—			4			—			4

Net loss applicable to SandRidge Energy, Inc.	$	(101,316	)	$	(51,566	)	$	51,566		$	(101,316	)


Three Months Ended September 30, 2008
Revenues	$	98,320		$	234,415		$	1,288		$	334,023
Expenses:
Direct operating expenses		18,806			86,372			1,288			106,466
General and administrative		10,722			18,513			—			29,235
Depreciation, depletion, and amortization		31,400			58,161			—			89,561
Gain on derivative contracts		(292,526	)		—			—			(292,526	)

Total expenses		(231,598	)		163,046			1,288			(67,264	)

Income from operations		329,918			71,369			—			401,287
Equity earnings from subsidiaries		70,172			—			(70,172	)		—
Interest expense, net		(39,130	)		(973	)		—			(40,103	)
Other income (expense), net		43			(186	)		—			(143	)

Income before income tax expense		361,003			70,210			(70,172	)		361,041
Income tax expense		130,657			36			—			130,693

Net income		230,346			70,174			(70,172	)		230,348
Less: net income attributable to noncontrolling interest		—			2			—			2

Net income attributable to SandRidge Energy, Inc.	$	230,346		$	70,172		$	(70,172	)	$	230,346

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)


	Parent Company			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Nine Months Ended September 30, 2009
Revenues	$	58,271		$	371,801		$	(2,105	)	$	427,967
Expenses:
Direct operating expenses		27,737			210,658			(2,105	)		236,290
General and administrative		15,515			61,608			—			77,123
Depreciation, depletion, amortization and impairment		627,478			843,294			—			1,470,772
(Gain) loss on derivative contracts		(237,351	)		97,629			—			(139,722	)

Total expenses		433,379			1,213,189			(2,105	)		1,644,463

Loss from operations		(375,108	)		(841,388	)		—			(1,216,496	)
Equity earnings from subsidiaries		(842,935	)		—			842,935			—
Interest expense, net		(133,520	)		(2,561	)		—			(136,081	)
Other income, net		102			1,025			—			1,127

Loss before income tax benefit		(1,351,461	)		(842,924	)		842,935			(1,351,450	)
Income tax benefit		(4,114	)		—			—			(4,114	)

Net loss		(1,347,347	)		(842,924	)		842,935			(1,347,336	)
Less: net income attributable to noncontrolling interest		—			11			—			11

Net loss applicable to SandRidge Energy, Inc.	$	(1,347,347	)	$	(842,935	)	$	842,935		$	(1,347,347	)


Nine Months Ended September 30, 2008
Revenues	$	266,929		$	715,308		$	(1,078	)	$	981,159
Expenses:
Direct operating expenses		54,327			260,073			(1,078	)		313,322
General and administrative		28,021			48,411			—			76,432
Depreciation, depletion, and amortization		83,336			177,302			—			260,638
Loss on derivative contracts		4,086			—			—			4,086

Total expenses		169,770			485,786			(1,078	)		654,478

Income from operations		97,159			229,522			—			326,681
Equity earnings from subsidiaries		228,249			—			(228,249	)		—
Interest expense, net		(82,738	)		(2,615	)		—			(85,353	)
Other (expense) income, net		(20	)		2,231			—			2,211

Income before income tax expense		242,650			229,138			(228,249	)		243,539
Income tax expense		89,272			36			—			89,308

Net income		153,378			229,102			(228,249	)		154,231
Less: net income attributable to noncontrolling interest		—			853			—			853

Net income attributable to SandRidge Energy, Inc.	$	153,378		$	228,249		$	(228,249	)	$	153,378

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Condensed Consolidating Statements of Cash Flows


	Parent Company			Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Nine Months Ended September 30, 2009
Net cash provided by operating activities	$	137,794		$	135,426		$	—	$	273,220
Net cash used in investing activities		(240,992	)		(123,531	)		—		(364,523	)
Net cash provided by (used in) financing activities		117,594			(12,285	)		—		105,309

Net increase (decrease) in cash and cash equivalents		14,396			(390	)		—		14,006
Cash and cash equivalents at beginning of period		18			618			—		636

Cash and cash equivalents at end of period	$	14,414		$	228		$	—	$	14,642


Nine Months Ended September 30, 2008
Net cash (used in) provided by operating activities	$	(150,969	)	$	685,337		$	—	$	534,368
Net cash used in investing activities		(789,828	)		(667,274	)		—		(1,457,102	)
Net cash provided by (used in) financing activities		877,858			(17,361	)		—		860,497

Net (decrease) increase in cash and cash equivalents		(62,939	)		702			—		(62,237	)
Cash and cash equivalents at beginning of period		62,967			168			—		63,135

Cash and cash equivalents at end of period	$	28		$	870		$	—	$	898

ITEM 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Introduction

The following discussion and analysis is intended to help the reader understand our business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with our condensed consolidated financial statements and the accompanying notes included in this Quarterly Report, as well as our audited consolidated financial statements and the accompanying notes included in our 2008 Form 10-K.

The financial information with respect to the three and nine-month periods ended September 30, 2009 and September 30, 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 consolidated 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 results of operations largely is determined by the amount of work each performs for third parties. Revenues and costs related to work performed by these businesses for our own account are eliminated in consolidation and, therefore, do not contribute to our consolidated results of operations.

Recent Events

Crusader Acquisition. On September 22, 2009, we entered into the Crusader Purchase Agreement with Crusader to purchase all of the shares of common stock of Crusader that will be issued upon the effectiveness of Crusader’s reorganization under Chapter 11 of the United States Bankruptcy Code. The closing of the transaction is subject to customary conditions, approval by Crusader’s creditors and the Bankruptcy Court, consideration of alternative transactions that may be submitted prior to the bid deadline, and an auction to be held after the bid deadline. The closing of the transaction is expected to occur during the fourth quarter of 2009.

The consideration payable by us consists of the following: $55.0 million cash, subject to certain adjustments; 13,015,797 shares of Company common stock, subject to certain adjustments; and warrants to purchase an aggregate of 2.0 million shares of Company common stock at an exercise price of $15.00 per share during an exercise period ending five years after the closing date of the transactions contemplated under the Crusader Purchase Agreement. Recipients of the stock consideration and warrants will not be permitted to dispose of such stock consideration or warrants for 180 days after the closing date of the transaction.

shares of the Company’s common stock with an aggregate value (calculated at $13.4452 per share) equal to the amount of the loan will be withheld and reserved from the shares required to be issued on the closing date. Approximately six months after the closing date, we will deliver the number of reserved shares that has an aggregate value (calculated at $13.4452 per share) equal to the amount of the loan that was repaid to us by the liquidating trust minus unpaid interest.

Grey Ranch. During October 2009, we executed amendments to certain agreements related to the ownership and operation of Grey Ranch Plant, LP (“GRLP”), the limited partnership that operates the Grey Ranch Plant located in Pecos County, Texas. As a result of these amendments, we became the primary beneficiary of GRLP. We currently account for our ownership interest in GRLP using the equity method of accounting; however, due to this change, we will include the activity of GRLP in our consolidated financial statements prospectively beginning on the agreements’ effective date, or October 1, 2009. The change from equity method of accounting to the consolidation of GRLP activity will have no effect on our net income.

Segment Overview

We operate in three business segments: exploration and production, drilling and oil field services and midstream gas services. The All Other column in the tables below includes items not related to our reportable segments including our CO₂ gathering and sales operations and corporate operations. Management evaluates the performance of our business segments based on operating income (loss), which is defined as segment operating revenue less operating expenses and depreciation, depletion and amortization. Results of these measures provide important information to us about the activity and profitability of our lines of business. Set forth in the table below is financial information regarding each of our business segments for the three and nine-month periods ended September 30, 2009 and 2008 (in thousands).


	Exploration and Production			Drilling and Oil Field Services			Midstream Gas Services			All Other			Consolidated Total
Three Months Ended September 30, 2009
Revenues	$	105,026		$	42,958		$	52,564		$	9,576		$	210,124
Inter-segment revenue		(66	)		(37,160	)		(36,644	)		(1,399	)		(75,269	)

Total revenues	$	104,960		$	5,798		$	15,920		$	8,177		$	134,855


Operating (loss) income	$	(31,123	)	$	(4,621	)	$	476		$	(14,961	)	$	(50,229	)
Interest expense, net		(52,344	)		(482	)		—			(286	)		(53,112	)
Other (expense) income, net		(1,144	)		—			593			—			(551	)

(Loss) income before income taxes	$	(84,611	)	$	(5,103	)	$	1,069		$	(15,247	)	$	(103,892	)


Three Months Ended September 30, 2008
Revenues	$	259,878		$	121,376		$	198,220		$	5,851		$	585,325
Inter-segment revenue		(66	)		(109,343	)		(140,510	)		(1,383	)		(251,302	)

Total revenues	$	259,812		$	12,033		$	57,710		$	4,468		$	334,023


Operating income (loss)	$	418,751		$	4,054		$	(1,359	)	$	(20,159	)	$	401,287
Interest expense, net		(39,075	)		(729	)		—			(299	)		(40,103	)
Other (expense) income, net		(63	)		281			(418	)		57			(143	)

Income (loss) before income taxes	$	379,613		$	3,606		$	(1,777	)	$	(20,401	)	$	361,041


	Exploration and Production			Drilling and Oil Field Services			Midstream Gas Services			All Other			Consolidated Total
Nine Months Ended September 30, 2009
Revenues	$	330,686		$	192,747		$	218,769		$	21,983		$	764,185
Inter-segment revenue		(196	)		(175,540	)		(158,339	)		(2,143	)		(336,218	)

Total revenues	$	330,490		$	17,207		$	60,430		$	19,840		$	427,967


Operating loss(1)	$	(1,132,233	)	$	(10,177	)	$	(27,344	)	$	(46,742	)	$	(1,216,496	)
Interest expense, net		(133,550	)		(1,673	)		—			(858	)		(136,081	)
Other income, net		100			—			1,027			—			1,127

Loss before income taxes	$	(1,265,683	)	$	(11,850	)	$	(26,317	)	$	(47,600	)	$	(1,351,450	)


Nine Months Ended September 30, 2008
Revenues	$	760,316		$	309,934		$	566,274		$	17,358		$	1,653,882
Inter-segment revenue		(154	)		(273,715	)		(395,181	)		(3,673	)		(672,723	)

Total revenues	$	760,162		$	36,219		$	171,093		$	13,685		$	981,159


Operating income (loss)	$	364,817		$	6,550		$	5,226		$	(49,912	)	$	326,681
Interest expense, net		(82,310	)		(2,141	)		—			(902	)		(85,353	)
Other income, net		716			389			891			215			2,211

Income (loss) before income taxes	$	283,223		$	4,798		$	6,117		$	(50,599	)	$	243,539

(1)

The operating loss for the exploration and production segment for the nine-month period ended September 30, 2009 includes a $1,304.4 million non-cash full cost ceiling impairment recorded in the first quarter of 2009 on our natural gas and crude oil properties. The operating loss for the midstream gas services segment for the nine-month period ended September 30, 2009 includes the approximately $26.5 million loss on the sale of its gathering and compression assets in the Piñon Field in the second quarter of 2009.

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 natural gas and crude oil we produce and changes in the fair value of commodity derivative contracts we use to reduce the volatility of the prices we receive for our natural gas and crude oil production. Three and nine-month comparisons of production and prices are presented in the following tables:


	Three Months Ended September 30,				Change
	2009		2008		Amount			Percent
Production data:
Natural gas (Mmcf)		20,897		22,209		(1,312	)	(5.9	)%
Crude oil (MBbls)		723		521		202		38.8	%
Combined equivalent volumes (Mmcfe)		25,235		25,335		(100	)	(0.4	)%
Average daily combined equivalent volumes (Mmcfe/d)		274		275		(1	)	(0.4	)%

Average prices — as reported(1):
Natural gas (per Mcf)	$	2.82	$	9.04	$	(6.22	)	(68.8	)%
Crude oil (per Bbl)(2)	$	62.76	$	112.24	$	(49.48	)	(44.1	)%
Combined equivalent (per Mcfe)	$	4.14	$	10.23	$	(6.09	)	(59.5	)%

Average prices — including impact of derivative contract settlements:
Natural gas (per Mcf)	$	6.67	$	8.09	$	(1.42	)	(17.6	)%
Crude oil (per Bbl)(2)	$	66.47	$	100.19	$	(33.72	)	(33.7	)%
Combined equivalent (per Mcfe)	$	7.43	$	9.15	$	(1.72	)	(18.8	)%


	Nine Months Ended September 30,				Change
	2009		2008		Amount			Percent
Production data:
Natural gas (Mmcf)		67,583		63,097		4,486		7.1	%
Crude oil (MBbls)		2,163		1,751		412		23.5	%
Combined equivalent volumes (Mmcfe)		80,561		73,603		6,958		9.5	%
Average daily combined equivalent volumes (Mmcfe/d)		295		269		26		9.7	%

Average prices — as reported(1):
Natural gas (per Mcf)	$	3.23	$	9.09	$	(5.86	)	(64.5	)%
Crude oil (per Bbl)(2)	$	51.02	$	104.73	$	(53.71	)	(51.3	)%
Combined equivalent (per Mcfe)	$	4.08	$	10.28	$	(6.20	)	(60.3	)%

Average prices — including impact of derivative contract settlements:
Natural gas (per Mcf)	$	7.18	$	8.10	$	(0.92	)	(11.4	)%
Crude oil (per Bbl)(2)	$	55.40	$	95.66	$	(40.26	)	(42.1	)%
Combined equivalent (per Mcfe)	$	7.51	$	9.22	$	(1.71	)	(18.5	)%

(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 — Three months ended September 30, 2009 compared to the three months ended September 30, 2008

Exploration and production segment revenues decreased 59.6% to $105.0 million in the three months ended September 30, 2009 from $259.8 million in the three months ended September 30, 2008, as a result of a 59.5% decrease in the combined average price we received for our natural gas and crude oil production. In the three-month period ended September 30, 2009, natural gas production decreased slightly to 20.9 Bcf and crude oil production increased by 202 MBbls to 723 MBbls from the comparable period in 2008. The decrease in natural gas production resulted from shut-ins for repair and maintenance activities conducted on certain of our producing properties during 2009.

The average price we received for our natural gas production for the three-month period ended September 30, 2009 decreased 68.8%, or $6.22 per Mcf, to $2.82 per Mcf from $9.04 per Mcf in the comparable period in 2008. The average price received for our crude oil production decreased 44.1%, or $49.48 per barrel, to $62.76 per barrel during the three months ended September 30, 2009 from $112.24 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 September 30, 2009 was $6.67 per Mcf compared to $8.09 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 September 30, 2009 was $66.47 per Bbl compared to $100.19 per Bbl during the same period in 2008. During 2008 and early 2009, we entered into derivative contracts to mitigate the impact of commodity price fluctuations on our production through 2012. Due to the long-term nature of our investment in the development of the West Texas Overthrust (“WTO”), we 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. 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.”

During the three-month period ended September 30, 2009, the exploration and production segment reported a $47.9 million net loss on our commodity derivative positions ($130.9 million unrealized loss and $83.0 million realized gains) compared to a $292.5 million net gain on our commodity derivative positions ($319.8 million

unrealized gain and $27.3 million realized losses) in the comparable period in 2008. Unrealized gains or losses on derivative contracts represent the change in fair value of open derivative contracts during the period. The unrealized loss on natural gas and crude oil derivative contracts recorded during the three months ended September 30, 2009 was attributable to an increase in average natural gas and crude oil prices at September 30, 2009 compared to the average natural gas and crude oil prices at June 30, 2009 or the contract price for contracts entered into during the third quarter of 2009.

For the three months ended September 30, 2009, we had a $31.1 million operating loss in our exploration and production segment compared to operating income of $418.8 million for the same period in 2008. The operating loss for the three months ended September 30, 2009 was attributable to a $154.8 million decrease in exploration and production revenues and an increase of $340.5 million in loss (gain) on derivative contracts, partially offset by a $38.9 million decrease in depreciation, depletion and amortization (“DD&A”) and a $5.6 million decrease in production taxes. See further discussion of DD&A and production taxes at “Results of Operations—Consolidated.”

Exploration and Production Segment — Nine months ended September 30, 2009 compared to the nine months ended September 30, 2008

Exploration and production segment revenues decreased 56.5% to $330.5 million in the nine months ended September 30, 2009 from $760.2 million in the nine months ended September 30, 2008, as a result of a 60.3% decrease in the combined average price we received for our natural gas and crude oil production. The decrease in prices received was slightly offset by a 9.5% increase in combined production volumes. In the nine-month period ended September 30, 2009, we increased natural gas production by 4.5 Bcf to 67.6 Bcf and increased crude oil production by 412 MBbls to 2,163 MBbls from the comparable period in 2008. The total combined 7.0 Bcfe increase in production was primarily due to the increased number of producing wells in which we owned interests during the 2009 period compared to the 2008 period.

The average price we received for our natural gas production for the nine-month period ended September 30, 2009 decreased 64.5%, or $5.86 per Mcf, to $3.23 per Mcf from $9.09 per Mcf in the comparable period in 2008. The average price received for our crude oil production decreased 51.3%, or $53.71 per barrel, to $51.02 per barrel during the nine months ended September 30, 2009 from $104.73 per barrel during the same period in 2008. Including the impact of derivative contract settlements, the effective price received for natural gas for the nine-month period ended September 30, 2009 was $7.18 per Mcf compared to $8.10 per Mcf during the same period in 2008. Including the impact of derivative contract settlements, the effective price received for crude oil for the nine-month period ended September 30, 2009 was $55.40 per Bbl compared to $95.66 per Bbl during the same period in 2008.

During the nine-month period ended September 30, 2009, the exploration and production segment reported a $139.7 million net gain on our commodity derivative positions ($136.5 million unrealized loss and $276.2 million realized gains) compared to a $4.1 million net loss on our commodity derivative positions ($73.9 million unrealized gain and $78.0 million realized losses) in the same period in 2008. The unrealized loss on natural gas and crude oil derivative contracts recorded during the nine months ended September 30, 2009 was attributable to an increase in average natural gas and crude oil prices at September 30, 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. The realized gains of $276.2 million for the nine months ended September 30, 2009 was due to a decline in natural gas prices at the time of settlement compared to the contract price.

For the nine months ended September 30, 2009, we had a $1,132.2 million operating loss in our exploration and production segment compared to operating income of $364.8 million for the same period in 2008. The operating loss for the nine months ended September 30, 2009 is attributable to a $429.7 million decrease in exploration and production revenues, a first quarter $1,304.4 million full cost ceiling impairment, and a $12.9 million increase in production expenses, partially offset by a $139.7 million net gain on our commodity

derivative contracts, which included a $136.5 million unrealized loss, a $81.7 million decrease in DD&A and a $26.3 million decrease in production taxes. 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. No additional full cost ceiling impairment was recognized at June 30, 2009 or September 30, 2009. See further discussion of production expenses, DD&A and production taxes at “Results of Operations—Consolidated.”

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 our 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, including third party working interests in wells we operate, are included in drilling and services revenues and expenses while drilling and oil field service revenues earned and expenses incurred in performing services for our own account are eliminated in consolidation.

As of September 30, 2009, we owned 31 drilling rigs, through Lariat, of which 20 were idle. As Lariat’s rigs are intended primarily to drill for our account, there is not a significant impact to our consolidated results of operations in having this number of rigs idle. The table below presents information concerning rigs owned by Lariat:


	September 30,
	2009	2008
Rigs working for SandRidge	7	26
Rigs working for third parties	1	2
Idle rigs(1)	20	—

Total operational	28	28
Non-operational rigs(2)	3	4

Total rigs owned	31	32

(1)	Includes one rig receiving stand-by rates from a third party at September 30, 2009.

(2)	Includes rigs being serviced.

Until April 15, 2009, we indirectly owned an additional eleven operational rigs through our investment in Larclay. Although our ownership in Larclay afforded us access to Larclay’s operational rigs, we did not control Larclay, and, therefore, did not consolidate the results of its operations with ours. Only the activities of our wholly owned drilling and oil field services subsidiaries are included in the financial results of our drilling and oil field services segment. On April 15, 2009, Lariat completed an assignment to CWEI of Lariat’s 50% equity interest in Larclay. Pursuant to the Larclay Assignment, Lariat assigned all of its right, title and interest in and to Larclay to CWEI effective as of April 15, 2009, and CWEI assumed all of the obligations and liabilities of Lariat relating to Larclay. We fully impaired our investment in and notes receivable due from Larclay at December 31, 2008. There were no additional losses on Larclay during the three or nine-month periods ended September 30, 2009 or as a result of the Larclay Assignment.

Drilling and Oil Field Services Segment — Three months ended September 30, 2009 compared to the three months ended September 30, 2008

Drilling and oil field services segment revenues decreased to $5.8 million in the three-month period ended September 30, 2009 from $12.0 million in the three-month period ended September 30, 2008. This resulted in an operating loss of $4.6 million in the three-month period ended September 30, 2009 compared to operating

income of $4.1 million for 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 as well as lower operating margins. Seven of our eight rigs working at September 30, 2009 were working for our account, compared to 26 of our 28 working rigs working for our account at September 30, 2008. The average daily rate received per rig working for third parties declined to an average of $11,020 per rig per working day during the three-month period ended September 30, 2009 from an average of $13,600 per rig per working day during the comparable period in 2008. We received reduced, or stand-by, rates on two of our rigs during the three-month period ended September 30, 2009, which resulted in a lower average rate per rig per working day for the three-month period ended September 30, 2009 than the comparable period in 2008.

Drilling and Oil Field Services Segment — Nine months ended September 30, 2009 compared to the nine months ended September 30, 2008

Drilling and oil field services segment revenues decreased to $17.2 million in the nine-month period ended September 30, 2009 from $36.2 million in the nine-month period ended September 30, 2008. This resulted in an operating loss of $10.2 million in the nine-month period ended September 30, 2009 compared to operating income of $6.6 million in the same period in 2008. The decline in revenues and operating income was primarily attributable to the decrease in the number of our rigs operating and services performed for third parties as well as lower operating margins. During the nine-month period ended September 30, 2009, approximately 91.1%, or $175.5 million, of our drilling and oil field services revenues were generated by work performed on our own account and eliminated in consolidation compared to approximately 88.3%, or $273.7 million, for the same period in 2008. The average daily rate received per rig working for third parties declined to an average of $10,524 per rig per working day during the nine-month period ended September 30, 2009 from an average of $14,600 per rig per working day during the comparable period in 2008. We received reduced, or stand-by, rates on two of our rigs during the nine-month period ended September 30, 2009, which resulted in a lower average rate per rig per working day for the nine-month period ended September 30, 2009 than the comparable period in 2008.

Midstream Gas Services Segment

Midstream gas services segment revenues consist mostly of gas marketing revenue, which is one of our largest revenue components; however, gas marketing is a very low-margin business. On a consolidated basis, midstream and marketing revenues represent natural gas sold on behalf of third parties and the fees we charge related to gathering, compressing and treating this gas. Gas marketing operating costs represent payments made to third parties for the proceeds from the sale of gas owned by such parties, net of any applicable margin and actual costs to gather, compress and treat the gas that we charge. The primary factors affecting midstream gas services are the quantity of natural gas we gather, treat and market and the prices we pay and receive for natural gas.

In June 2009, we completed the sale of our gathering and compression assets located in the Piñon Field of the WTO. Net proceeds from the sale were approximately $197.5 million, which resulted in a loss on the sale of $26.5 million. The sale of these assets is not expected to have a significant impact on our future consolidated results of operations. In conjunction with the sale, we entered into a gas gathering agreement and an operations and maintenance agreement. Under the gas gathering agreement, we have dedicated our Piñon Field acreage for priority gathering services for a period of twenty years and we will pay a fee for such services that was negotiated at arms’ length. Pursuant to the operations and maintenance agreement, we will operate and maintain the gathering system assets sold for a period of twenty years unless we or the buyer of the assets chooses to terminate the agreement.

Midstream Gas Services Segment — Three months ended September 30, 2009 compared to the three months ended September 30, 2008

Midstream gas services segment revenues for the three months ended September 30, 2009 were $15.9 million compared to $57.7 million in the comparable period of 2008. The quarterly decrease in midstream gas services revenues was attributable to a 66.4% decrease in natural gas prices received in the three-month period ended September 30, 2009 compared to the same period in 2008. Operating costs decreased in proportion to revenues due to the decrease in natural gas prices paid in the three-month period ended September 30, 2009 compared to the same period in 2008. Profit margin for the three-month period ended September 30, 2009 was 9.5% compared to a profit margin of 10.9% for the same period in 2008.

Midstream Gas Services Segment — Nine months ended September 30, 2009 compared to the nine months ended September 30, 2008

Midstream gas services segment revenues for the nine months ended September 30, 2009 were $60.4 million compared to $171.1 million in the comparable period of 2008. The decrease in midstream gas services revenues was attributable to a 61.7% decrease in natural gas prices received in the nine-month period ended September 30, 2009 compared to the same period in 2008. Midstream operating costs decreased in proportion to revenue based on the decrease in natural gas prices paid in the nine-month period ended September 30, 2009 compared to the same period in 2008. Profit margin for the nine-month period ended September 30, 2009 was 8.6% compared to a profit margin of 9.8% for the same period in 2008. The operating loss of $27.3 million for the nine-month period ended September 30, 2009 compared to operating income of $5.2 million for the same period in 2008 is primarily attributable to the loss on the sale of our gathering and compression assets in the Piñon Field in 2009.

Results of Operations — Consolidated

Three months ended September 30, 2009 compared to the three months ended September 30, 2008

Revenues. Total revenues decreased 59.6% to $134.9 million for the three months ended September 30, 2009 from $334.0 million in the same period in 2008. This decrease was primarily due to a $154.8 million decrease in natural gas and crude oil sales combined with decreases in midstream and marketing revenues. The table below presents a comparison of revenues for the three-month periods ended September 30, 2009 and 2008.


	Three Months Ended September 30,
	2009		2008		$ Change			% Change
	(In thousands)
Revenues:
Natural gas and crude oil	$	104,348	$	259,141	$	(154,793	)	(59.7	)%
Drilling and services		5,878		12,054		(6,176	)	(51.2	)%
Midstream and marketing		16,453		58,343		(41,890	)	(71.8	)%
Other		8,176		4,485		3,691		82.3	%

Total revenues	$	134,855	$	334,023	$	(199,168	)	(59.6	)%

Total natural gas and crude oil revenues decreased to $104.3 million for the three months ended September 30, 2009 compared to $259.1 million for the same period in 2008. The decrease was primarily attributable to a decrease in prices received for our natural gas and crude oil production. The average price received, excluding the impact of derivative contracts, for our natural gas and crude oil production decreased 59.5% in the 2009 period to $4.14 per Mcfe compared to $10.23 per Mcfe in 2008.

Drilling and services revenues decreased 51.2% to $5.9 million for the three months ended September 30, 2009 compared to $12.1 million in the same period in 2008. The decline in revenues was due to the decrease in rigs operating for and services provided to third parties combined with the decline in the average daily rate received per rig working for third parties.

Midstream and marketing revenues decreased $41.9 million, or 71.8%, with revenues of $16.4 million in the three-month period ended September 30, 2009 compared to $58.3 million in the three-month period ended September 30, 2008. The quarterly decrease in midstream gas services revenues was primarily attributable to the decrease in natural gas prices for third party volumes we marketed in the three-month period ended September 30, 2009 compared to the same period in 2008.

Other revenues, generated primarily by our CO₂gathering and sales operations, increased to $8.2 million for the three months ended September 30, 2009 from $4.5 million for the same period in 2008. The increase was due to higher CO₂ volumes sold to third parties during the three months ended September 30, 2009 compared to the same period in 2008.

Operating Costs and Expenses. Total operating costs and expenses increased to $185.1 million for the three months ended September 30, 2009 compared to $(67.3) million for the same period in 2008. The increase was primarily due to the increase of $340.5 million in loss (gain) on derivative contracts and increased drilling and services expenses, which were slightly offset by decreases in midstream and marketing, DD&A and general and administrative expenses. The table below presents a comparison of operating costs and expenses for the three-month periods ended September 30, 2009 and 2008.


	Three Months Ended September 30,
	2009		2008			$ Change			% Change
	(In thousands)
Operating costs and expenses:
Production	$	41,350	$	41,070		$	280		0.7	%
Production taxes		1,069		6,717			(5,648	)	(84.1	)%
Drilling and services		9,676		8,191			1,485		18.1	%
Midstream and marketing		14,889		51,908			(37,019	)	(71.3	)%
Depreciation, depletion and amortization — natural gas and crude oil		33,060		71,964			(38,904	)	(54.1	)%
Depreciation, depletion and amortization — other		12,092		17,597			(5,505	)	(31.3	)%
General and administrative		25,006		29,235			(4,229	)	(14.5	)%
Loss (gain) on derivative contracts		47,933		(292,526	)		340,459		(116.4	)%
Loss (gain) on sale of assets		9		(1,420	)		1,429		(100.6	)%

Total operating costs and expenses	$	185,084	$	(67,264	)	$	252,348		(375.2	)%

Production taxes decreased $5.6 million, or 84.1%, to $1.1 million. The decrease was primarily due to severance tax refunds received in 2009 and the decreased prices received for our production during the three months ended September 30, 2009.

Drilling and services expenses, which includes operating expenses attributable to the drilling and oil field services segment and our CO₂ services companies, increased 18.1% for the three months ended September 30, 2009 compared to the same period in 2008. The increase was primarily due to less rig activity and lower profit margins in 2009, which resulted in a lower amount of costs associated with the drilling business being allocated to the full cost pool and an increased amount of such costs being expensed.

Midstream and marketing expenses decreased $37.0 million, or 71.3%, to $14.9 million due to lower natural gas prices paid for natural gas that we sold on behalf of third parties during the three months ended September 30, 2009 compared to the same period in 2008.

DD&A for our natural gas and crude oil properties decreased to $33.1 million for the three months ended September 30, 2009 from $72.0 million for the same period in 2008. Our DD&A per Mcfe decreased $1.53 to

$1.31 in the third quarter of 2009 from $2.84 in the comparable period in 2008 as a result of the cumulative $3,159.4 million full cost ceiling impairment, which reduced the carrying value of our natural gas and crude oil properties. Of the cumulative impairment, $1,855.0 million was incurred at December 31, 2008 and $1,304.4 million was incurred at March 31, 2009. See Note 5 of Notes to Condensed Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding the full cost ceiling impairment.

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 a change in asset lives of certain of our drilling, oil field services, midstream and other assets to align with industry average lives for similar 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.

General and administrative expenses decreased $4.2 million to $25.0 million for the three months ended September 30, 2009 from $29.2 million for the comparable period in 2008. The decrease was attributable to higher bad debt expense for the three months ended September 30, 2008 due to the establishment of a $1.5 million allowance for amounts due from a customer filing for bankruptcy and overall decreases in spending due to economic conditions and a decrease in employees during the three months ended September 30, 2009. General and administrative expenses included non-cash stock compensation expense of $6.2 million, net of amounts capitalized, for the three months ended September 30, 2009 compared to $5.5 million for the comparable period in 2008. Salaries, wages and stock compensation were reduced by $6.0 million in capitalized general and administrative expenses, which included $1.1 million of capitalized stock compensation expense, for the three months ended September 30, 2009 compared to $6.3 million for the three months ended September 30, 2008. There was no stock compensation capitalized during 2008.

We recorded a net loss of $47.9 million ($130.9 million unrealized loss and $83.0 million realized gains) on our commodity derivative contracts for the three months ended September 30, 2009 compared to a $292.5 million net gain ($319.8 million unrealized gain and $27.3 million realized losses) for the same period in 2008. The unrealized loss recorded in the third quarter of 2009 was attributable to an increase in average natural gas prices at September 30, 2009 compared to average natural gas prices at June 30, 2009 or the contract date for contracts entered into during the third quarter of 2009.

Other Income (Expense). Total other expense increased to $53.7 million in the three-month period ended September 30, 2009 from $40.2 million in the three-month period ended September 30, 2008. The increase is reflected in the table below.


	Three Months Ended September 30,
	2009			2008			$ Change			% Change
	(In thousands)
Other income (expense):
Interest income	$	89		$	923		$	(834	)	(90.4	)%
Interest expense		(53,201	)		(41,026	)		(12,175	)	29.7	%
Income (loss) from equity investments		593			(60	)		653		(1,088.3	)%
Other expense, net		(1,144	)		(83	)		(1,061	)	1,278.3	%

Total other (expense) income		(53,663	)		(40,246	)		(13,417	)	33.3	%

(Loss) income before income tax (benefit) expense		(103,892	)		361,041			(464,933	)	(128.8	)%
Income tax (benefit) expense		(2,580	)		130,693			(133,273	)	(102.0	)%

Net (loss) income	$	(101,312	)	$	230,348		$	(331,660	)	(144.0	)%

Interest expense increased to $53.2 million for the three months ended September 30, 2009 from $41.0 million for the same period in 2008. This increase was primarily attributable to the higher average debt

balances outstanding during the three months ended September 30, 2009. A $4.5 million unrealized loss on our interest rate swap further increased interest expense for the three months ended September 30, 2009 compared to a $2.7 million unrealized loss for the three months ended September 30, 2008.

We reported an income tax benefit of $2.6 million for the three months ended September 30, 2009, compared to an expense of $130.7 million for the same period in 2008. The current period income tax benefit represents an effective income tax rate of 2.5% compared to an effective income tax rate of 36.2% in the same period in 2008. 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 the full valuation allowance on our net deferred tax asset.

Nine months ended September 30, 2009 compared to the nine months ended September 30, 2008

Revenues. Total revenues decreased 56.4% to $428.0 million for the nine months ended September 30, 2009 from $981.2 million for the same period in 2008. This decrease was primarily due to a $428.1 million decrease in natural gas and crude oil sales and a $112.2 million decrease in midstream and marketing revenues. The table below presents a comparison of revenues for the nine-month periods ended September 30, 2009 and 2008.


	Nine Months Ended September 30,				$ Change			% Change
	2009		2008		$ Change			% Change
	(In thousands)
Revenues:
Natural gas and crude oil	$	328,628	$	756,762	$	(428,134	)	(56.6	)%
Drilling and services		17,449		36,345		(18,896	)	(52.0	)%
Midstream and marketing		62,051		174,240		(112,189	)	(64.4	)%
Other		19,839		13,812		6,027		43.6	%

Total revenues	$	427,967	$	981,159	$	(553,192	)	(56.4	)%

Natural gas and crude oil revenues decreased to $328.6 million for the nine months ended September 30, 2009 compared to $756.8 million for the same period in 2008. The decrease was primarily attributable to a decrease in prices received for our natural gas and crude oil production, which was 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 60.3% in the 2009 period to $4.08 per Mcfe compared to $10.28 per Mcfe in 2008. Total natural gas production increased 7.1% to 67.6 Bcf in 2009 compared to 63.1 Bcf in 2008, while crude oil production increased 23.5% to 2,163 MBbls in 2009 from 1,751 MBbls in 2008.

Drilling and services revenues decreased 52.0% to $17.4 million for the nine months ended September 30, 2009 compared to $36.3 million for the same period in 2008. The decline in revenues was due to the decrease in rigs operating for and services provided to third parties and the decline in the average daily rate received per rig working for third parties.

Midstream and marketing revenues decreased $112.2 million, or 64.4%, with revenues of $62.0 million in the nine-month period ended September 30, 2009 compared to $174.2 million in the nine-month period ended September 30, 2008. The decrease was attributable to the decrease in prices for natural gas that we sold on behalf of third parties in the nine-month period ended September 30, 2009 compared to the same period in 2008.

Other revenues increased to $19.8 million for the nine months ended September 30, 2009 from $13.8 million for the same period in 2008. The increase was primarily due to higher CO₂volumes sold to third parties during the nine months ended September 30, 2009 compared to the same period in 2008.

Operating Costs and Expenses. Total operating costs and expenses increased to $1,644.5 million for the nine months ended September 30, 2009 compared to $654.5 million for the same period in 2008. The increase was primarily due to a first quarter 2009 full cost ceiling impairment of $1,304.4 million, an increase in production expenses and a loss on the sale of our gathering and compression assets in the Piñon Field. These increases were partially offset by net gains on our derivative contracts and decreases in production taxes, midstream and marketing expenses and DD&A. The table below presents a comparison of operating costs and expenses for the nine-month periods ended September 30, 2009 and 2008.


	Nine Months Ended September 30,						$ Change			% Change
	2009			2008			$ Change			% Change
	(In thousands)
Operating costs and expenses:
Production	$	128,379		$	115,512		$	12,867		11.1	%
Production taxes		3,153			29,456			(26,303	)	(89.3	)%
Drilling and services		21,697			20,426			1,271		6.2	%
Midstream and marketing		56,702			157,059			(100,357	)	(63.9	)%
Depreciation, depletion and amortization — natural gas and crude oil		127,503			209,296			(81,793	)	(39.1	)%
Depreciation, depletion and amortization — other		38,851			51,342			(12,491	)	(24.3	)%
Impairment		1,304,418			—			1,304,418		100.00	%
General and administrative		77,123			76,432			691		0.9	%
(Gain) loss on derivative contracts		(139,722	)		4,086			(143,808	)	(3,519.5	)%
Loss (gain) on sale of assets		26,359			(9,131	)		35,490		(388.7	)%

Total operating costs and expenses	$	1,644,463		$	654,478		$	989,985		151.3	%

Production expenses increased $12.9 million primarily due to an increase in the number of wells in which we own an interest and increased production volumes. In the nine-month period ended September 30, 2009, we increased natural gas production by 4.5 Bcf to 67.6 Bcf and increased crude oil production by 412 MBbls to 2,163 MBbls from the comparable period in 2008. Production taxes decreased $26.3 million, or 89.3%, to $3.2 million. The decrease was primarily due to severance tax refunds received in 2009 and the decreased prices received for production during the nine months ended September 30, 2009.

Midstream and marketing expenses decreased $100.4 million, or 63.9%, to $56.7 million due to lower prices paid for natural gas that we sold on behalf of third parties during the nine months ended September 30, 2009 than during the comparable period in 2008.

DD&A for our natural gas and crude oil properties decreased to $127.5 million for the nine months ended September 30, 2009 from $209.3 million during the same period in 2008. Our average DD&A per Mcfe decreased $1.26 to $1.58 in the first nine months of 2009 from $2.84 for the comparable period in 2008 as a result of the $3,159.4 million cumulative full cost ceiling impairment, which reduced the carrying value of our natural gas and crude oil properties. The effect of the decrease in DD&A per Mcfe was slightly offset by the 9.5% increase in production during the first nine months of 2009 compared to the same period 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 of certain of our drilling, oil field services, midstream and other assets to align with industry average lives for similar assets.

General and administrative expenses increased slightly to $77.1 million for the nine months ended September 30, 2009 from $76.4 million for the comparable period in 2008. General and administrative expenses included non-cash stock compensation expense, net of amounts capitalized, of $16.5 million for the nine months

ended September 30, 2009 compared to $12.8 million for the comparable period in 2008. The increases in salaries and wages and stock compensation were partially offset by $18.9 million in capitalized general and administrative expenses, which included $3.2 million of capitalized stock compensation expense, for the nine months ended September 30, 2009 compared to $13.9 million for the nine months ended September 30, 2008. There was no stock compensation capitalized in 2008.

We recorded a net gain of $139.7 million ($136.5 million unrealized loss and $276.2 million realized gains) on our commodity derivatives contracts for the nine months ended September 30, 2009 compared to a $4.1 million net loss ($73.9 million unrealized gain and $78.0 million realized losses) for the same period in 2008. The unrealized loss recorded in 2009 was attributable to an increase in average natural gas prices at September 30, 2009 compared to average natural gas prices at December 31, 2008 or the contract date for contracts entered into during 2009. The realized gains of $276.2 million for the nine months ended September 30, 2009 were primarily due to a decline in natural gas prices at the time of settlement compared to the contract price.

The loss on sale of assets for the nine months ended September 30, 2009 was primarily due to the $26.5 million loss on the sale of our gathering and compression assets in the Piñon Field. For the nine months ended September 30, 2008, the gain on sale of assets of $9.1 million was attributable to the approximately $7.5 million gain on the sale of our assets located in the Piceance Basin of Colorado.

Other Income (Expense). Total other expense increased to $135.0 million in the nine-month period ended September 30, 2009 from $83.1 million in the nine-month period ended September 30, 2008. The increase is reflected in the table below.


	Nine Months Ended September 30,
	2009			2008			$ Change			% Change
	(In thousands)
Other income (expense):
Interest income	$	287		$	3,068		$	(2,781	)	(90.6	)%
Interest expense		(136,368	)		(88,421	)		(47,947	)	54.2	%
Income from equity investments		1,027			1,355			(328	)	(24.2	)%
Other income, net		100			856			(756	)	(88.3	)%

Total other (expense) income		(134,954	)		(83,142	)		(51,812	)	62.3	%

(Loss) income before income tax (benefit) expense		(1,351,450	)		243,539			(1,594,989	)	(654.9	)%
Income tax (benefit) expense		(4,114	)		89,308			(93,422	)	(104.6	)%

Net (loss) income	$	(1,347,336	)	$	154,231		$	(1,501,567	)	(973.6	)%

Interest income decreased to $0.3 million for the nine months ended September 30, 2009 from $3.1 million for the same period in 2008. The decrease was generally due to lower excess cash levels during the nine months ended September 30, 2009 compared to the same period in 2008.

Interest expense increased to $136.4 million for the nine months ended September 30, 2009 from $88.4 million for the same period in 2008. This increase was attributable to higher average debt balances outstanding during the nine months ended September 30, 2009. For the nine months ended September 30, 2009, an unrealized loss of $0.9 million related to our interest rate swap resulted in higher interest expense during this period. Also contributing to the increase was a $7.7 million unrealized gain related to our interest rate swap which reduced interest expense for the nine months ended September 30, 2008.

We reported an income tax benefit of $4.1 million for the nine months ended September 30, 2009, compared to an expense of $89.3 million for the same period in 2008. The current period income tax benefit represents an

effective income tax rate of 0.3% compared to an effective income tax rate of 36.8% for the same period in 2008. 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

We historically have funded our capital requirements through a combination of cash flow generated from operations, borrowings under our senior credit facility, the issuance of equity and debt securities and, to a lesser extent, the sale of assets. During the first nine months of 2009, our primary sources of cash were cash flow generated from operations, borrowings under our senior credit facility, proceeds from the issuance of convertible perpetual preferred stock and common stock, proceeds from the issuance of our 9.875% Senior Notes, proceeds from the sale of gathering and compression assets related to our midstream operations in the Piñon Field and proceeds from the sale of our drilling rights in East Texas below the depth of the Cotton Valley formation. Our primary uses of cash during the first nine months of 2009 were capital expenditures related to the development of our natural gas and crude oil properties and other fixed assets and the repayment of amounts outstanding on our senior credit facility and interest payments on our outstanding debt.

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

Our cash flows for the nine-month periods ended September 30, 2009 and 2008 are presented in the following table and discussed below:


	Nine Months Ended September 30,
	2009			2008
	(In thousands)
Cash flows provided by operating activities	$	273,220		$	534,368
Cash flows used in investing activities		(364,523	)		(1,457,102	)
Cash flows provided by financing activities		105,309			860,497

Net increase (decrease) in cash and cash equivalents	$	14,006		$	(62,237	)

Cash Flows from Operating Activities

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

Net cash provided by operating activities for the nine-month periods ended September 30, 2009 and 2008 was $273.2 million and $534.4 million, respectively. The decrease in cash provided by operating activities in 2009 compared to 2008 was primarily due to a 60.3% decrease in the combined average prices we received for our natural gas and crude oil production for the nine months ended September 30, 2009. Decreases in midstream and marketing revenues also contributed to the decrease in operating cash flows.

Cash Flows from Investing Activities

We dedicate and expect to continue to dedicate a substantial portion of our capital expenditure program toward the exploration, development, production and acquisition of natural gas and crude oil reserves. These capital expenditures are necessary to offset inherent declines in production and proven reserves, which is typical in the capital-intensive natural gas and crude oil industry. Net cash used in investing activities, which included capital expenditures for property, plant and equipment, for the nine months ended September 30, 2009 and 2008 was $364.5 million and $1,457.1 million, respectively.

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


	Nine Months Ended September 30,
	2009		2008
	(In thousands)
Capital Expenditures:
Exploration and production	$	470,519	$	1,404,067
Drilling and oil field services		2,770		61,540
Midstream gas services		43,788		110,125
Other		25,124		33,623

Total	$	542,201	$	1,609,355

Capital expenditures decreased $1,067.2 million to $542.2 million for the nine months ended September 30, 2009 compared to $1,609.4 million for the same period in 2008 primarily due to our decreased drilling activities. Cash outflows from capital expenditures in the first nine months of 2009 were partially offset by approximately $254.0 million in combined proceeds from the sale of our gathering and compression assets located in the Piñon Field and our deep drilling rights in East Texas. Cash outflows from capital expenditures in the first nine months of 2008 were partially offset by approximately $147.2 million in proceeds from the sale of our assets located in the Piceance Basin of Colorado.

Cash Flows from Financing Activities

Our financing activities provided $105.3 million in cash for the nine-month period ended September 30, 2009 compared to $860.5 million for the same period in 2008. Proceeds from borrowings, including the senior notes described below, were $1,638.4 million for the nine months ended September 30, 2009 compared to $1,768.7 million for the same period in 2008. Repayments of approximately $1,874.0 million resulted in net repayments during the nine-month period ended September 30, 2009 of approximately $235.6 million. Repayments of $864.1 million during the first nine months of 2008 resulted in net borrowings during the period of $904.6 million. Additionally, the issuance of our 8.5% convertible perpetual preferred stock and 14,480,000 shares of common stock provided net proceeds of $243.3 million and $107.6 million, respectively, during the nine months ended September 30, 2009.

Long-Term Debt Issuances and Repayments

Senior Credit Facility. As a result of net repayments of $573.5 million during the first nine months of 2009, we had no outstanding indebtedness under our senior credit facility as of September 30, 2009. The amount we may borrow under the facility is limited to a borrowing base amount, which is currently $985.4 million, and is subject to periodic redeterminations. The borrowing base is available to be drawn on subject to limitations based on its terms and certain financial covenants. The borrowing base is determined based upon proved developed producing reserves, proved developed non-producing reserves and proved undeveloped reserves. Our ability to develop properties as well as changes in commodity prices may affect the borrowing base of our senior credit

facility. Based on the October 2009 redetermination, our borrowing base remained unchanged from the previous determination of $985.4 million. The average annual interest rate paid on amounts outstanding under our senior credit facility was 2.30% for the nine months ended September 30, 2009. Our senior credit facility matures on November 21, 2011.

9.875% Senior Notes Due 2016. In May 2009, we completed a private placement of $365.5 million of unsecured 9.875% Senior Notes to qualified institutional investors eligible under Rule 144A of the Securities Act. These notes were issued at a discount which will be amortized into interest expense over the term of the notes. Net proceeds from the offering were approximately $342.1 million after deducting the discount and offering expenses of $7.9 million. We used the net proceeds from the offering to repay outstanding borrowings under our senior credit facility and for general corporate purposes. The notes bear interest at a fixed rate of 9.875% per annum, payable semi-annually, with the principal due on May 15, 2016. We may redeem the notes, in whole or in part, prior to their maturity at specified redemption prices. The notes are jointly and severally, unconditionally guaranteed on an unsecured basis by all of the Company’s wholly owned subsidiaries, except certain minor subsidiaries, and will become freely tradable six months after their issuance pursuant to Rule 144 under the Securities Act.

8.0% Senior Notes Due 2018. In May 2008, we received approximately $735.0 million net proceeds from the issuance of $750.0 million of 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 are freely tradable.

Preferred and Common Stock Issuances

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 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 per share 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 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 $107.6 million after deducting offering expenses of approximately $2.4 million and were used to repay a portion of the amount outstanding under our senior credit facility and for general corporate purposes.

Outlook

We have budgeted a range of $500.0 million to $700.0 million for capital expenditures, excluding acquisitions, for the year ending December 31, 2009. For 2010, we are budgeting approximately $750.0 million for capital expenditures. The majority of our planned capital expenditures is 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. Additionally, we have entered into interest rate swaps as well as fixed-price swaps and basis swaps for a portion of our production through 2012 in order to stabilize future cash flows for planning purposes. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding our derivative contracts.

As of September 30, 2009, our cash and cash equivalents were $14.6 million and we had approximately $2.1 billion in total debt outstanding with no amounts outstanding under our senior credit facility. As of September 30, 2009, we were in compliance with all of the covenants under all of our senior notes and our senior credit facility. See Note 8 of Notes to Condensed Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our long-term debt. As of November 5, 2009, our cash and cash equivalents were approximately $27.0 million, the balance outstanding under our senior credit facility was $29.9 million and we had $46.7 million in outstanding letters of credit.

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

Debt and equity capital markets experienced adverse conditions during the latter part of 2008 and into 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 to our ability to access the full amounts available under our senior credit facility was the bankruptcy of Lehman Brothers, a lender responsible for 0.29% of the obligations under our senior credit facility. The largest commitment from any lender under the senior credit facility is 6.3% of the total amount available under the facility. We cannot predict with any certainty the impact to us of any further disruptions in the credit or capital markets.

Contractual Obligations

Gas Gathering Agreement. In conjunction with the sale of our gathering and compression assets located in the Piñon Field of the WTO, we entered into a gas gathering agreement. Under the gas gathering agreement, we have dedicated our Piñon Field acreage for priority gathering services over a period of twenty years and we will pay a fee that was negotiated at arms’ length for such services. Pursuant to the gas gathering agreement, the base fee can be reduced if certain criteria are met. The table below presents our contractual obligations under this agreement as of September 30, 2009.


	Payments Due
	(In thousands)
2009	$	3,929
2010		22,226
2011		33,780
2012		42,814
2013		42,634
After 2013		327,749

	$	473,132

Long Term Debt. We issued our 9.875% Senior Notes in May 2009. This debt issuance along with the pay down of the outstanding balance on our senior credit facility are discussed further under “Long-Term Debt Issuances and Repayments” above.

ITEM 3.

Quantitative and Qualitative Disclosures About Market Risk

General

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

Commodity Price Risk. Our most significant market risk relates to the prices we receive for our 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 September 30, 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. We have no derivative contracts in 2009 and beyond with counterparties other than those that are lenders under our senior credit facility. Lehman Brothers was a counterparty to one of our derivative contracts. Due to the bankruptcy of Lehman Brothers and its parent, Lehman Brothers Holdings Inc. and the asset position of the contract, we did not assign any value to this derivative contract from September 30, 2008 until September 30, 2009. During August 2009, the Company entered into an agreement with Lehman Brothers to settle all unsettled positions under this derivative contract through September 30, 2009. As of October 1, 2009, Lehman Brothers assigned this contract to a third party to serve as the counterparty for the remainder of the contract. Accordingly, both the realized portion and the future value of this contract were included in the condensed consolidated financial statements at September 30, 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.

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.

At September 30, 2009, our open natural gas and crude oil commodity derivative contracts consisted of the following:

Natural Gas


Period and Type of Contract	Notional (MMcf)(1)	Weighted Avg. Fixed Price
October 2009 — December 2009
Price swap contracts	19,010	$	8.46
Basis swap contracts	17,480	$	(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	$	7.32
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	25,650	$	(0.47	)
April 2011 — June 2011
Basis swap contracts	25,935	$	(0.47	)
July 2011 — September 2011
Basis swap contracts	26,220	$	(0.47	)
October 2011 — December 2011
Basis swap contracts	26,220	$	(0.47	)
January 2012 — March 2012
Basis swap contracts	28,210	$	(0.55	)
April 2012 — June 2012
Basis swap contracts	28,210	$	(0.55	)
July 2012 — September 2012
Basis swap contracts	28,520	$	(0.55	)
October 2012 — December 2012
Basis swap contracts	28,520	$	(0.55	)

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

Crude Oil


Period and Type of Contract	Notional (in MBbls)	Weighted Avg. Fixed Price
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 nine months ended September 30, 2009 and 2008 (in thousands):


	Nine Months Ended September 30,
	2009			2008
Realized (gain) loss	$	(276,175	)	$	77,954
Unrealized loss (gain)		136,453			(73,868	)

(Gain) loss on commodity derivative contracts	$	(139,722	)	$	4,086

Credit Risk. 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 6.3%. 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 amount available 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.

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 the interest rate on our variable rate term loan for the period from April 1, 2008 through April 1, 2011. As a result of the exchange of our variable rate term loan to Senior Floating Rate Notes, the interest rate swap is now used to fix the variable LIBOR interest rate on the Senior Floating Rate Notes at 6.26% through April 2011. In May 2009, we entered into a $350.0 million notional amount interest rate swap agreement with a financial institution that effectively fixed the interest rate on our Senior Floating Rate Notes at 6.69% for the period from April 1, 2011 through April 1, 2013. These swaps have not been designated as hedges.

Our interest rate swaps reduce our market risk on our Senior Floating Rate Notes. We use sensitivity analyses to determine the impact that market risk exposures could have on our variable interest rate borrowings if not for our interest rate swaps. Based on the $350.0 million outstanding balance of our Senior Floating Rate Notes at September 30, 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 and $2.6 million for the three months and nine months ended September 30, 2009, respectively.

Unrealized losses of $4.5 million and $2.7 million were recorded in interest expense in the consolidated statements of operations for the change in fair value of the interest rate swaps for the three months ended September 30, 2009 and 2008, respectively. An unrealized loss of $0.9 million and an unrealized gain of $7.7 million were recorded in interest expense in the consolidated statements of operations for the change in fair value of the interest rate swaps for the nine months ended September 30, 2009 and 2008, respectively. Realized losses of $1.8 million and $4.1 million were included in interest expense in the condensed consolidated statements of operations for the three and nine months ended September 30, 2009, respectively. There were no realized gains or losses recorded on our interest rate swaps during the first nine months of 2008.

ITEM 4.

Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we performed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15 as of the end of the period covered by this Quarterly Report. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 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 September 30, 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 party to various legal actions from time to time in the normal course of business. While the final outcome of such actions cannot be predicted with certainty, it is management’s opinion that the Company is not currently involved in any legal proceedings that, individually or in the aggregate, could have a material adverse effect on its financial position, results of operations, or cash flow.

ITEM 1A.

Risk Factors

We describe certain of our business risk factors below. This description includes material changes to the description of the risk factors previously disclosed in Part I, Item 1A of the 2008 Form 10-K.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

President Obama’s Proposed Fiscal Year 2010 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could negatively affect our financial condition and results of operations.

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. The “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or ACESA, which was approved for adoption by the U.S. House of Representatives on June 26, 2009, contains provisions that would prohibit private over-the-counter energy commodity derivative and hedging transactions. ACESA would expand the power of the Commodity Futures Trading Commission, or CFTC, to regulate derivative transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The CFTC has conducted hearings to consider whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. In addition, legislation has been introduced in Congress that would subject OTC derivative dealers and major OTC derivative market participants to substantial supervision and regulation, including by imposing conservative capital and margin requirements and strong business conduct standards. Derivative contracts that are not cleared through central clearinghouses and exchanges may be subject to substantially higher capital and margin requirements. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of bills currently pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, these bills, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

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 September 30, 2009, the following shares were withheld in satisfaction of tax withholding obligations arising from the vesting of restricted stock:


Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
July 1, 2009 — July 31, 2009	64,344	$	8.78	N/A	N/A
August 1, 2009 — August 31, 2009	312	$	12.20	N/A	N/A
September 1, 2009 — September 30, 2009	319	$	12.96	N/A	N/A

ITEM 6.

Exhibits

See the Exhibit Index accompanying this Quarterly Report.

SIGNATURE

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


SandRidge Energy, Inc.

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

Date: November 5, 2009

EXHIBIT INDEX

Incorporated by Reference

Exhibit

No.

Exhibit Description

Form

SEC

File No.

Exhibit

Filing Date

Filed

Herewith

2.1

Stock Purchase Agreement, dated September 22, 2009, among SandRidge Energy, Inc., SandRidge Exploration, LLC, Crusader Energy Group Inc., Crusader Energy Group, LLC, Hawk Energy Fund I, LLC, Knight Energy Group, LLC, Knight Energy Group II, LLC, Knight Energy Management, LLC and RCH Upland Acquisition, LLC

3.1

Certificate of Incorporation of SandRidge Energy, Inc.

S-1

333-148956

3.1

01/30/2008

3.2

Amended and Restated Bylaws of SandRidge Energy, Inc.

8-K

001-33784

3.1

03/09/2009

31.1

Section 302 Certification — Chief Executive Officer

31.2

Section 302 Certification — Chief Financial Officer

32.1

Section 906 Certifications of Chief Executive Officer and Chief Financial Officer

101.INS

XBRL Instance Document

101.SCH

XBRL Taxonomy Extension Schema Document

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF

XBRL Taxonomy Extension Definition Document

101.LAB

XBRL Taxonomy Extension Label Linkbase Document

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company